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Item 7. Management’s Discussion and Analysis

2024-02-29 compared with 2023-03-01 · 117 added, 154 removed, 527 unchanged (34% of the section changed)

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GP LLC is a Delaware limited liability company that holds the non-economic general partner interest in AAP.

AAP is a Delaware limited partnership that, as of December 31, 2022, directly owned a limited partner interest in PAA through its ownership of approximately 241.0 million PAA common units (approximately 31% PAA’s total outstanding common units and Series A preferred units combined).

AAP is a Delaware limited partnership that, as of December 31, 2023, directly owned a limited partner interest in PAA through its ownership of approximately 232.7 million PAA common units (approximately 30% of PAA’s total outstanding common units and Series A preferred units combined).

AAP is the sole member of PAA GP, a Delaware limited liability company that directly holds the non-economic general partner interest in PAA.

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Market Overview and Outlook

Crude oil and other petroleum liquids are supplied to the global market by producers around the world, with the majority coming from the Organization of Petroleum Exporting Countries (“OPEC”), the Russian Federation and North American producers, among others.

Crude oil and other petroleum liquids are supplied to the global market by producers around the world, with the majority coming from the Organization of Petroleum Exporting Countries (“OPEC”), North American producers and the Russian Federation, among others.

The chart below depicts the relationship between global supply of crude oil and other petroleum liquids and demand since the beginning of 2019 and the U.S.

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(1) Barrels produced and consumed per quarter.

Global crude oil demand at the end of 2022 was near pre-COVID levels, with the EIA and other third parties forecasting demand to exceed 2019 levels by the second half of 2023 and continue to grow for the foreseeable future.

We believe this demand growth combined with the multi-year backdrop of reduced upstream investment and a continuation of OPEC discipline and Western sanctions on Russian petroleum could further exacerbate many of the supply concerns that emerged in 2022.

This includes tight global markets and continued commodity price volatility.

As a result, we expect North American energy supply to play a critical long-term role in meeting global demand and the Permian Basin to drive the vast majority of U.S.

production growth in the coming years.

It is against this macro backdrop that we expect to generate significant positive free cash flow on a multi-year basis, supported by our existing asset base and integrated business model.

We believe that the combination of population growth and progressively improving living standards for non-OECD (Organization for Economic Cooperation and Development) countries underpins increasing energy demand globally for decades to come.

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.

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.

North America has proven to be an essential and reliable source of crude oil and NGL production growth for the global market.

This is driven by the lifting of the U.S.

crude oil export ban, infrastructure debottlenecking in both the U.S.

and Canada, and world-class geological formations unlocked through technological improvements and techniques.

The Permian Basin continues to be one of the most prolific basins in the world and was the predominant driver of U.S.

production growth in 2023.

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.

It is against this macro energy market backdrop that we expect to generate significant positive free cash flow on a multi-year basis, supported by our existing asset base and integrated business model.

Our financial strategy and long-term capital allocation framework is focused on generating meaningful multi-year free cash flow and improving shareholder returns by (i) increasing returns of capital to equity holders, primarily through increased distributions, (ii) making disciplined accretive investments and (iii) maintaining an investment grade credit profile and ensuring balance sheet flexibility.

Overview of Operating Results

During 2022, we continued to build momentum and reinforce our long-term positioning by taking actions to further optimize our asset base and streamline our operations.

We recognized net income of $1.163 billion for the year ended December 31, 2022 compared to net income of $600 million for the year ended December 31, 2021.

Results from our operations increased for 2022 over the comparable 2021 period driven primarily by more favorable margins in our NGL segment, as well as increased earnings from our crude oil pipelines due to higher tariff volumes and higher loss allowance revenue attributable to higher volumes and commodity prices.

However, these items were partially offset by the impact of the monetization of contango hedges that benefited the 2021 period, the sale of our natural gas storage facilities in the third quarter of 2021 and higher field operating costs in the 2022 period primarily from (i) an increase in estimated costs associated with the Line 901 incident and (ii) gains related to hedged power costs resulting from the extreme winter weather event that occurred in February 2021 (“Winter Storm Uri”) recognized in the first quarter of 2021.

Index to Financial Statements

Additionally, results for 2022 included a net loss on asset sales and asset impairments of $269 million, primarily related to the impairment of certain of our California crude oil assets, compared to a net loss on asset sales and asset impairments of $592 million included in results for 2021, a majority of which was related to the write-down of our natural gas storage facilities, which were classified as held for sale in the second quarter and sold in the third quarter.

The 2022 period also includes net gains of approximately $346 million, primarily 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.

Overview of Operating Results

We recognized net income of $1.425 billion for the year ended December 31, 2023 compared to net income of $1.163 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.

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

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2022 $ 71 $ 124 $ 94

Product sales revenues and purchases increased for the year ended December 31, 2022 compared to the year ended December 31, 2021 primarily due to higher prices in 2022.

Revenues from services increased for the year ended December 31, 2022 compared to the year ended December 31, 2021 primarily due to higher prices and volumes in 2022 (a portion of which was related to contributions from recently completed acquisitions and joint venture transactions), partially offset by the impact of the sale of our natural gas storage facilities in the third quarter of 2021.

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.

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.

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, 2022 compared to the year ended December 31, 2021 was primarily due to (i) employee-related costs, including an increase in equity-indexed compensation expense due to changes in plan assumptions and a higher PAA common unit price (a portion of which is excluded in the calculation of Adjusted EBITDA and Segment Adjusted EBITDA), (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, partially offset by (iv) costs associated with the formation of the Permian JV in the prior year.

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 PAA 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, 2022 compared to the year ended December 31, 2021 largely driven by depreciation and amortization expense on assets (i) contributed by Oryx Midstream Holdings LLC (“Oryx Midstream”) upon formation of the Permian JV and (ii) consolidated in connection with our acquisition of an additional interest in Cactus II.

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 losses on asset sales and asset impairments for 2022 primarily included (i) a $330 million non-cash impairment charge recognized in the fourth quarter of 2022 related to certain crude oil assets in California and (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.

See Note 6 and Note 7 to our Consolidated Financial Statements for additional information.

The net losses on asset sales and asset impairments for 2021 primarily included (i) an approximate $220 million non-cash impairment charge recognized in the third quarter related to the write-down of certain crude oil storage terminal assets as a result of decreased demand for our services due to changing market conditions, (ii) an approximate $475 million non-cash impairment charge related to the write-down of our Pine Prairie and Southern Pines natural gas storage facilities upon classification as held for sale (these assets were sold in August 2021), and (iii) a gain of $106 million related to the asset exchange agreement (the “Asset Exchange”) involving the sale of one of our crude oil pipelines in Canada in exchange for additional interests in certain of the Empress natural gas processing plants.

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.

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

Index to Financial Statements

Equity Earnings in Unconsolidated Entities

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

Index to Financial Statements

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.

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Interest Expense, Net

Interest expense is primarily impacted by:

• our weighted average debt balances;

• the level and maturity of fixed rate debt and interest rates associated therewith;

• market interest rates and our interest rate hedging activities;

• interest capitalized on capital projects.

The following table summarizes the components impacting the interest expense variance (in millions, except percentages):

LIBOR/SOFR Weighted Average

Interest Rate (1)

Interest expense for the year ended December 31, 2021

$ 425 0.1 % 4.2 %

Impact of retirement of senior notes (22)

Impact of lower capitalized interest 13

Impact of interest rate swap (7)

Interest expense for the year ended December 31, 2022

$ 405 1.9 % 4.3 %

(1) Excludes commitment and other fees.

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.

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

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

$ 102 $ (219)

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

Index to Financial Statements

(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.

Income Tax (Expense)/Benefit

The net unfavorable income tax variance for the year ended December 31, 2022 compared to the year ended December 31, 2021 was primarily a result of higher year-over-year income as impacted by fluctuations of the derivative mark-to-market valuations in our Canadian operations.

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 and the impact of higher earnings at PAA on income attributable to PAGP.

See Note 7 to our Consolidated Financial Statements for additional information regarding the Keyera Fort Saskatchewan divestiture.

Index to Financial Statements

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.

The primary additional measures used by management are Adjusted EBITDA and Adjusted EBITDA attributable to PAA, which excludes the portion of Adjusted EBITDA attributable to noncontrolling interests in consolidated joint venture entities.

Adjusted EBITDA is defined as earnings before interest, 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, goodwill impairment losses and gains or losses on and impairments of investments in unconsolidated entities, adjusted for certain selected items impacting comparability.

The primary additional measures used by management are Adjusted EBITDA and Adjusted EBITDA attributable to PAA.

Our definition and calculation of certain non-GAAP financial measures may not be comparable to similarly-titled measures of other companies.

Adjusted EBITDA and Adjusted EBITDA attributable to PAA are reconciled to Net Income/(Loss), 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.

Adjusted EBITDA and Adjusted EBITDA attributable to PAA are reconciled to Net Income, 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.

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.

Adjusted EBITDA attributable to PAA excludes the portion of Adjusted EBITDA that is attributable to noncontrolling interests in consolidated joint venture entities.

Management believes that the presentation of such additional financial measures 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, (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 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 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 Consolidated Financial Statements.

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Depreciation and amortization of unconsolidated entities (1)

85 123 (38) (31) %

Unallocated general and administrative expenses (2)

5 6 (1) (17) %

Selected Items Impacting Comparability:

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Line 901 incident 10 95 (85) **

Significant transaction-related expenses — 16 (16) **

Transaction-related expenses

Selected Items Impacting Comparability - Segment Adjusted EBITDA (3)

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Foreign currency revaluation (5)

(16) 37 (53) **

Selected Items Impacting Comparability - Adjusted EBITDA (6)

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(3) For a more detailed discussion of these selected items impacting comparability, see the footnotes to the Segment Adjusted EBITDA Reconciliation table in Note 19 to our Consolidated Financial Statements.

(4) The Preferred Distribution Rate Reset Option of PAA’s Series A preferred units is accounted for as an embedded derivative and recorded at fair value in our Consolidated Financial Statements.

(4) The Preferred Distribution Rate Reset Option of PAA’s Series A preferred units was accounted for as an embedded derivative and recorded at fair value in our Consolidated Financial Statements.

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

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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 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 in consolidated joint venture entities (“Adjusted EBITDA attributable to noncontrolling interests in consolidated joint ventures”).

See Note 20 to our Consolidated Financial Statements for a reconciliation of Segment Adjusted EBITDA to Net income/(loss) attributable to PAGP.

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 in consolidated joint venture entities (“Segment amounts attributable to noncontrolling interests in consolidated joint ventures”).

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

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 facilities-related services utilizing our integrated assets across the United States and Canada.

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 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 hedge our exposure.

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 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) the overall strength, weakness and volatility of market conditions, including regional differentials and time spreads.

In addition, the execution of our risk management strategies in conjunction with our assets can provide upside in certain markets.

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.

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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Line 901 incident 10 95 (85) **

Significant transaction-related expenses — 16 (16) **

Adjusted EBITDA attributable to noncontrolling interests in consolidated joint ventures (364) (94) (270) **

Transaction-related expenses 1 — 1 **

Segment amounts attributable to noncontrolling interests in consolidated joint ventures

(454) (364) (90) **

Segment Adjusted EBITDA $ 2,163 $ 1,986 $ 177 9 %

Maintenance capital $ 112 $ 100 $ 12 12 %

Maintenance capital expenditures $ 145 $ 112 $ 33 29 %

Average Volumes Year Ended December 31, Variance

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Commercial crude oil storage capacity (5) (6)

72 73 (1) (1) %

Crude oil lease gathering purchases (4) (7)

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Segment Adjusted EBITDA

Crude Oil Segment Adjusted EBITDA was favorably impacted for the year ended December 31, 2022 compared to the year ended December 31, 2021 by higher volumes on our pipelines, favorable Canadian crude oil differentials and higher loss allowance revenue.

These favorable impacts were partially offset by (i) the monetization of contango hedges that benefited the 2021 period, (ii) the sale of our natural gas storage facilities in August 2021 (which were reported in our Crude Oil Segment) and (iii) gains related to hedged power costs resulting from Winter Storm Uri recognized in the first quarter of 2021.

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.

The following is a more detailed discussion of the significant factors impacting Segment Adjusted EBITDA for the year ended December 31, 2023 compared to the year ended December 31, 2022.

• Permian JV.

In October 2021, we closed on the transaction with Oryx Midstream to merge our respective Permian Basin assets, with the exception of our long-haul pipeline systems and certain of our intra-basin assets, into the Permian JV.

The significant year-over-year growth in our tariff volumes in the Permian Basin region was primarily from the Permian JV assets, largely due to additional volumes from the pipelines contributed by Oryx Midstream as well as increased production and new connections.

We deduct the portion of the financial results attributable to Oryx Midstream’s 35% interest in the Permian JV in determining Segment Adjusted EBITDA, which partially offset the favorable impact of the volume growth when comparing Segment Adjusted EBITDA for 2022 compared to 2021.

• Pipeline Projects.

The Capline pipeline reversal project and phase two of the Wink to Webster pipeline project were placed in service in the first quarter of 2022, which favorably impacted equity earnings in unconsolidated entities and our tariff volumes in 2022.

The variance in equity earnings in unconsolidated entities for the year ended December 31, 2022 compared to the year ended December 31, 2021 was also driven by the unfavorable impact to the prior period of the recognition of our proportionate share of the write-off of costs associated with a capital project canceled during the second quarter of 2021 (which impacted equity earnings in unconsolidated entities but is excluded from Segment Adjusted EBITDA and thus is reflected as an “Adjustment” as “Depreciation and amortization of unconsolidated entities” in the table above).

• Pipeline Loss Allowance Revenue.

Pipeline loss allowance revenues increased for the year ended December 31, 2022 compared to the year ended December 31, 2021 due to a combination of higher prices and higher volumes during 202 2.

• Market Opportunities.

Our results for the year ended December 31, 2022 benefited from favorable Canadian crude oil differentials and the sale of excess linefill and inventory in a higher crude oil price environment;

however, in comparison to the year ended December 31, 2021, these favorable variances were offset by the benefit of the monetization of contango hedges during the year ended December 31, 2021.

• Natural Gas Storage Assets.

We sold our natural gas storage facilities in August 2021, impacting the comparison of our results for the year ended December 31, 2022 compared to the year ended December 31, 2021.

Net revenues from our natural gas storage facilities were approximately $76 million for the year ended December 31, 2021, which included the benefit of favorable margins from hub activities related to Winter Storm Uri, as mentioned below.

• Winter Storm Uri.

During the first quarter of 2021, Winter Storm Uri had a negative impact on our volumes;

however, this impact was more than offset during the 2021 period by gains related to hedged power costs, which are reflected in equity earnings and field operating costs, and favorable margins from hub activities at our natural gas storage facilities resulting from Winter Storm Uri.

Index to Financial Statements

• Line 2000 Pipeline.

In the third quarter of 2022, we temporarily ceased service on Line 2000 in California as a precautionary measure following a routine inspection, which unfavorably impacted our results for the year ended December 31, 2022 compared to the year ended December 31, 2021.

Line 2000 was returned to service in the first quarter of 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.

Field Operating Costs.

The increase in field operating costs for the year ended December 31, 2022 compared to the year ended December 31, 2021 was primarily due to (i) an increase in estimated costs 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), (ii) the impact of gains related to hedged power costs resulting from Winter Storm Uri recognized in the first quarter of 2021, (iii) incremental operating costs from the Permian JV, (iv) increased utilities as a result of higher volumes, (v) increased costs resulting from higher third-party trucked volumes and (vi) higher fuel prices, partially offset by (vii) the sale of our natural gas storage facilities in August 2021.

Segment General and Administrative Expenses.

See the “—Consolidated Results” section above for a discussion of general and administrative expenses.

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).

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, 2022 compared to the year ended December 31, 2021 was primarily due to ongoing station upgrades, integrity projects and tank maintenance, partially offset by lower costs due to the completion of certain projects.

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.

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.

Generally, our segment results are impacted by (i) increases or decreases in our NGL sales volumes, (ii) the overall strength, weakness and volatility of market conditions, including the differential between the price of natural gas and the extracted NGL, as well as location differentials and time spreads, and (iii) the effects of competition on our NGL margins.

In addition, we utilize various risk management strategies to manage our commodity exposure.

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.

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 Statements

The following tables set forth our operating results from our NGL segment:

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Long-term inventory costing adjustments 13 (1) 14 **

Equity-indexed compensation expense

Foreign currency revaluation 5 1 4 **

Segment Adjusted EBITDA $ 522 $ 518 $ 4 1 %

Maintenance capital $ 99 $ 68 $ 31 46 %

Maintenance capital expenditures $ 86 $ 99 $ (13) (13) %

Year Ended December 31, Variance

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See Note 19 to our Consolidated Financial Statements for additional discussion of such adjustments.

(4) Average daily volumes calculated as the 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) During the fourth quarter of 2022, we modified our sales volumes reported to include only propane and butane sales.

Prior to the fourth quarter of 2022, our reported sales volumes included other NGL products, primarily ethane, that represented a significant portion of our total NGL sales volumes but did not contribute significantly to Segment Adjusted EBITDA.

Sales volumes for earlier periods presented herein have been recast to include only propane and butane.

(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.

Segment Adjusted EBITDA

NGL Segment Adjusted EBITDA increased for the year ended December 31, 2022 compared to the year ended December 31, 2021 primarily due to the favorable impact of higher realized fractionation spreads between the price of natural gas and the extracted NGL (“frac spreads”) and increased NGL mix produced at our straddle plants.

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.

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

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Net Revenues.

Net revenues from our NGL activities, excluding the impact of derivative activities and inventory valuation and long-term inventory costing adjustments, increased for the year ended December 31, 2022 compared to the year ended December 31, 2021 primarily due to higher realized frac spreads, increased NGL mix produced at our straddle plants and higher field operating cost recoveries at our Empress straddle plants as part of our commercial agreements, primarily related to higher utilities-related costs.

This was partially offset by lower NGL sales volumes due to a reduction in lower margin hub activity.

Additionally, net revenues for the year ended December 31, 2022 include the benefit of a full year of increased ownership in the Empress straddle plants and higher product gains at certain of our NGL facilities.

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.

Field Operating Costs.

The increase in field operating costs for the year ended December 31, 2022 compared to the year ended December 31, 2021 was primarily due to increased utilities-related costs from (i) increased production at certain of our Empress straddle plants, (ii) our increased ownership in the Empress straddle plants and (iii) higher utility-related prices in the 2022 period.

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.

Segment General and Administrative Expenses.

See the “—Consolidated Results” section above for a discussion of general and administrative expenses.

Maintenance Capital

The increase in maintenance capital spending for the year ended December 31, 2022 compared to the year ended December 31, 2021 was primarily due to (i) a turnaround at one of our Empress facilities during 2022 and (ii) various maintenance capital projects on our Co-Ed pipeline system.

This increase was partially offset by the absence of certain costs in 2022 that were incurred in 2021, including repair costs at the Fort Saskatchewan facility.

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.

Liquidity and Capital Resources

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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, 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 long-term debt and (v) distributions to our Class A shareholders and noncontrolling interests.

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 long-term debt and (v) distributions to our Class A shareholders 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 PAA’s commercial paper program or credit facilities.

In addition, we generally expect to fund our long-term needs, such as those resulting from investment capital activities or acquisitions and refinancing long-term debt, through a variety of sources (either separately or in combination), which may include the sources mentioned above as funding for short-term needs and/or the issuance of additional equity or debt securities and the sale of assets.

As of December 31, 2022, although we had a working capital deficit of $535 million, we had approximately $3.0 billion of liquidity available to meet our ongoing operating, investing and financing needs, subject to continued covenant compliance, as noted below (in millions):

We generally expect to fund our short-term cash requirements through cash flow generated from operating activities and/or borrowings under credit facilities or PAA’s 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 long-term debt, through a variety of sources, which may include any or a combination of the sources listed above.

As of December 31, 2023, although we had a working capital deficit of $89 million, we had over $2.6 billion of liquidity available to meet our ongoing operating, investing and financing needs, subject to continued covenant compliance, as noted below (in millions):

December 31, 2023

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(1) Represents availability prior to giving effect to borrowings outstanding under the PAA commercial paper program, which reduce available capacity under the facilities.

(2) Available capacity under the PAA senior unsecured revolving credit facility and the PAA senior secured hedged inventory facility was reduced by outstanding letters of credit of $33 million and $69 million, respectively.

Index to Financial Statements

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We believe that our financial position remains strong and we have sufficient liquid assets, cash flow from operating activities and borrowing capacity under PAA’s 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 associated with the COVID-19 pandemic and/or actions by OPEC.

A prolonged material decrease in our cash flows would likely produce an adverse effect on our borrowing capacity and cost of borrowing.

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

These include PAA’s $1.35 billion senior unsecured revolving credit facility maturing in 2027, $1.35 billion senior secured hedged inventory facility maturing in 2025 and $2.7 billion unsecured commercial paper program that is backstopped by PAA’s revolving credit facility and its hedged inventory facility.

These include PAA’s $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 PAA’s revolving credit facility and its hedged inventory facility.

The credit agreements for PAA’s revolving credit facilities (which impact PAA’s ability to access its commercial paper program because they provide the financial backstop that supports PAA’s short-term credit ratings) and the indentures governing its senior notes contain cross-default provisions.

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Index to Financial Statements

During 2022, we decreased the volume of our crude oil inventory due to opportunities for inventory liquidation during the year, and we also had lower margin balances required as part of our hedging activities, both of which reduced required funding by short-term debt.

These decreases were partially offset by higher NGL volumes at the end of 2022 due to inventory builds as part of the winter heating season.

During 2021, we decreased the volume of both our crude oil inventory due to fewer storage opportunities in the contango market and our NGL inventory as well as the margin balances required as part of our hedging activities, all of which reduced required funding by short-term debt.

The cash inflows associated with these activities were partially offset by higher prices for inventory purchased and stored at the end of the current period compared to the end of 2020.

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.

Investing Activities

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Acquisition capital (2) (4)

$ 1,061 $ 829

(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.”

(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 interest, was approximately $265 million and $202 million, respectively, for 2022.

(4) 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.

Acquisition capital for 2021 represents the cash consideration paid as part of the Asset Exchange transaction.

(3) Investment capital and maintenance capital, net to our 65% interest in the Permian JV, was approximately $310 million and $214 million, respectively, for 2023, and approximately $265 million and $202 million, respectively, for 2022.

(4) 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.

Acquisition capital, net to our 65% interest in the Permian JV, was approximately $281 million and $258 million for 2023 and 2022, respectively.

Investment Capital Projects

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(3) Includes projects at our St.

James, Cushing and Fort Saskatchewan terminals.

James and Fort Saskatchewan terminals.

Projected 2024 Capital Expenditures.

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Approximately half of our projected investment capital expenditures are expected to be invested in the Permian JV assets.

Additionally, maintenance capital for 2023 is currently projected to be $205 million ($195 million net to our interest).

Additionally, maintenance capital for 2024 is currently projected to be approximately $250 million ($230 million net to our interest).

We expect to fund our 2024 investment and maintenance capital expenditures primarily with retained cash flow.

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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.

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

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 sale of non-core assets, the sale of partial interests in assets to strategic joint venture partners, acquisitions and large investment capital projects.

With respect to a potential divestiture or acquisition, 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 buyers (in the case of a divestiture) or sellers (in the case of an acquisition).

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.

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Borrowings and Repayments Under Credit Arrangements

We had no net borrowings or repayments under the PAA credit facilities or commercial paper program during the year ended December 31, 2022.

During the year ended December 31, 2021, we had net repayments under the PAA credit facilities and commercial paper program of $712 million.

The net repayments resulted primarily from cash flow from operating activities and proceeds from asset sales, which offset borrowings during the period related to funding needs for capital investments, inventory purchases and other general partnership purposes.

During the year ended December 31, 2023, we had net borrowings under the PAA 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.

Index to Financial Statements

In connection with the sale of our Pine Prairie and Southern Pines natural gas storage facilities in August 2021, we repaid our two GO Zone term loans totaling $200 million.

See Note 7 for additional information regarding the sale of our natural gas storage facilities.

We had no net borrowings or repayments under the PAA credit facilities or commercial paper program during the year ended December 31, 2022.

Repayments of PAA Senior Notes.

During 2022, PAA repaid the following senior unsecured notes in full (in millions):

During 2023 and 2022, PAA repaid the following senior unsecured notes in full (in millions):

Year Description Repayment Date

2023 $700 million 3.85% PAA Senior Notes due October 2023

October 2023 (1)

2023 $400 million 2.85% PAA Senior Notes due January 2023

January 2023 (1)

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

(1) PAA repaid these senior notes with cash on hand and borrowings under its commercial paper program.

On January 31, 2023, PAA redeemed its 2.85%, $400 million senior notes.

PAA utilized a combination of cash on hand and borrowings under its commercial paper program to repay these senior notes.

PAA also intends to utilize a combination of cash flow from operating activities, proceeds from asset sales and borrowings under its commercial paper program to repay its 3.85%, $700 million notes due October 2023.

Registration Statements

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We also have access to a universal shelf registration statement (“PAGP WKSI Shelf”), which provides us with the ability to offer and sell an unlimited amount of equity securities, subject to market conditions and its capital needs.

We did not conduct any offerings under the PAGP Traditional Shelf or PAGP WKSI Shelf during the years ended December 31, 2022 or 2021.

PAA Registration Statements .

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

PAA repurchased common units under the Program during the years ended December 31, 2022 and 2021 for a total purchase price of $74 million and $178 million, respectively, including commissions and fees.

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

PAA 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.

The remaining available capacity under the Program as of December 31, 2023 was $198 million.

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Holders of PAA’s 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).

Subject to certain limitations, following January 28, 2021, the holders of PAA’s Series A preferred units have the right to make a one-time election to reset the distribution rate.

In January 2023, PAA received notice that the Series A preferred unitholders elected the Preferred Distribution Rate Reset Option.

Effective January 31, 2023, the new Series A preferred unit distribution rate is equal to 9.375% per annum on the original issue price (approximately $2.46 per unit annualized).

The quarterly distribution to be paid in May 2023 will reflect a pro-rated amount of $0.58516 per unit.

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

Distributions to PAA’s Series B preferred unitholders.

Holders of PAA’s Series B preferred units are entitled to receive, when, as and if declared by PAA’s general partner out of legally available funds for such purpose, cumulative cash distributions, as applicable.

Through and including November 15, 2022, holders were entitled to a distribution equal to $61.25 per unit per year, payable semiannually in arrears on the 15th day of May and November.

On and after November 15, 2022, distributions on the Series B units accumulate based on a floating rate equal to the applicable three-month LIBOR (or, if discontinued, a substitute or successor rate determined by the calculation agent) plus a spread of 4.11% and is payable quarterly on the 15th day of February, May, August and November.

The distribution rate for the quarterly distribution paid on February 15, 2023 was 8.71614% ($22.27 per Series B preferred unit).

See Note 12 to our Consolidated Financial Statements for further discussion of PAA’s Series B preferred units.

Distributions on the Series B preferred units accumulate based on the applicable three-month SOFR, plus a credit spread adjustment of 0.26121%, plus 4.11% per annum.

The distribution rate for the quarterly distribution paid on February 15, 2024 was 9.75093% per annum ($24.92 per Series B preferred unit).

Distributions to PAA’s common unitholders.

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See Note 10 to our Consolidated Financial Statements for information regarding our debt obligations and Note 18 for information regarding our leases and other commitments.

Index to Financial Statements

Purchase Obligations

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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.

Index to Financial Statements

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

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50% $ 210 $ 5

OMOG JV LLC Crude Oil Pipeline (1)

57% $ 434 $ 13

Saddlehorn Pipeline Company, LLC Crude Oil Pipeline 30% $ 600 $ 21

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(1) We serve as operator of the asset.

Index to Financial Statements

Critical Accounting Policies and Estimates

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We also discuss our critical accounting policies and estimates with the Audit Committee of the Board of Directors.

Index to Financial Statements

We believe that the assumptions, judgments and estimates involved in the accounting for our (i) estimated fair value of assets and liabilities acquired and identification of associated goodwill and intangible assets, (ii) fair value of derivatives, (iii) accruals and contingent liabilities, (iv) property and equipment, depreciation and amortization expense and asset retirement obligations, (v) impairment assessments of property and equipment, investments in unconsolidated entities and intangible assets and (vi) inventory valuations have the greatest potential impact on our Consolidated Financial Statements.

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Determining the fair value of assets and liabilities acquired, as well as intangible assets that relate to such items as customer relationships, acreage dedications and other contracts, involves professional judgment and is ultimately based on acquisition models and management’s assessment of the value of the assets acquired and, to the extent available, third-party assessments.

In the third quarter of 2023, our Permian JV acquired the remaining 43% interest in OMOG JV Holdings LLC (“OMOG”) and certain gathering assets in the Southern Delaware basin from Rattler Midstream Operating LLC.

The transaction had an aggregate purchase price of $294 million ($191 million net to our 65% interest in the Permian JV).

As a result of the transaction, the Permian JV now owns 100% of OMOG and its subsidiaries and such entities are reflected as consolidated subsidiaries in our Consolidated Financial Statements.

Prior to this transaction, the Permian JV’s 57% interest in OMOG was accounted for as an equity method investment.

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 November 2022, we and Enbridge Inc.

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Less than 1% of total annual revenues are based on estimates derived from internal valuation models.

Index to Financial Statements

The Preferred Distribution Rate Reset Option of our Series A preferred units is an embedded derivative that is recorded at fair value in our Consolidated Balance Sheets.

The valuation model utilized for this embedded derivative contains multiple inputs, some of which involve management judgment, including our common unit price, ten-year United States treasury rates, default probabilities and timing estimates to ultimately calculate the fair value of our Series A preferred units with and without the Preferred Distribution Rate Reset Option.

Although the resolution of the uncertainties involved in these estimates has not historically had a material impact on our results of operations or financial condition, we cannot provide assurance that actual amounts will not vary significantly from estimated amounts.

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 Statements

Accruals and Contingent Liabilities.

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• the intention of “holding”, “abandoning” or “selling” an asset;

Index to Financial Statements

• the forecast of undiscounted expected future cash flow over the asset’s estimated useful life;

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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 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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During the years ended December 31, 2023, 2022 and 2021, we did not record any charges related to the valuation adjustment of our inventory.

During the year ended December 31, 2020, we recorded charges of $233 million related to the valuation adjustment of our crude oil inventory due to declines in prices.

See Note 5 to our Consolidated Financial Statements for further discussion regarding inventory.

Index to Financial Statements

Line 901 Incident Insurance Receivable.

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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.

In the fourth quarter of 2022, insurers responsible for the majority of our remaining insurance coverage formally communicated a denial of coverage.

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.

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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.

We cannot provide assurance that actual receivable amounts will not vary significantly from our estimated amounts.

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.

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

Index to Financial Statements

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