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Item 7. Management’s Discussion and Analysis

2023-03-01 compared with 2022-03-01 · 211 added, 320 removed, 470 unchanged (53% of the section changed)

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• Recent Accounting Pronouncements

A comparative discussion of our 2021 to 2020 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, 2021 filed with the SEC on March 1, 2022.

Executive Summary

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We are a Delaware limited partnership formed in 2013 that has elected to be taxed as a corporation for United States federal income tax purposes.

As of December 31, 2021, our sole cash-generating assets consisted of (i) a 100% managing member interest in GP LLC, an entity that has also elected to be taxed as a corporation for United States federal income tax purposes and (ii) an approximate 81% limited partner interest in AAP through our direct ownership of approximately 193.2 million AAP units and indirect ownership of approximately 1.0 million AAP units through GP LLC.

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

As of December 31, 2022, our sole cash-generating assets consisted of an approximate 81% limited partner interest in AAP through our ownership of approximately 194.4 million AAP units.

We also own a 100% managing member interest in GP LLC.

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).

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PAA’s assets and the services it provides are primarily focused on crude oil and NGL.

Index to Financial Statements

Segment Changes

During the fourth quarter of 2021, we reorganized our historical operating segments:

Transportation, Facilities and Supply and Logistics into two operating segments:

Crude Oil and Natural Gas Liquids (“NGL”).

The change in our segments stems primarily from (i) a multi-year transition in the midstream energy industry driven by increased competition that has reduced the stand alone earnings opportunities of our supply and logistics activities such that those activities now primarily support our effort to increase the utilization of our Crude Oil and NGL assets and (ii) internal changes regarding the oversight and reporting of our assets and related results of operations.

Additionally, during the fourth quarter of 2021, we modified our definition of Segment Adjusted EBITDA to exclude amounts attributable to noncontrolling interests in consolidated joint ventures.

In connection with the Permian JV formation in October 2021, our CODM determined this modification resulted in amounts that were more meaningful to evaluate segment performance.

See Note 7 to our Consolidated Financial Statements for additional information regarding the Permian JV.

All segment data and related disclosures for earlier periods presented herein have been recast to reflect the new segment reporting structure and the modification to our definition of Segment Adjusted EBITDA.

See Note 20 to our Consolidated Financial Statements for additional information.

Market Overview and Outlook

Crude oil and other petroleum liquids are supplied by producers around the world, including the Organization of Petroleum Exporting Countries (“OPEC”) 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”), the Russian Federation and North American producers, among others.

The chart below depicts the relationship between global supply of crude oil and other petroleum liquids and demand since the beginning of 2018 and the U.S.

Energy Information Administration’s (“EIA”) Short-Term Energy Outlook as of February 2022:

Energy Information Administration’s (“EIA”) Short-Term Energy Outlook as of January 2023:

Index to Financial Statements

World Liquid Fuels Production and Consumption Balance (1)

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(1) Barrels produced and consumed per quarter.

Index to Financial Statements

Global crude oil demand at the end of 2021 was near pre-COVID levels, with the EIA and other third parties forecasting demand to exceed 2019 levels by late 2022 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 could further exacerbate many of the supply concerns that emerged in 2021.

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.

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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 base and integrated business model.

Building on the actions we took in 2020 to ensure that we were well positioned to manage through the pandemic, in 2021 we continued to build momentum and reinforce our long-term positioning.

This included further optimizing our asset portfolio including, but not limited to, exceeding our asset sales target, substantially completing our multi-year capital program, and closing a highly strategic joint-venture in the Permian Basin through a cashless and debt-free transaction.

Additionally, we reduced debt by $1 billion, meaningfully reduced capital expenditures by $230 million versus our initial 2021 guidance, and further streamlined our U.S.

and Canadian operations and organizational cost structure.

While each of these actions should contribute to a stronger balance sheet and enhanced liquidity and long-term financial flexibility, we can provide no assurance that we will be able to effect certain future actions (such as additional capital reductions, asset sales and expense reductions) and additional actions may be necessary to achieve our balance sheet, liquidity and financial security objectives.

See “Risk Factors—Risks Related to PAA’s Business” in Item 1A.

While some modifications in our operations continue to be necessary to deal with risks associated with the COVID-19 pandemic, we have not experienced any material constraints on our ability to continue our essential business functions and have not incurred any significant additional operating costs as a result of the pandemic.

We remain focused on the health and safety of our workforce, and have modified our operations in ways that we believe are prudent and appropriate in order to protect our employees while continuing to operate our assets in an effective, safe and responsible manner.

Many governments have enacted or are contemplating measures to provide aid and economic stimulus in response to the COVID-19 pandemic.

These measures include actions by both the United States federal government and the government of Canada.

There has been no material direct impact to our financial position, results of operations or cash flows resulting from these measures.

However, our Canadian subsidiary participated in a wage subsidy program during 2021 and 2020 for subsidies totaling approximately $7 million and $23 million, respectively.

The impact of such subsidies and incremental COVID-19 costs is included in the line items “Field operating costs” and “General and administrative expenses”.

See “—Results of Operations” for further discussion.

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.

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

We recognized net income of $600 million for the year ended December 31, 2021 compared to a net loss of $2.440 billion for the year ended December 31, 2020 and net income of $2.062 billion for the year ended December 31, 2019.

The net loss for the 2020 period was primarily driven by the macroeconomic and industry specific challenges discussed above which resulted in goodwill impairment losses and non-cash impairment charges related to the write-down of certain pipeline and other long-lived assets, certain of our investments in unconsolidated entities, and assets upon classification as held for sale totaling approximately $3.4 billion.

In addition, we recognized approximately $233 million of inventory valuation adjustments due to declines in commodity prices during the first quarter of 2020.

The 2021 period includes a net loss on asset sales and asset impairments of $592 million, 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.

Results from our reporting segments were lower for the year ended December 31, 2021 compared to the year ended December 31, 2020 primarily due to less favorable crude oil market conditions.

Results from our reporting segments were lower for the year ended December 31, 2020 compared to the year ended December 31, 2019 primarily due to less favorable crude oil differentials and NGL sales margins and lower volumes, partially offset by the favorable impact of contango market conditions.

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

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.

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

Results of Operations

Consolidated Results

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

Year Ended December 31, 2021-2020 2020-2019

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

Year Ended December 31, Variance

2022 2021 $ %

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Gains/(losses) on asset sales and asset impairments, net (269) (592) 323 55 %

Goodwill impairment losses — (2,515) — 2,515 100 % (2,515) N/A

Equity earnings in unconsolidated entities 403 274 129 47 %

Gain on/(impairment of) investments in unconsolidated entities, net

2 (182) 271 184 101 % (453) (167) %

Gains/(losses) on investments in unconsolidated entities, net 346 2 344 **

Interest expense, net (405) (425) 20 5 %

Other income, net 19 39 24 (20) (51) % 15 63 %

Income tax (expense)/benefit (112) 167 (176) (279) (167) % 343 195 %

Net income/(loss) 600 (2,440) 2,062 3,040 125 % (4,502) (218) %

Net (income)/loss attributable to noncontrolling interests (540) 1,872 (1,731) (2,412) (129) % 3,603 208 %

Net income/(loss) attributable to PAGP $ 60 $ (568) $ 331 $ 628 111 % $ (899) (272) %

Basic net income/(loss) per Class A share

$ 0.31 $ (3.06) $ 1.97 $ 3.37 ** $ (5.03) **

Diluted net income/(loss) per Class A share

$ 0.31 $ (3.07) $ 1.96 $ 3.38 ** $ (5.03) **

Basic weighted average Class A shares outstanding

194 186 168 8 ** 18 **

Diluted weighted average Class A shares outstanding

Other income/(expense), net (219) 19 (238) **

Income tax expense (246) (112) (134) (120) %

Net income 1,163 600 563 94 %

Net income attributable to noncontrolling interests (995) (540) (455) (84) %

Net income attributable to PAGP $ 168 $ 60 $ 108 180 %

Basic and diluted net income per Class A share

$ 0.86 $ 0.31 $ 0.55 **

Basic and diluted weighted average Class A shares outstanding

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

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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 three years (in dollars per barrel):

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

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2021 $ 48 $ 85 $ 68

2019 $ 46 $ 66 $ 57

Product sales revenues and purchases increased for the year ended December 31, 2021 compared to the year ended December 31, 2020 primarily due to higher prices and volumes in the 2021 period.

Product sales revenues and purchases decreased for the year ended December 31, 2020 compared to the year ended December 31, 2019 primarily due to lower prices and volumes in the 2020 period.

Revenues from services decreased for the year ended December 31, 2021 compared to the year ended December 31, 2020 primarily due to the sale of assets, partially offset by the recognition of revenues associated with deficiencies under minimum volume commitments in 2020.

Revenues from services decreased for the year ended December 31, 2020 compared to the year ended December 31, 2019 primarily due to lower pipeline volumes, a portion of which were covered by minimum volume commitments for which the associated revenue was deferred to future periods.

See further discussion of our net revenues in the “—Analysis of Operating Segments” section below.

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.

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

Field Operating Costs

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General and Administrative Expenses

The increase in general and administrative expenses for the year the year ended December 31, 2021 compared to the year ended December 31, 2020 was primarily due to (i) transaction-related costs incurred in connection with the formation of the Permian JV (which impacts our general and administrative expenses but are excluded in the calculation of Adjusted EBITDA and Segment Adjusted EBITDA), (ii) increased information systems costs and (iii) reduced wage subsidies received by our Canadian subsidiary, partially offset by other lower employee-compensation related items during the 2021 period.

The decrease in general and administrative expenses for the year the year ended December 31, 2020 compared to the year ended December 31, 2019 was primarily due to (i) lower equity-based compensation costs on liability-classified awards (which is not excluded in the calculation of Adjusted EBITDA and Segment Adjusted EBITDA), due to a decrease in PAA’s common unit price, (ii) decreased travel and entertainment costs, (iii) lower compensation costs including the benefit of wage subsidies received by our Canadian subsidiary and (iv) general cost reductions associated with exiting low margin, high administrative cost businesses.

Such items were partially offset by an overall increase in compensation costs related to severance costs associated with our efforts to streamline our organization.

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.

Depreciation and Amortization

Depreciation and amortization expense increased for the year ended December 31, 2021 compared to the year ended December 31, 2020 largely driven by (i) a reduction in the useful lives of certain assets and (ii) additional depreciation expense associated with acquired assets, partially offset by a reduction in depreciation expense associated with assets sold.

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.

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

Depreciation and amortization expense increased for the year ended December 31, 2020 compared to the year ended December 31, 2019 largely driven by additional depreciation expense associated with acquired assets, the completion of various investment capital projects and a reduction in the useful lives of certain assets, partially offset by a reduction in depreciation expense associated with assets sold.

Index to Financial Statements

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

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 during the second quarter (these assets were sold in August 2021), and (iii) a gain of $106 million recognized in the second quarter related to the asset exchange agreement (the “Asset Exchange”) involving the sale of our Milk River crude oil pipeline in exchange for additional interests in certain of the Empress gas processing plants.

The net loss on asset sales and asset impairments for the year ended December 31, 2020 included (i) non-cash impairment losses on held and used assets of approximately $541 million related to the write-down of (a) certain pipeline and other long-lived assets due to the current macroeconomic and geopolitical conditions including the collapse of oil prices driven by both the decrease in demand caused by the COVID-19 pandemic and excess supply, as well as changing market conditions and expected lower crude oil production in certain regions, and (b) idled or underutilized assets for which is it has been determined that it is unlikely that opportunities will exist in the future to recover our investment in these assets and (ii) net losses of approximately $178 million related to the sale of assets, including non-cash impairments recognized upon classification as assets held for sale.

The net loss on asset sales and asset impairments for the year ended December 31, 2019 was largely driven by a loss on the sale of a storage terminal in North Dakota.

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.

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

Goodwill Impairment Losses

During the first quarter of 2020, we recognized a goodwill impairment charge of $2.5 billion, representing the entire balance of goodwill.

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

Gain on/(Impairment of) Investments in Unconsolidated Entities, Net

During the year ended December 31, 2020, we recognized losses of $202 million related to the write-down of certain of our investments in unconsolidated entities.

Additionally, we recognized a gain of $21 million related to our sale of a 10% interest in Saddlehorn Pipeline Company, LLC.

During the year ended December 31, 2019, we recognized a non-cash gain of $269 million related to a fair value adjustment resulting from the accounting for the contribution of our undivided joint interest in the Capline pipeline system for an equity interest in Capline Pipeline Company LLC.

See Note 9 to our Consolidated Financial Statements for additional information regarding our unconsolidated entities.

Interest Expense

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.

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

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 9 to our Consolidated Financial Statements for additional information regarding these transactions.

Interest Expense, Net

Interest expense is primarily impacted by:

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• interest capitalized on capital projects.

Index to Financial Statements

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

Weighted Average

LIBOR/SOFR Weighted Average

Interest Rate (1)

Interest expense for the year ended December 31, 2021

Impact of lower capitalized interest 10

Impact of borrowings under credit facilities and commercial paper program 3

Impact of issuance and retirement of senior notes (4)

Interest expense for the year ended December 31, 2020 $ 436 0.5 % 4.1 %

Impact of issuance and retirement of senior notes (13)

Impact of borrowings under credit facilities and commercial paper program (4)

$ 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.

See Note 11 to our Consolidated Financial Statements for additional information regarding our debt and related activities during the periods presented.

Other Income, Net

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

Other Income/(Expense), Net

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

Year Ended December 31,

2021 2020 2019

Gain related to mark-to-market adjustment of PAA’s Preferred Distribution Rate Reset Option (1)

$ 14 $ 20 $ 2

Net gain on foreign currency revaluation (2)

$ 19 $ 39 $ 24

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

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

(1) See Note 13 to our Consolidated Financial Statements for additional information.

(2) The activity during the years presented was primarily related to the impact from the change in the USD to CAD 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, 2021 compared to the year ended December 31, 2020 was primarily due to the impact of higher earnings.

The net favorable income tax variance for the year ended December 31, 2020 compared to the year ended December 31, 2019 was primarily due to (i) lower taxable earnings from our Canadian operations, (ii) the impact of lower earnings at PAA on income attributable to PAGP and (iii) lower year-over-year income as impacted by fluctuations in the derivative mark-to-market valuations in our Canadian operations, partially offset by (iv) the recognition of a deferred tax benefit of approximately $60 million during the second quarter of 2019 as a result of the reduction of the provincial tax rate in Alberta, Canada.

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.

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 earnings before interest, taxes, depreciation and amortization (including our proportionate share of depreciation and amortization, including write-downs related to cancelled projects, of unconsolidated entities), gains and losses on asset sales and asset impairments, goodwill impairment losses and gains on and impairments of investments in unconsolidated entities, adjusted for certain selected items impacting comparability (“Adjusted EBITDA”) and Adjusted EBITDA attributable to PAA, which excludes the portion of Adjusted EBITDA attributable to noncontrolling interests in consolidated joint venture entities.

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.

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.

Performance Measures

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 related to investing activities (such as the purchase of linefill) 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 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.

We also adjust for amounts billed by our equity method investees related to deficiencies under minimum volume commitments.

Such amounts are presented net of applicable amounts subsequently recognized into revenue.

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Index to Financial Statements

The following table sets forth the reconciliation of the non-GAAP financial performance measures Adjusted EBITDA and Adjusted EBITDA attributable to PAA from Net Income/(Loss) (in millions):

Year Ended December 31, 2021-2020 2020-2019

The following table sets forth the reconciliation of the non-GAAP financial performance measures Adjusted EBITDA and Adjusted EBITDA attributable to PAA from Net Income (in millions):

Year Ended December 31, Variance

2022 2021 $ %

Net income/(loss) $ 600 $ (2,440) $ 2,062 $ 3,040 125 % $ (4,502) (218) %

Net income $ 1,163 $ 600 $ 563 94 %

Interest expense, net 405 425 (20) (5) %

Income tax expense/(benefit) 112 (167) 176 279 167 % (343) (195) %

Income tax expense 246 112 134 120 %

Depreciation and amortization 968 777 191 25 %

(Gains)/losses on asset sales and asset impairments, net 269 592 (323) (55) %

Goodwill impairment losses — 2,515 — (2,515) (100) % 2,515 N/A

(Gain on)/impairment of investments in unconsolidated entities, net (2) 182 (271) (184) (101) % 453 167 %

(Gains)/losses on investments in unconsolidated entities, net (346) (2) (344) **

Depreciation and amortization of unconsolidated entities (1)

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Selected Items Impacting Comparability:

(Gains)/losses from derivative activities and inventory valuation adjustments (271) 480 160 (751) ** 320 **

Derivative activities and inventory valuation adjustments (280) (271) (9) **

Long-term inventory costing adjustments (4) (94) 90 **

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Equity-indexed compensation expense 32 19 13 **

Net (gain)/loss on foreign currency revaluation (4) (3) 14 (1) ** (17) **

Foreign currency revaluation 4 (4) 8 **

Line 901 incident 95 15 80 **

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(146) (326) 180 **

Gains from derivative activities (4)

(14) (20) (2) 6 ** (18) **

Net gain on foreign currency revaluation (5)

(3) (13) (15) 10 ** 2 **

Net gain on early repayment of senior notes (6)

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

189 (14) 203 **

Foreign currency revaluation (5)

Selected Items Impacting Comparability - Adjusted EBITDA (6)

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

(1) We exclude our proportionate share of the depreciation and amortization expense (including write-downs related to cancelled projects) of unconsolidated entities when reviewing Adjusted EBITDA, similar to our consolidated assets.

(1) 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.

(2) Represents general and administrative expenses incremental to those of PAA, which are not allocated to our reporting segments in determining Segment Adjusted EBITDA and are excluded in the non-GAAP financial performance measures utilized by management.

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(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.

The associated gains and losses are not

Index to Financial Statements

integral to our results and were thus classified as a selected item impacting comparability.

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

See Note 13 to our Consolidated Financial Statements for additional information regarding the Preferred Distribution Rate Reset Option.

(5) During the periods presented, there were fluctuations in the value of CAD to USD, resulting in the realization of foreign exchange gains and losses on the settlement of foreign currency transactions as well as the revaluation of monetary assets and liabilities denominated in a foreign currency.

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

(6) Includes net gains recognized in connection with the repurchase of our outstanding senior notes on the open market.

See Note 11 to our Consolidated Financial Statements for additional information.

(7) Other income/(expense), net per 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.

(8) Reflects amounts attributable to noncontrolling interests in the Permian JV and Red River Pipeline LLC.

See Note 12 to our Consolidated Financial Statements for additional information regarding these noncontrolling interests.

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

Index to Financial Statements

(6) 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.

(7) Reflects amounts attributable to noncontrolling interests in the Permian JV, Cactus II and Red River.

Analysis of Operating Segments

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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) of unconsolidated entities, further adjusted for (e) certain selected items including (i) the mark-to-market of 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 related to investing activities (such as the purchase of linefill) 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”).

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.

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Revenues and expenses from our Canadian based subsidiaries, which use CAD as their functional currency, are translated at the prevailing average exchange rates for the month.

Index to Financial Statements

Crude Oil Segment

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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 to sales locations, including our terminals, third-party connecting carriers, regional hubs or to refineries.

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.

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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.

Index to Financial Statements

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

Operating Results (1)

(in millions, except per barrel data)

Year Ended December 31, 2021-2020 2020-2019

(in millions)

Year Ended December 31, Variance

2022 2021 $ %

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Depreciation and amortization of unconsolidated entities 85 123 (38) (31) %

(Gains)/losses from derivative activities and inventory valuation adjustments (252) 259 180 (511) ** 79 **

Derivative activities and inventory valuation adjustments (11) (252) 241 **

Long-term inventory costing adjustments (3) (67) 64 **

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Equity-indexed compensation expense 32 19 13 **

Net (gain)/loss on foreign currency revaluation (3) (2) 11 (1) ** (13) **

Foreign currency revaluation 3 (3) 6 **

Line 901 incident 95 15 80 **

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Maintenance capital $ 112 $ 100 $ 12 12 %

Index to Financial Statements

Average Volumes Year Ended December 31, 2021-2020 2020-2019

2021 2020 2019 Volumes % Volumes %

Tariff activities volumes (4)

Crude oil pipelines tariff volumes (by region):

Average Volumes Year Ended December 31, Variance

2022 2021 Volumes %

Crude oil pipeline tariff (by region) (4)

Permian Basin (5)

5,638 4,412 1,226 28 %

South Texas / Eagle Ford (5)

1,927 1,793 134 7 %

Mid-Continent (5)

455 379 498 76 20 % (119) (24) %

Gulf Coast 158 134 165 24 18 % (31) (19) %

Rocky Mountain (5)

332 245 293 87 36 % (48) (16) %

Western 236 223 198 13 6 % 25 13 %

Canada 286 294 323 (8) (3) % (29) (9) %

Crude oil pipelines tariff activities total volumes 6,205 6,082 6,613 123 2 % (531) (8) %

Total crude oil pipeline tariff 7,565 6,205 1,360 22 %

Commercial crude oil storage capacity (5) (6)

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See Note 20 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 pipelines owned by unconsolidated entities or undivided joint interests) for the year divided by the number of days in the year.

(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.

Volumes associated with acquisitions represent total volumes for the number of days we actually owned the assets divided by the number of days in the period.

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

Index to Financial Statements

(6) 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.

(7) Of this amount, approximately 1,038 thousand barrels per day (“MBbls/d”), 862 MBbls/d and 767 MBbls/d were purchased in the Permian Basin for the years ended December 31, 2021, 2020 and 2019, respectively.

(7) Of this amount, approximately 1,073 and 1,038 thousand barrels per day were purchased in the Permian Basin for the years ended December 31, 2022 and 2021, respectively.

Segment Adjusted EBITDA

Crude Oil Segment Adjusted EBITDA decreased for the year ended December 31, 2021 compared to the year ended December 31, 2020 primarily due to less favorable crude oil market conditions for our merchant activities in 2021 (largely associated with decreased contango margins and continuing compressed regional basis differentials).

In addition, the 2021 period was negatively impacted by asset sales.

These impacts were partially offset by lower field operating costs and slightly higher volumes on our pipeline assets.

Crude Oil Segment Adjusted EBITDA decreased for the year ended December 31, 2020 compared to the year ended December 31, 2019 primarily due to overall less favorable crude oil market conditions for our merchant activities during 2020 (compressed regional basis differentials, partially offset by the favorable impact of contango margins) and lower pipeline volumes caused by the impact of the COVID-19 pandemic, partially offset by lower field operating costs.

The various components of Segment Adjusted EBITDA are discussed further below.

Index to Financial Statements

Revenues, Net of Purchases and Related Costs (“net revenues”) and Equity Earnings in Unconsolidated Entities.

The following is a discussion of the significant items impacting net revenues and equity earnings in unconsolidated entities for the comparable 2021, 2020 and 2019 periods.

• COVID-19 Impact.

Crude oil production in the U.S.

stabilized in 2021 and while it began increasing in the second half of the year, on average, U.S.

crude oil production was slightly lower than the 2020 average.

In 2020, crude oil production in the U.S.

was nearly 1 million barrels per day lower than the 2019 average, as the pandemic significantly reduced demand for crude oil.

These factors resulted in lower pipeline transportation net revenues across the majority of the regions in which we operate in 2020 as compared to 2019 and unfavorable market conditions and lower earnings from our merchant activities during 2020 and 2021 highlighted by less favorable crude oil differentials, particularly the differential between the value of crude oil in the Permian Basin compared to the Gulf Coast market.

Those negative conditions were partially offset by the favorable impact of contango market conditions during 2020 and, to a lesser extent, during 2021.

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.

The following is a more detailed discussion of the significant factors impacting Segment Adjusted EBITDA for the year ended December 31, 2022 compared to the year ended December 31, 2021.

• 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.

The extreme winter weather event that occurred in February 2021 (“Winter Storm Uri”) resulted in shut-ins that further compounded the impact of the COVID-19 pandemic-related reset to production on our pipeline volumes.

The resulting unfavorable impact on our revenues was more than offset by the favorable impact from lower power costs on equity earnings and field operating costs, as discussed further below.

• Equity Earnings in Unconsolidated Entities.

Volumes on pipelines owned by unconsolidated entities were also negatively impacted by the COVID-19 pandemic-related production declines and, for the pipelines located in the Permian Basin and South Texas/Eagle Ford regions, the effects of Winter Storm Uri in 2021.

The unfavorable impact of the lower volumes on equity earnings was partially offset by lower power costs, including the impact of gains related to hedged power costs resulting from Winter Storm Uri.

In addition, equity earnings for the 2021 period were negatively impacted by (i) the write-off of costs associated with the cancellation of capital projects and (ii) depreciation expense and transition costs associated with phase one of the Wink to Webster pipeline being placed into service during the first quarter of 2021.

Such costs are included in the line item “Depreciation and amortization of unconsolidated entities” in the table above as an adjustment to arrive at Segment Adjusted EBITDA.

• Minimum Volume Commitments.

A portion of the lower volumes experienced on our pipelines, and pipelines owned by unconsolidated entities, in 2020 were covered by minimum volume commitments, some of which had make-up rights.

For contracts that have make-up rights, although payment has been received associated with the volume deficiency, the earnings are not recognized until future periods when either the shortfall is made up or when the shipper’s make-up rights expire or it is determined that their ability to utilize the make-up right is remote.

Such deficiencies are reflected as an “Adjustment” in the table above as discussed further below under “— Adjustments — Deficiencies under minimum volume commitments, net.

• Asset Sales .

Storage and terminalling fees for 2021 compared to 2020 were unfavorably impacted by the sale of (i) our natural gas storage facilities in August 2021 and (ii) our Los Angeles Basin terminals in October 2020.

Field Operating Costs.

The decrease in field operating costs for the year ended December 31, 2021 compared to the year ended December 31, 2020 was primarily due to (i) lower power costs, including the impact of gains related to hedged power costs resulting from Winter Storm Uri, (ii) lower compensation costs resulting from lower headcount and the sales of our natural gas storage facilities in August 2021 and Los Angeles Basin terminals in October 2020, (iii) lower long-haul third-party trucking costs and a decrease in company personnel and truck costs as more of our supply was connected to pipelines and taken off trucks and (iv) streamlining efforts which have resulted in decreases in variable costs.

These favorable impacts were partially offset by (i) incremental operating costs from the Permian JV and (ii) additional 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).

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

The decrease in field operating costs for the year ended December 31, 2020 compared to the year ended December 31, 2019 was primarily due to (i) a decrease in variable costs due to lower volumes, (ii) a decrease of maintenance and integrity management activities, primarily due to interval changes facilitated through risk-based data application, (iii) reduced activity at our rail terminals, (iv) a decrease in long-haul third-party trucking costs and a decrease in company personnel and truck costs as more of our supply was connected to pipelines and taken off trucks and (v) additional estimated costs recognized in 2019 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).

Such favorable impacts were partially offset by higher property taxes attributable to assets placed in service in 2020 and increased property valuations.

• 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.

• 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.

The following is a discussion of adjustments included in the calculation of Segment Adjusted EBITDA, the performance measure utilized by our CODM in the evaluation of segment results.

• Deficiencies under minimum volume commitments, net.

Many industry infrastructure projects developed and completed over the last several years were underpinned by long-term minimum volume commitment contracts whereby the shipper agreed to either:

(i) ship and pay for certain stated volumes or (ii) pay the agreed upon price for a minimum contract quantity.

Some of these agreements include make-up rights if the minimum volume is not met.

If a counterparty has a make-up right associated with a deficiency, we bill the counterparty and defer the revenue attributable to the counterparty’s make-up right but record an adjustment to reflect such amount associated with the current period activity in Segment Adjusted EBITDA.

We subsequently recognize the revenue, and record a corresponding reversal of the adjustment, at the earlier of when the deficiency volume is delivered or shipped, when the make-up right expires or when it is determined that the counterparty’s ability to utilize the make-up right is remote.

The amount presented as an “Adjustment” in the table above reflects the net adjustment for revenues deferred during the period and the reversal of previously deferred revenues that were recognized during the period.

• Impact from Certain Derivative Activities and Inventory Valuation Adjustments.

The impact from certain derivative activities on our net revenues includes mark-to-market and other gains and losses resulting from certain derivative instruments that are related to underlying activities in another period (or the reversal of mark-to-market gains and losses from a prior period), gains and losses on derivatives that are related to investing activities (such as the purchase of linefill) and inventory valuation adjustments, as applicable.

See Note 13 to our Consolidated Financial Statements for a comprehensive discussion regarding our derivatives and risk management activities.

These gains and losses impact our net revenues but are excluded from Segment Adjusted EBITDA and thus are reflected as an “Adjustment” in the table above.

• Long-Term Inventory Costing Adjustments.

Our net revenues are impacted by changes in the weighted average cost of our crude oil inventory pools that result from price movements during the periods.

These costing adjustments relate to long-term inventory necessary to meet our minimum inventory requirements in third-party assets and other working inventory that is needed for our commercial operations.

We consider this inventory necessary to conduct our operations and we intend to carry this inventory for the foreseeable future.

These costing adjustments impact our net revenues but are excluded from Segment Adjusted EBITDA and thus are reflected as an “Adjustment” in the table above.

• Foreign Exchange Impacts.

Our net revenues are impacted by fluctuations in the value of CAD to USD, resulting in the realization of foreign exchange gains and losses on the settlement of foreign currency transactions as well as the revaluation of monetary assets and liabilities denominated in a foreign currency within our Canadian operations.

These gains and losses impact our net revenues 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 decrease in maintenance capital for the year ended December 31, 2021 compared to the year ended December 31, 2020 as well as the comparable period for 2020 and 2019 was due to timing changes, the completion of multi-year reliability improvement programs, application of updated regulatory guidance and lower tractor trailer lease buyouts, among other factors.

The decrease for the year ended December 31, 2021 compared to the year ended December 31, 2020 was also due to the sales of our natural gas storage facilities and Los Angeles Basin terminals.

Index to Financial Statements

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.

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 supply from the gas stream processed at our Empress straddle plant facility as well as acquiring NGL mix supply, which mix supply is then transported, stored and fractionated into finished products and sold to customers.

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.

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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.

Index to Financial Statements

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

Operating Results (1)

(in millions, except per barrel data)

Year Ended December 31, 2021-2020 2020-2019

(in millions)

Year Ended December 31, Variance

2022 2021 $ %

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Adjustments (3) :

(Gains)/losses from derivative activities and inventory valuation adjustments

(19) 221 (20) (240) ** 241 **

Derivative activities (269) (19) (250) **

Long-term inventory costing adjustments (1) (27) 26 **

(27) 1 15 (28) ** (14) **

Net (gain)/loss on foreign currency revaluation

(1) (1) 3 — ** (4) **

Foreign currency revaluation 1 (1) 2 **

Segment Adjusted EBITDA $ 518 $ 285 $ 233 82 %

$ 285 $ 327 $ 467 $ (42) (13) % $ (140) (30) %

Maintenance capital $ 99 $ 68 $ 31 46 %

$ 68 $ 45 $ 39 $ 23 51 % $ 6 15 %

Year Ended December 31, 2021-2020 2020-2019

Year Ended December 31, Variance

Average Volumes (in thousands of barrels per day) (4)

2021 2020 2019 Volumes % Volumes %

2022 2021 Volumes %

NGL fractionation 137 129 8 6 %

NGL pipeline tariff 192 179 13 7 %

NGL sales 141 144 207 (3) (2) % (63) (30) %

Propane and butane sales (5)

94 110 (16) (15) %

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

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

Index to Financial Statements

(2) 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 20 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 pipelines and facilities in which we have undivided joint interests) for the year divided by the number of days in the year.

(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.

Segment Adjusted EBITDA

NGL Segment Adjusted EBITDA decreased for the year ended December 31, 2021 compared to the year ended December 31, 2020 primarily due to (i) higher power costs and (ii) lower wage subsidies received by our Canadian subsidiary in the 2021 period, partially offset by (iii) the favorable impact of higher realized fractionation spreads between the price of natural gas and the extracted NGL (“frac spreads”).

NGL Segment Adjusted EBITDA decreased for the year ended December 31, 2020 compared to the year ended December 31, 2019 primarily due to less favorable NGL sales margins as a result of (i) warmer weather during the fourth quarter of 2020, (ii) weaker frac spreads and (iii) lower NGL supply.

Such unfavorable impacts were partially offset by the favorable impact of wage subsidies received by our Canadian subsidiary in the 2020 period.

The various components of Segment Adjusted EBITDA are discussed further below:

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.

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

Index to Financial Statements

Net Revenues.

The following is a discussion of the significant items impacting net revenues for the comparable 2021, 2020 and 2019 periods.

• Net revenues from our NGL activities, excluding the impact of derivative activities and inventory valuation and long-term inventory costing adjustments, increased slightly for the year ended December 31, 2021 compared to the year ended December 31, 2020 due to higher realized frac spreads, partially offset by the absence of the favorable impact of a deficiency payment in 2020 upon the expiration of a multi-year contract.

• Net revenues from our NGL activities decreased for the year ended December 31, 2020 compared to the year ended December 31, 2019, primarily due to (i) warmer weather during the fourth quarter of 2020, (ii) weaker frac spreads, (iii) less NGL supply as a result of lower border flows through our Empress straddle plants, (iv) the impact of the sale of certain NGL storage terminals in the fourth quarter of 2019 and the second quarter of 2020 and (v) the absence of the favorable impact from certain non-recurring items recorded in the second quarter of 2019, partially offset by (vi) the favorable impact of the receipt of a deficiency payment in 2020 upon the expiration of a multi-year contract.

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.

Field Operating Costs.

The increase in field operating costs for the year ended December 31, 2021 compared to December 31, 2020 was primarily due to (i) increased power costs related to increased ownership in our Empress straddle plants as well as higher power prices, (ii) higher compensation costs including lower wage subsidies received by our Canadian subsidiary, and (iii) costs associated with an operational incident at our Fort Saskatchewan facility that occurred in late September 2021.

The decrease in field operating costs for the year ended December 31, 2020 compared to December 31, 2019 was primarily due to (i) lower power costs as a result of favorable natural gas and electricity price movements, (ii) reductions in compensation costs, primarily due to the benefit of wage subsidies received by our Canadian subsidiary, (iii) the divestiture of certain NGL storage terminals, and (iv) lower integrity management and maintenance activities due to interval changes facilitated through risk-based data application.

Such favorable impacts were partially offset by lower mark-to-market gains in the 2020 period on fuel hedges (which impacts field operating costs but are excluded from Segment Adjusted EBITDA and thus are reflected as an “Adjustment” in the table above).

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 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.

The following is a discussion of adjustments included in the calculation of Segment Adjusted EBITDA, the performance measure utilized by our CODM in the evaluation of segment results.

Index to Financial Statements

• Impact from Certain Derivative Activities and Inventory Valuation Adjustments.

See Note 13 to our Consolidated Financial Statements for a comprehensive discussion regarding our derivatives and risk management activities.

These gains and losses impact our net revenues but are excluded from Segment Adjusted EBITDA and thus are reflected as an “Adjustment” in the table above.

• Long-Term Inventory Costing Adjustments.

Our net revenues are impacted by changes in the weighted average cost of our NGL inventory pools that result from price movements during the periods.

We consider this inventory necessary to conduct our operations and we intend to carry this inventory for the foreseeable future.

These costing adjustments impact our net revenues but are excluded from Segment Adjusted EBITDA and thus are reflected as an “Adjustment” in the table above.

Maintenance Capital.

The increase in maintenance capital spending for the year ended December 31, 2021 compared to the year ended December 31, 2020 was primarily due to (i) repair costs at the Fort Saskatchewan facility, (ii) additional projects related to increased ownership in our Empress straddle plants and (iii) various maintenance capital projects at our Sarnia facility, identified through out of service inspections.

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.

Liquidity and Capital Resources

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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, 2021, although we had a working capital deficit of $94 million, we had over $3 billion of liquidity available to meet our ongoing operating, investing and financing needs, subject to continued covenant compliance, as noted below (in millions):

As of 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):

December 31, 2022

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Index to Financial Statements

(3) Excludes restricted cash of $23 million.

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

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See Note 13 to our Consolidated Financial Statements for a discussion regarding our derivatives and risk management activities.

Net cash provided by operating activities for the years ended December 31, 2021, 2020 and 2019 was approximately $2.0 billion, $1.5 billion and $2.5 billion, respectively, and primarily resulted from earnings from our operations.

Net cash provided by operating activities for the years ended December 31, 2022 and 2021 was approximately $2.4 billion and $2.0 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.

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.

During 2020, we increased the volume of both our crude oil inventory to be stored during the contango market and our NGL inventory in anticipation of the 2020-2021 heating season as well as the margin balances required as part of our hedging activities, all of which was funded by short-term debt.

The cash outflows associated with these activities were partially offset by lower prices for inventory purchased and stored at the end of the current period compared to the end of 2019.

Cash provided by operating activities was favorably impacted by cash received for transactions for which the revenue has been deferred pending the completion of future performance obligations.

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

During 2019, our cash provided by operating activities was positively impacted by the proceeds from the sale of NGL and crude oil inventory that we held and also by the lower weighted average price of NGL inventory compared to prior year amounts.

Investing Activities

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Year Ended December 31,

2021 2020 2019

Investment capital (1) (2) (3)

$ 237 $ 921 $ 1,340

Maintenance capital (1) (3)

Acquisition capital (2) (4)

$ 437 $ 1,447 $ 1,677

(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) Includes contributions to unconsolidated entities, accounted for under the equity method of accounting, related to investment capital projects by such entities.

(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.

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

Acquisition capital for 2020 primarily includes consideration paid in connection with the acquisition of Felix Midstream LLC, a crude oil gathering system located in the Delaware Basin.

Investment Capital Projects

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The following table summarizes our investment in capital projects (in millions):

Index to Financial Statements

Year Ended December 31,

Projects 2022 2021

Permian Basin Takeaway Pipeline Projects (1)

$ 75 $ 292 $ 440

Complementary Permian Basin Projects (1)

Long-Haul Pipeline Projects (Non-Permian) 12 195 98

Permian Basin Takeaway Pipeline Projects (2)

Selected Facilities/Downstream Projects (3)

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Total $ 334 $ 237

(1) Represents pipeline projects with takeaway capacity out of the Permian Basin, including (i) our 16% interest in Wink to Webster Pipeline and (ii) our 65% interest in the Cactus II Pipeline.

Index to Financial Statements

(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.

(3) Includes projects at our St.

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Projected 2023 Capital Expenditures.

Total investment capital for the year ending December 31, 2022 is projected to be approximately $330 million ($275 million net to our interest).

Total investment capital for the year ending December 31, 2023 is currently projected to be approximately $420 million ($325 million net to our interest).

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

Additionally, maintenance capital for 2022 is projected to be $220 million ($210 million net to our interest).

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

We expect to fund our 2023 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.

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

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

Year Ended December 31,

2021 2020 2019

Proceeds from divestitures (1)

$ 875 $ 451 $ 205

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

(2) Amounts for 2020 include proceeds from a multi-year supply agreement related to the sale of certain NGL terminals in April 2020.

Amounts for 2019 include proceeds associated with the formation of Red River Pipeline Company LLC in May 2019.

See Note 7 and Note 12 to our Consolidated Financial Statements for additional information.

Ongoing Activities Related to Strategic Transactions

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Accordingly, we can give no assurance that our current or future efforts with respect to any such transactions will be successful, and we can provide no assurance that our financial expectations with respect to such transactions will ultimately be realized.

“Risk Factors—Risks Related to PAA’s Business—Divestitures and acquisitions involve risks that may adversely affect PAA’s business.”

Index to Financial Statements

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

Financing Activities

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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, 2020, we had net borrowings under the PAA credit facilities and commercial paper program of $296 million.

The net borrowings resulted primarily from borrowings during the period related to funding needs for inventory purchases and general partnership purposes.

During the year ended December 31, 2019, we had net borrowings under the PAA credit facilities and commercial paper program of $418 million.

The net borrowings resulted primarily from borrowings during the period related to funding needs for 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.

Issuances of PAA Senior Notes.

PAA did not issue any senior unsecured notes during 2021.During 2020 and 2019, PAA issued senior unsecured notes as summarized in the table below (in millions):

Year Description Maturity Face Value Gross

2020 3.80% Senior Notes issued at 99.794% of face value September 2030 $ 750 $ 748 $ 742 (3)

2019 3.55% Senior Notes issued at 99.801% of face value December 2029 $ 1,000 $ 998 $ 989 (4)

(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) PAA used the net proceeds from the offering to repay the principal amounts of its 5.00% senior notes due February 2021.

(4) PAA used the net proceeds from the offering to partially repay the principal amounts of its 2.60% senior notes due December 2019 and 5.75% senior notes due January 2020 and for general partnership purposes.

Repayments of PAA Senior Notes.

PAA did not repay any senior unsecured notes during 2021.During 2020 and 2019, PAA repaid the following senior unsecured notes in full (in millions):

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

Year Description Repayment Date

2020 $600 million 5.00% Senior Notes due February 2021 November 2020 (1)

2019 $500 million 2.60% Senior Notes due December 2019 November 2019 (2)

2019 $500 million 5.75% Senior Notes due January 2020 December 2019 (2)

Index to Financial Statements

(1) PAA repaid these senior notes with proceeds from its 3.80% senior notes issued in June 2020 and cash on hand.

(2) PAA repaid these senior notes with proceeds from its 3.55% senior notes issued in September 2019 and cash on hand.

Additionally, during the year ended December 31, 2020, PAA repurchased $17 million of its outstanding senior notes on the open market and recognized a gain of $3 million on these transactions.

In January 2022, PAA provided notice of its intention to redeem its 3.65% senior notes due June 2022 early, on March 1, 2022.

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

PAGP Registration Statements.

We have filed with the SEC a shelf registration statement that, subject to effectiveness at the time of use, allows us to issue up to an aggregate of $939 million of equity securities (“PAGP Traditional Shelf”).

We have filed with the SEC a shelf registration statement that, subject to effectiveness at the time of use, allows us to issue up to a specified amount of equity securities (“PAGP Traditional Shelf”).

At December 31, 2022, we had approximately $939 million of unsold securities available under the PAGP Traditional Shelf.

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PAA also has access to a universal shelf registration statement (“PAA WKSI Shelf”), which provides it with the ability to offer and sell an unlimited amount of debt and equity securities, subject to market conditions and capital needs.

The offerings of PAA’s $750 million, 3.80% senior notes in June 2020 and $1.0 billion, 3.55% senior notes in September 2019 were conducted under the PAA WKSI Shelf.

Common Equity Repurchase Program

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

PAA repurchased 18.1 million and 6.2 million common units under the Program through open market purchases that settled during the years ended December 31, 2021 and 2020, respectively, for a total purchase price of $178 million and $50 million respectively, including commissions and fees.

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.

The remaining available capacity under the Program as of December 31, 2022 was $198 million.

Index to Financial Statements

Distributions to Our Class A Shareholders

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Available cash is generally defined as all of our cash and cash equivalents on hand at the end of each quarter less reserves established in the discretion of our general partner for future requirements.

Our levels of financial reserves are established by our general partner and include reserves for the proper conduct of our business (including future capital expenditures and anticipated credit needs), compliance with legal or contractual obligations and funding of future distributions to our shareholders.

Our levels of financial reserves are established by our general partner and include reserves for, among other things, the proper conduct of our business (including future capital expenditures and anticipated credit needs), compliance with legal or contractual obligations and funding of future distributions to our shareholders.

“Market for Registrant’s Shares, Related Shareholder Matters and Issuer Purchases of Equity Securities—Cash Distribution Policy” for additional discussion regarding distributions.

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See Note 12 to our Consolidated Financial Statements for details of distributions paid during the three years ended December 31, 2022.

Index to Financial Statements

Distributions to Noncontrolling Interests

Distributions to noncontrolling interests represent amounts paid on interests in consolidated entities that are not owned by us.

As of December 31, 2021, noncontrolling interests in our subsidiaries consisted of (i) limited partner interests in PAA including a 69% interest in PAA’s common units and PAA’s Series A preferred units combined and 100% of PAA’s Series B preferred units, (ii) an approximate 19% limited partner interest in AAP, (iii) a 35% interest in the Permian JV and (iv) a 33% interest in Red River Pipeline LLC.

As of December 31, 2022, noncontrolling interests in our subsidiaries consisted of (i) limited partner interests in PAA including a 69% interest in PAA’s common units and PAA’s Series A preferred units combined and 100% of PAA’s Series B preferred units, (ii) an approximate 19% limited partner interest in AAP, (iii) a 35% interest in the Permian JV, (iv) a 30% interest in Cactus II and (v) a 33% interest in Red River.

See Note 12 to our Consolidated Financial Statements for details of distributions paid to noncontrolling interests during the three years ended December 31, 2022.

The initial distribution from the Permian JV of approximately $155 million was paid during the first quarter of 2022, with 65% of the distribution paid to PAA and 35% to noncontrolling interests.

Subsequent distributions will be allocated based on a modified sharing arrangement.

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

Distributions to PAA’s Series A preferred unitholders.

Holders of PAA’s Series A preferred units are entitled to receive quarterly distributions, subject to customary anti-dilution adjustments, of $0.525 per unit ($2.10 per unit annualized).

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

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.

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

See Note 12 to our Consolidated Financial Statements for further discussion of PAA’s Series B preferred units, including distribution rates and payment dates after November 15, 2022.

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 to PAA’s common unitholders.

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See Note 11 to our Consolidated Financial Statements for information regarding our debt obligations and Note 19 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, 2022 (in millions):

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We have invested in entities that are not consolidated in our financial statements.

Certain of these entities are borrowers under credit facilities.

We are neither a co-borrower nor a guarantor under these credit facilities.

None of these entities had debt outstanding as of December 31, 2022.

We may elect at any time to make additional capital contributions to any of these entities.

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BridgeTex Pipeline Company, LLC Crude Oil Pipeline 20% $ 792 $ 26

Cactus II Pipeline LLC Crude Oil Pipeline (1)

65% $ 1,129 $ 45 $ —

Capline Pipeline Company LLC Crude Oil Pipeline 54% $ 1,268 $ 33

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These areas are key components of our results of operations and are based on complex rules which require us to make judgments and estimates.

Therefore, we consider these to be our critical accounting policies and estimates, which are discussed further as follows.

Therefore, we consider these to be our critical accounting policies and estimates, which are discussed below.

For further information on all of our significant accounting policies, see Note 2 to 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 November 2022, we and Enbridge Inc.

(“Enbridge”) purchased Western Midstream Partners, LP (“WES”)’s 15% interest in Cactus II Pipeline, LLC (“Cactus II”) for an aggregate amount of $265 million.

Enbridge acquired 10% and we acquired 5% of Cactus II, with each paying a proportionate share of the purchase price.

We and Enbridge are now the sole owners of Cactus II, with 70% and 30% respective ownership interests.

We previously accounted for our 65% interest in Cactus II as an equity method investment.

In addition to the change in ownership, there were changes in governance which led to a change in control.

We now control Cactus II and reflect Cactus II as a consolidated subsidiary in our Consolidated Financial Statements, with Enbridge’s 30% interest reflected as a noncontrolling interest.

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.

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We reflect estimates for these items based on our internal records and information from third parties.

We have commodity derivatives, interest rate derivatives and foreign currency derivatives that are accounted for as assets and liabilities at fair value on our Consolidated Balance Sheets.

We have commodity derivatives and interest rate derivatives that are accounted for as assets and liabilities at fair value on our Consolidated Balance Sheets.

The valuations of our derivatives that are exchange traded are based on market prices on the applicable exchange on the last day of the period.

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

We also have embedded derivatives that are recorded at fair value on our Consolidated Balance Sheets.

These embedded derivatives are valued using models that contain inputs, some of which involve management judgment.

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 13 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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Property and Equipment, Depreciation and Amortization Expense and Asset Retirement Obligations.

We compute depreciation and amortization using the straight-line method based on estimated useful lives.

We compute depreciation and amortization based on estimated useful lives.

These estimates are based on various factors including condition, manufacturing specifications, technological advances and historical data concerning useful lives of similar assets.

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Uncertainties that impact these estimates include the costs associated with these activities and the timing of incurring such costs.

See Note 6 and Note 10 to our Consolidated Financial Statements for additional information on our property and equipment and depreciation and amortization expense.

A hypothetical variance of 5% in our aggregate estimate for the retirement obligations discussed above would have an impact on earnings of up to approximately $6 million.

Although the resolution of these uncertainties 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.

See Note 6 and Note 10 to our Consolidated Financial Statements for additional information on our property and equipment, intangible assets and depreciation and amortization expense.

See Note 2 to our Consolidated Financial Statements for additional information on our asset retirement obligations.

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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 determining the existence of an other-than-temporary impairment of carrying value, we make a number of subjective assumptions as to:

Index to Financial Statements

• whether there is an event or circumstance that may be indicative of a decline in value of the investment;

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Intangible assets with finite lives are amortized over their estimated useful life as determined by management.

Impairment testing entails estimating future net cash flows relating to the business, based on management’s estimate of future revenues, future cash flows and market conditions including pricing, demand, competition, operating costs and other factors.

Impairment testing entails estimating future net cash flows relating to the business, based on the grouping of assets and management’s estimate of future revenues, future cash flows and market conditions including pricing, demand, competition, operating costs and other factors.

Uncertainties associated with these estimates include changes in production decline rates, production interruptions, fluctuations in refinery capacity or product slates, economic obsolescence factors in the area and potential future sources of cash flow.

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Changes in assumptions made as to the timing of a sale can materially impact net realizable value.

During the years ended December 31, 2020 and 2019, we recorded charges of $233 million and $11 million, respectively, related to the valuation adjustment of our crude oil inventory due to declines in prices.

During the years ended December 31, 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.

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 $740 million, which includes actual and projected emergency response and clean-up costs, natural resource damage assessments, fines and penalties payable pursuant to the Consent Decree, certain third-party claims settlements, 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, 2022, 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.

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.

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

See Note 19 to our Consolidated Financial Statements for further discussion regarding the Line 901 incident and our related insurance receivable.

Recent Accounting Pronouncements

See Note 2 to our Consolidated Financial Statements for information regarding the effect of recent accounting pronouncements on our Consolidated Financial Statements.

Index to Financial Statements

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