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Item 7. Management’s Discussion and Analysis

2022-03-01 compared with 2021-03-01 · 445 added, 549 removed, 345 unchanged (74% of the section changed)

4 unchanged sentences

• Executive Summary

• Critical Accounting Policies and Estimates

• Recent Accounting Pronouncements

• Results of Operations

• Liquidity and Capital Resources

A comparative discussion of our 2019 to 2018 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, 2019 filed with the SEC on February 27, 2020.

• Critical Accounting Policies and Estimates

• Recent Accounting Pronouncements

Executive Summary

7 unchanged sentences

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

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

PAA’s business activities are conducted through three operating segments:

Transportation, Facilities and Supply and Logistics.

See “—Results of Operations—Analysis of Operating Segments” for further discussion.

Recent Events and Outlook

During the first quarter of 2020, COVID-19 escalated into a global pandemic, which led to widespread shelter-in-place or similar requirements throughout North America and across the world, resulting in significantly reduced energy demand.

As a result, North American producers responded aggressively by shutting in significant levels of production early in the second quarter, which mitigated the pace of crude oil inventory builds and the risk of testing storage maximums.

Subsequently, United States refinery utilization increased, the previously steep contango market structure tempered, and crude oil prices improved to more constructive levels.

Over the course of the second half of the year, the more constructive price environment allowed oil and gas producers to return to production wells that were previously shut-in, resume completion activities and begin to increase drilling activities during the third quarter at a level that is lower than pre-pandemic, but likely at a level that is sufficient to offset natural declines.

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

Index to Financial Statements

While prices have rebounded to levels that are near pre-pandemic levels, drilling activity is at a fraction of pre-pandemic levels as evidenced by the Lower 48 rig count, which is approximately 40% of peak levels reached in 2020 pre-COVID-19.

Many oil and gas producers in the United States have publicly stated their intention to reduce capital investment in oil and gas drilling activities in 2021 as they strive to improve their financial metrics and increase returns to shareholders.

Accordingly, we expect oil and gas drilling activities to continue to be lower than pre-pandemic levels which in turn will slow the growth in oil production, relative to pre-pandemic expectations of production growth.

We expect that the combination of a muted growth in production, with excess pipeline capacity in most of our operating areas will have a negative impact on our business relative to pre-pandemic levels, with the impacts in 2021 being more pronounced than in 2020.

Similar to the actions taken by oil and gas producers, we have implemented a number of initiatives, as described below, to ensure that we are positioned to manage through the current challenging market environment.

Longer term, we expect global demand for hydrocarbons will recover, which should drive higher production levels in key onshore shale basins, which should support growing demand for our assets.

Also see Items 1.

“Business and Properties—Global Petroleum Market Overview and Fundamental Themes” for additional information.

Our response to the challenging near-term market conditions has been to focus on measures to strengthen our balance sheet, liquidity and long-term financial flexibility.

These actions include significantly reducing our capital program, reducing the amount of our common equity distributions, progressing asset sales, and reducing costs, while remaining focused on operating safely and responsibly.

Specifically, since April, we have reduced our 2020/2021 capital program by $950 million, or 41%, and have decreased PAA’s common unit distributions and our Class A share distributions by 50% versus the distributions paid in February 2020, which reflects a reduction of $525 million on an annualized basis.

We have also completed approximately $450 million of asset sales.

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.

The chart below depicts the relationship between global supply of crude oil and other petroleum liquids and demand since the beginning of 2017 and the U.S.

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

World Liquid Fuels Production and Consumption Balance (1)

(in millions of barrels per day)

(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.

This includes tight global markets and continued commodity price volatility.

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

production growth in the coming years.

It is against this macro backdrop that we expect to generate significant positive free cash flow on a multi-year basis, supported by our existing 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 have been necessary to deal with risks associated with the COVID-19 pandemic, we have not experienced any material constraints in our ability to continue our essential business functions and have not incurred any significant additional operating costs as a result of the pandemic.

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.

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

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 the second, third and fourth quarters of 2020 for subsidies totaling approximately $23 million.

The impact of such subsidies is included in the line items “Field operating costs” and “Segment general and administrative expenses” of the applicable segments.

See “—Results of Operations—Analysis of Operating Segments” for further discussion.

Overview of Operating Results, Capital Investments and Other Significant Activities

The macroeconomic and industry specific challenges discussed above have resulted in a number of impairment charges recognized during 2020 as discussed further below.

See “—Liquidity and Capital Resources” for additional discussion of the expected and potential impact of COVID-19 and related market conditions on our business.

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

The net loss for the period was driven by goodwill impairment losses of $2.515 billion and was also impacted by non-cash impairment charges of approximately $914 million 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.

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

Index to Financial Statements

Our results for the comparative period were also impacted by:

• Less favorable results from our Supply and Logistics segment due to less favorable crude oil differentials, lower NGL margins and the unfavorable impact of the mark-to-market of certain derivative instruments, resulting in higher losses recognized in 2020 compared to 2019, partially offset by the favorable impact of contango market conditions during 2020;

• Less favorable results from our Transportation segment driven by lower volumes from shut-ins of crude oil production, reduced drilling and completion activity and compressed regional basis differentials, a portion of which are covered by minimum volume commitments that will be made up or paid for in future periods, and lower pipeline loss allowance revenue in 2020 due to lower prices and volumes, partially offset by lower field operating costs;

• Higher depreciation and amortization expense in the 2020 period primarily due to additional depreciation expense associated with acquired assets, the completion of various investment capital projects and a reduction in the useful lives of certain assets;

• A gain of $21 million recognized in the current period related to the sale of a portion of our interest in Saddlehorn Pipeline Company, LLC in February 2020, compared to a non-cash gain of $269 million recognized in the 2019 period 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;

partially offset by

• Favorable results from our Facilities segment primarily due to lower field operating costs;

• The favorable impact on income tax expense of (i) lower income attributable to PAGP as a result of lower earnings at PAA and (ii) lower taxable earnings and lower year-over-year income as impacted by fluctuations in the derivative mark-to-market valuations in our Canadian operations.

See further discussion of our operating results in the “—Results of Operations—Analysis of Operating Segments” and “—Other Income and Expenses” sections below.

We invested $921 million in midstream infrastructure projects during 2020, which primarily related to projects under development in the Permian Basin.

See “—Liquidity and Capital Resources—Investing Activities—Investment Capital Projects” for additional information.

Additionally, during the first quarter of 2020, we acquired $310 million of assets, which primarily included a crude oil gathering system located in the Delaware Basin.

We also paid approximately $863 million of cash distributions to our Class A Shareholders and noncontrolling interests during 2020.

In June 2020, PAA completed the issuance of $750 million, 3.80% senior notes due September 2030.

We used the net proceeds from this offering of $742 million, after deducting the underwriting discount and offering expenses, to repay the principal amounts of PAA’s 5.00% senior notes due February 2021 in November 2020.

See “—Liquidity and Capital Resources—Financing Activities—Senior Notes” for additional information.

During the fourth quarter of 2020, PAA repurchased 6.6 million common units for $53 million, which includes repurchases of 350,000 common units for $3 million that did not settle until January 2021.

See “—Liquidity and Capital Resources—Financing Activities—Common Equity Repurchase Program” for additional information.

Critical Accounting Policies and Estimates

The preparation of financial statements in conformity with GAAP and rules and regulations of the SEC requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities, as well as the disclosure of contingent assets and liabilities, at the date of the financial statements.

Such estimates and assumptions also affect the reported amounts of revenues and expenses during the reporting period.

Although we believe these estimates are reasonable, actual results could differ from these estimates.

On a regular basis, we evaluate our assumptions, judgments and estimates.

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

Index to Financial Statements

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

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.

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

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

In accordance with Financial Accounting Standards Board (“FASB”) guidance regarding business combinations, with each acquisition, we allocate the cost of the acquired entity to the assets and liabilities assumed based on their estimated fair values at the date of acquisition.

If the initial accounting for the business combination is incomplete when the combination occurs, an estimate will be recorded.

We also expense the transaction costs as incurred in connection with each acquisition, except for acquisitions of equity method investments.

In addition, we are required to recognize intangible assets separately from goodwill.

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.

Impairment Assessments of Goodwill and Intangible Assets.

Goodwill and intangible assets with indefinite lives are not amortized but are instead periodically assessed for impairment.

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

See Note 8 and Note 10 to our Consolidated Financial Statements for further discussion of goodwill and intangible assets.

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.

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.

In addition, changes in our weighted average cost of capital from our estimates could have a significant impact on fair value.

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

Resolutions of these uncertainties have resulted, and in the future may result, in impairments that impact our results of operations and financial condition.

Fair Value of Derivatives.

The fair value of a derivative at a particular period end does not reflect the end results of a particular transaction, and will most likely not reflect the gain or loss at the conclusion of a transaction.

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.

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.

For our derivatives that are not exchange traded, the estimates we use are based on indicative broker quotations or an internal valuation model.

Our valuation models utilize market observable inputs such as price, volatility, correlation and other factors and may not be reflective of the price at which they can be settled due to the lack of a liquid market.

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.

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.

We record accruals or liabilities for, among other things, environmental remediation, potential legal claims or settlements and fees for legal services associated with loss contingencies, and bonuses.

Accruals are made when our assessment indicates that it is probable that a liability has occurred and the amount of liability can be reasonably estimated.

Our estimates are based on all known facts at the time and our assessment of the ultimate outcome.

Among the many uncertainties that impact our estimates are the necessary regulatory approvals for, and potential modification of, our environmental remediation plans, the limited amount of data available upon initial assessment of the impact of soil or water contamination, changes in costs associated with environmental remediation services and equipment, the duration of the natural resource damage assessment and the ultimate amount of damages determined, the determination and calculation of fines and penalties, the possibility of existing legal claims giving rise to additional claims and the nature, extent and cost of legal services that will be required in connection with lawsuits, claims and other matters.

Our estimates for contingent liability accruals are increased or decreased as additional information is obtained or resolution is achieved.

A hypothetical variance of 5% in our aggregate estimate for the accruals and contingent liabilities discussed above would have an impact on earnings of up to approximately $19 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.

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.

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

Uncertainties that impact these estimates include changes in laws and regulations relating to restoration and abandonment requirements, economic conditions and supply and demand in the area.

When assets are put into service, we make estimates with respect to useful lives and salvage values that we believe are reasonable.

However, subsequent events could cause us to change our estimates, thus impacting the future calculation of depreciation and amortization.

We record retirement obligations associated with tangible long-lived assets based on estimates related to the costs associated with cleaning, purging and, in some cases, completely removing the assets and returning the land to its original state.

In addition, our estimates include a determination of the settlement date or dates for the potential obligation, which may or may not be determinable.

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

Impairment Assessments of Property and Equipment and Investments in Unconsolidated Entities.

We periodically evaluate property and equipment for impairment when events or circumstances indicate that the carrying value of these assets may not be recoverable.

Any evaluation is highly dependent on the underlying assumptions of related cash flows.

We consider the fair value estimate used to calculate impairment of property and equipment a critical accounting estimate.

In determining the existence of an impairment of carrying value, we make a number of subjective assumptions as to:

• whether there is an event or circumstance that may be indicative of an impairment;

• the grouping of assets;

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

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

• if an impairment exists, the fair value of the asset or asset group.

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

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

Examples of such events or circumstances include continuing operating losses of the entity and/or long-term negative changes in the entity’s core business.

When it is determined that an indicated impairment is other than temporary, a charge is recognized for the difference between the investment’s carrying amount and its estimated fair value.

We consider the fair value estimate used to calculate the impairment of investments in unconsolidated entities a critical accounting estimate.

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

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

• whether the decline in value is other than temporary;

• the fair value of the investment.

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.

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.

Index to Financial Statements

A change in our outlook or use could result in impairments that may be material to our results of operations or financial condition.

See “—Executive Summary— Recent Events and Outlook” and Note 6 and Note 9 to our Consolidated Financial Statements for additional information.

Inventory Valuations.

Inventory, including long-term inventory, primarily consists of crude oil and NGL and is valued at the lower of cost or net realizable value, with cost determined using an average cost method within specific inventory pools.

At the end of each reporting period, we assess the carrying value of our inventory and use estimates and judgment when making any adjustments necessary to reduce the carrying value to net realizable value.

Among the uncertainties that impact our estimates are the applicable quality and location differentials to include in our net realizable value analysis.

Additionally, we estimate the upcoming liquidation timing of the inventory.

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

During the years ended December 31, 2020, 2019 and 2018, we recorded charges of $233 million, $11 million and $8 million, respectively, 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.

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.

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, Variance

2020 2019 $ %

Transportation Segment Adjusted EBITDA (1)

$ 1,616 $ 1,722 $ (106) (6) %

Facilities Segment Adjusted EBITDA (1)

731 705 26 4 %

Supply and Logistics Segment Adjusted EBITDA (1)

210 803 (593) (74) %

Depreciation and amortization of unconsolidated entities (73) (62) (11) (18) %

Selected items impacting comparability - Segment Adjusted EBITDA (617) (163) (454) **

Unallocated general and administrative expenses

Year Ended December 31, 2021-2020 2020-2019

2021 2020 2019 $ % $ %

Product sales revenues $ 40,883 $ 22,058 $ 32,272 $ 18,825 85 % $ (10,214) (32) %

Services revenues 1,195 1,232 1,397 (37) (3) % (165) (12) %

Purchases and related costs (38,504) (20,431) (29,452) (18,073) (88) % 9,021 31 %

Field operating costs (1,065) (1,076) (1,303) 11 1 % 227 17 %

General and administrative expenses (298) (276) (302) (22) (8) % 26 9 %

Depreciation and amortization (777) (656) (604) (121) (18) % (52) (9) %

1 unchanged sentence

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

Equity earnings in unconsolidated entities 274 355 388 (81) (23) % (33) (9) %

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

15 unchanged sentences

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

Revenues and Purchases

Fluctuations in our consolidated revenues and purchases and related costs are primarily associated with our merchant activities and generally explained in large part by changes in commodity prices.

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

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

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

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

Index to Financial Statements

(1) Segment Adjusted EBITDA is the measure of segment performance that is utilized by our Chief Operating Decision Maker (“CODM”) to assess performance and allocate resources among our operating segments.

This measure is adjusted for certain items, including those that our CODM believes impact comparability of results across periods.

See Note 21 to our Consolidated Financial Statements for additional discussion of such adjustments.

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):

Crude Oil Price

During the Year Ended December 31, Low High Average

2021 $ 48 $ 85 $ 68

2020 $ (38) $ 63 $ 39

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.

Field Operating Costs

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

General and Administrative Expenses

The increase in general and administrative expenses for the 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.

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.

See Note 6 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.

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

Interest expense is primarily impacted by:

• our weighted average debt balances;

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

• market interest rates and our interest rate hedging activities;

• interest capitalized on capital projects.

Index to Financial Statements

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

Weighted Average

Interest Rate (1)

Interest expense for the year ended December 31, 2019 $ 425 2.2 % 4.4 %

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)

Impact of lower capitalized interest 6

Interest expense for the year ended December 31, 2021 $ 425 0.1 % 4.2 %

(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):

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

(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

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 measure used by management is earnings before interest, taxes, depreciation and amortization (including our proportionate share of depreciation and amortization 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”).

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.

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

Adjusted EBITDA is reconciled to Net Income/(Loss), the most directly comparable measure 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.

Management believes that the presentation of such additional financial measure provides useful information to investors regarding our performance and results of operations because this measure, 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 measurements that investors, rating agencies and debt holders have indicated are useful in assessing us and our results of operations.

This non-GAAP measure 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 business outlook and/or (v) other items that we believe should be excluded in understanding our core operating performance.

This measure 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.

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.

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 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.

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 our non-GAAP financial performance measure Adjusted EBITDA from Net Income/(Loss) (in millions):

Year Ended December 31, Variance

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

2021 2020 2019 $ % $ %

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

Add/(Subtract):

Interest expense, net 425 436 425 (11) (3) % 11 3 %

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123 73 62 50 68 % 11 18 %

Selected Items Impacting Comparability:

Losses from derivative activities net of inventory valuation adjustments (2)

Unallocated general and administrative expenses (2)

6 5 5 1 20 % — — %

Selected Items Impacting Comparability:

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

Long-term inventory costing adjustments (94) 44 (20) (138) ** 64 **

44 (20) 64 **

Deficiencies under minimum volume commitments, net (7) 74 (18) (81) ** 92 **

74 (18) 92 **

Equity-indexed compensation expense 19 19 17 — ** 2 **

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

(3) 14 (17) **

Line 901 incident 15 — 10 15 ** (10) **

Significant acquisition-related expenses (8)

Significant transaction-related expenses 16 3 — 13 ** 3 **

Selected Items Impacting Comparability - Segment Adjusted EBITDA (3)

(326) 617 163 (943) ** 454 **

Gains from derivative activities (4)

3 unchanged sentences

Net gain on early repayment of senior notes (6)

— (3) — 3 ** (3) **

Selected Items Impacting Comparability - Adjusted EBITDA (7)

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$ 2,290 $ 2,560 $ 3,237 $ (270) (11) % $ (677) (21) %

Adjusted EBITDA attributable to noncontrolling interests in consolidated joint ventures (8)

(94) (14) (10) (80) ** (4) (40) %

Adjusted EBITDA attributable to PAA $ 2,196 $ 2,546 $ 3,227 $ (350) (14) % $ (681) (21) %

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

(1) Over the past several years, we have increased our participation in strategic pipeline joint ventures accounted for under the equity method of accounting.

We exclude our proportionate share of the depreciation and amortization expense of such unconsolidated entities when reviewing Adjusted EBITDA, similar to our consolidated assets.

(2) We use derivative instruments for risk management purposes, and our related processes include specific identification of hedging instruments to an underlying hedged transaction.

Although we identify an underlying transaction for each derivative instrument we enter into, there may not be an accounting hedge relationship between the instrument and the underlying transaction.

In the course of evaluating our results of operations, we identify the earnings that were recognized during the period related to derivative instruments for which the identified underlying transaction does not occur in the current period and exclude the related gains and losses in determining Adjusted EBITDA.

In addition, we exclude gains and losses on derivatives that are related to investing activities, such as the purchase of linefill.

We also exclude the impact of corresponding inventory valuation adjustments, as applicable.

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

(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.

(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.

(3) For a more detailed discussion of these selected items impacting comparability, see the footnotes to the Segment Adjusted EBITDA Reconciliation table in Note 20 to our Consolidated Financial Statements.

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

The associated gains and losses are not

Index to Financial Statements

(3) We carry crude oil and NGL inventory that is comprised of minimum working inventory requirements in third-party assets and other working inventory that is needed for our commercial operations.

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

Therefore, we classify this inventory as long-term on our balance sheet and do not hedge the inventory with derivative instruments (similar to linefill in our own assets).

We treat the impact of changes in the average cost of the long-term inventory (that result from fluctuations in market prices) and write-downs of such inventory that result from price declines as a selected item impacting comparability.

See Note 5 to our Consolidated Financial Statements for additional inventory disclosures.

(4) We, and certain of our equity method investments, have certain agreements that require counterparties to deliver, transport or throughput a minimum volume over an agreed upon period.

Substantially all of such agreements were entered into with counterparties to economically support the return on our capital expenditure necessary to construct the related asset.

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

We record a receivable from the counterparty in the period that services are provided or when the transaction occurs, including amounts for deficiency obligations from counterparties associated with minimum volume commitments.

If a counterparty has a make-up right associated with a deficiency, we defer the revenue attributable to the counterparty’s make-up right and subsequently recognize the revenue at the earlier of when the deficiency volume is delivered or shipped, when the make-up right expires or when it is determined that the counterparty’s ability to utilize the make-up right is remote.

We include the impact of amounts billed to counterparties for their deficiency obligation, net of applicable amounts subsequently recognized into revenue, as a selected item impacting comparability.

We believe the inclusion of the contractually committed revenues associated with that period is meaningful to investors as the related asset has been constructed, is standing ready to provide the committed service and the fixed operating costs are included in the current period results.

(5) Our total equity-indexed compensation expense includes expense associated with awards that will or may be settled in PAA common units and awards that will or may be settled in cash.

The awards that will or may be settled in PAA common units are included in PAA’s diluted net income per unit calculation when the applicable performance criteria have been met.

We consider the compensation expense associated with these awards as a selected item impacting comparability as the dilutive impact of the outstanding awards is included in PAA’s diluted net income per unit calculation, as applicable, and the majority of the awards are expected to be settled in PAA common units.

The portion of compensation expense associated with awards that are certain to be settled in cash is not considered a selected item impacting comparability.

See Note 18 to our Consolidated Financial Statements for a discussion regarding our equity-indexed compensation plans.

(6) During the periods presented, there were fluctuations in the value of the Canadian dollar (“CAD”) to the U.S.

dollar (“USD”), resulting in the realization of foreign exchange gains and losses on the settlement of foreign currency transactions as well as the revaluation of monetary assets and liabilities denominated in a foreign currency.

These gains and losses are not integral to our core operating performance and were thus classified as a selected item impacting comparability.

See Note 13 to our Consolidated Financial Statements for discussion regarding our currency exchange rate risk hedging activities.

(7) Includes costs recognized during the period related to the Line 901 incident that occurred in May 2015, net of amounts we believe are probable of recovery from insurance.

See Note 19 to our Consolidated Financial Statements for additional information regarding the Line 901 incident.

(8) Includes acquisition-related expenses associated with the acquisition of Felix Midstream LLC (“Felix Midstream”) in February 2020.

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

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.

1 unchanged sentence

(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.

Index to Financial Statements

(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.

Analysis of Operating Segments

We manage our operations through three operating segments:

Transportation, Facilities and Supply and Logistics.

Our CODM (our Chief Executive Officer) evaluates segment performance based on a variety of measures including Segment Adjusted EBITDA, segment volumes, Segment Adjusted EBITDA per barrel 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 our proportionate share of the depreciation and amortization expense of unconsolidated entities, and further adjusted for 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.

We manage our operations through two operating segments:

Crude Oil and NGL.

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

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”).

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

Our segment analysis involves an element of judgment relating to the allocations between segments.

In connection with its operations, the Supply and Logistics segment secures transportation and facilities services from our other two segments as well as third-party service providers under month-to-month and multi-year arrangements.

Intersegment transportation service rates are conducted at posted tariff rates, rates similar to those charged to third parties or rates that we believe approximate market.

Facilities segment services are also obtained at rates generally consistent with rates charged to third parties for similar services.

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

Intersegment transactions are conducted at rates similar to those charged to third parties or rates that we believe approximate market.

Intersegment activities are eliminated in consolidation and we believe that the estimates with respect to these rates are reasonable.

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Index to Financial Statements

Transportation Segment

Our Transportation segment operations generally consist of fee-based activities associated with transporting crude oil and NGL on pipelines, gathering systems and trucks.

The Transportation segment generates revenue through a combination of tariffs, pipeline capacity agreements and other transportation fees.

Tariffs and other fees on our pipeline systems vary by receipt point and delivery point.

The segment results generated by our tariff and other fee-related activities depend on the volumes transported on the pipeline and the level of the tariff and other fees charged, as well as the fixed and variable field costs of operating the pipeline.

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

Crude Oil Segment

Our Crude Oil segment operations generally consist of gathering and transporting crude oil using pipelines, gathering systems, trucks and at times on barges or railcars, in addition to providing terminalling, storage and other facilities-related services utilizing our integrated assets across the United States and Canada.

Our 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 are subject to our risk management policies and may include the use of derivative instruments to hedge our exposure.

Our Crude Oil segment generates revenue through a combination of tariffs, pipeline capacity agreements and other transportation fees, month-to-month and multi-year storage and terminalling agreements and the sale of gathered and bulk-purchased crude oil.

Tariffs and other fees on our pipeline systems are typically based on volumes transported and vary by receipt point and delivery point.

Fees for our terminalling and storage services are based on capacity leases and throughput volumes.

Generally, results from our merchant activities are impacted by (i) increases or decreases in our lease gathering crude oil purchases volumes and (ii) the overall strength, weakness and volatility of market conditions, including regional differentials and time spreads.

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

The segment results also include the direct fixed and variable field costs of operating the crude oil assets, as well as an allocation of indirect operating costs.

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

Operating Results (1)

(in millions, except per barrel data)

Year Ended December 31, Variance

Year Ended December 31, 2021-2020 2020-2019

2021 2020 2019 $ % $ %

7 unchanged sentences

Depreciation and amortization of unconsolidated entities 123 73 62 50 68 % 11 18 %

Losses from derivative activities, net of inventory valuation adjustments 1 — 1 **

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

Long-term inventory costing adjustments (67) 43 (35) (110) ** 78 **

Deficiencies under minimum volume commitments, net (7) 74 (18) (81) ** 92 **

Equity-indexed compensation expense 19 19 17 — ** 2 **

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

Line 901 incident 15 — 10 15 ** (10) **

Significant acquisition-related expenses 3 — 3 **

Significant transaction-related expenses 16 3 — 13 ** 3 **

Adjusted EBITDA attributable to noncontrolling interests in consolidated joint ventures (94) (14) (10) (80) ** (4) **

Segment Adjusted EBITDA $ 1,909 $ 2,216 $ 2,753 $ (307) (14) % $ (537) (20) %

Maintenance capital $ 100 $ 171 $ 248 $ (71) (42) % $ (77) (31) %

Segment Adjusted EBITDA per barrel $ 0.70 $ 0.68 $ 0.02 3 %

Average Daily Volumes

(in thousands of barrels per day) (4)

Year Ended December 31, Variance

2020 2019 Volumes %

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 (by region):

Crude oil pipelines tariff volumes (by region):

Permian Basin (5)

2 unchanged sentences

326 380 446 (54) (14) % (66) (15) %

Mid-Continent (5)

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

4 unchanged sentences

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

Crude oil pipelines 6,082 6,613 (531) (8) %

NGL pipelines 184 192 (8) (4) %

Tariff activities total volumes 6,266 6,805 (539) (8) %

Trucking volumes 74 88 (14) (16) %

Transportation segment total volumes 6,340 6,893 (553) (8) %

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

Commercial crude oil storage capacity (5)(6)

73 79 76 (6) (8) % 3 4 %

Crude oil lease gathering purchases (4) (7)

1,330 1,174 1,162 156 13 % 12 1 %

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

Index to Financial Statements

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

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See Note 20 to our Consolidated Financial Statements for additional discussion of such adjustments.

(4) Average daily volumes are calculated as the total volumes (attributable to our interest) for the year divided by the number of days in the year.

(5) Region includes volumes (attributable to our interest) from pipelines owned by unconsolidated entities.

The following is a discussion of items impacting Transportation segment operating results for the periods indicated.

Revenues, Purchases and Related Costs, Equity Earnings in Unconsolidated Entities and Volumes.

The following table presents variances in revenues, purchases and related costs and equity earnings in unconsolidated entities by region:

Favorable/(Unfavorable) Variance

(in millions) Revenues Purchases and Related Costs Equity Earnings

Crude oil pipelines

Permian Basin region $ (104) $ (17) $ 31

South Texas / Eagle Ford region (12) — (26)

Central region (33) (2) (21)

Rocky Mountain region (5) — (24)

Canada region (26) — —

Other regions, NGL pipelines, trucking and pipeline loss allowance revenue (120) 34 2

Total variance $ (300) $ 15 $ (38)

(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.

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

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

(6) Average monthly capacity in millions of barrels per day calculated as total volumes for the 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.

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.

The destruction of demand for refined products, and therefore crude oil, caused by COVID-19 created a supply and demand imbalance in the crude oil markets for a portion of 2020 in all of our operating regions.

This imbalance pushed crude oil prices to historically low levels, including negative values for at least one day in April 2020.

In turn, these factors caused U.S.

and Canadian producers to respond by quickly curtailing their crude oil production as well as their drilling and completion activities.

These actions led to a decline of onshore, lower 48 U.S.

oil production by approximately 1.4 million barrels of crude oil per day between February and May of 2020, according to the information provided by the EIA, and adversely impacted transportation volumes on our pipelines.

• Permian Basin region.

Revenues, net of purchases and related costs, (“net revenues”) decreased by $121 million for the year ended December 31, 2020 compared to the year ended December 31, 2019.

This decrease was primarily due to lower long-haul pipeline movements to Cushing, Oklahoma and Corpus Christi, Texas due to compressed regional basis differentials, as well as lower volumes on our intra-basin pipelines that feed our long-haul pipelines, partially offset by increased volumes on our gathering pipelines, almost half of which was attributable to the Felix Midstream system we acquired in February 2020.

Some shippers on the long-haul pipelines to Cushing and Corpus Christi have under-delivered relative to their minimum volume commitments;

however, the earnings related to these volume shortfalls will not be 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.

The increase in equity earnings over the comparative period was primarily from our 65% interest in the Cactus II pipeline, which was placed in service in August 2019, partially offset by lower equity earnings from our 20% interest in the BridgeTex pipeline primarily due to lower volumes.

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.

• 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).

Index to Financial Statements

• South Texas / Eagle Ford region.

The decrease in revenues for the year ended December 31, 2020 compared to the year ended December 31, 2019 was due to lower volumes, primarily related to lower production.

Equity earnings from our 50% interest in the Eagle Ford pipeline decreased for the year ended December 31, 2020 compared to the year ended December 31, 2019 due to a combination of lower joint tariff volumes from the Permian Basin via our Cactus I pipeline, and to a lesser extent, lower regional receipts.

Similar to some shippers in the Permian Basin region, certain shippers on the Eagle Ford pipeline have under-delivered relative to their minimum volume commitments and the earnings related to these volume shortfalls will not be recognized until future periods.

Such deficiencies are reflected as an “Adjustment” in the table above as discussed further below under “— Adjustments:

Deficiencies under minimum volume commitments, net.

• Central region.

The decrease in net revenues for the year ended December 31, 2020 compared to the year ended December 31, 2019 was primarily due to a decrease in crude oil production in the region.

This is also a region with a meaningful amount of excess pipeline capacity, which exacerbates the impact to our assets in this region.

The decrease in equity earnings for the year ended December 31, 2020 compared to the year ended December 31, 2019 was primarily due to the impact of refinery downtime on certain of the demand pull pipelines out of Cushing, Oklahoma, in which we own a 50% interest.

• Rocky Mountain region.

Equity earnings decreased for the year ended December 31, 2020 compared to the year ended December 31, 2019 primarily due to a combination of (i) lower crude oil volumes, partially offset by higher NGL volumes, (ii) lower tariff rates due to the expiration of certain long-term contracts and (iii) the sale of 25% of our interest in Saddlehorn in February 2020.

• Canada region.

The decrease in revenues for the year ended December 31, 2020 compared to the year ended December 31, 2019 was primarily due to decreased crude oil production in the areas serviced by our pipelines.

• Other regions, NGL pipelines, trucking and pipeline loss allowance revenue.

The decrease in other net revenues for the year ended December 31, 2020 compared to the year ended December 31, 2019 was primarily due to lower pipeline loss allowance revenue due to a combination of both lower prices and volumes in 2020.

To a lesser extent, lower net revenues from our trucking activities due to less favorable market conditions in 2020 contributed to the decrease.

Additionally, volumes in our Gulf Coast region were impacted by a decrease in throughput on a lower tariff pipeline, which did not result in a significant impact on revenue.

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.

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.

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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.

For the year ended December 31, 2020, amounts billed to counterparties exceeded revenue recognized during the period that was previously deferred.

For the year ended December 31, 2019, the recognition of previously deferred revenue exceeded amounts billed to counterparties associated with deficiencies under minimum volume commitments.

Field Operating Costs.

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 activities, primarily due to timing changes, (iii) lower equity-based compensation costs on liability-classified awards (which are not included as an “Adjustment” in the table above) due to a decrease in our common unit price, (iv) reductions in compensation costs, primarily due to the benefit of wage subsidies received by our Canadian subsidiary 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.

Index to Financial Statements

Segment General and Administrative Expenses.

The decrease in segment general and administrative expenses for 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 are not included as an “Adjustment” in the table above), due to a decrease in our common unit price, (ii) decreased travel and entertainment costs and (iii) the benefit of wage subsidies received by our Canadian subsidiary.

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 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, 2020 compared to the year ended December 31, 2019 was due to timing changes, the completion of multi-year reliability improvement programs and application of updated regulatory guidance, among other factors.

Facilities Segment

Our Facilities segment operations generally consist of fee-based activities associated with providing storage, terminalling and throughput services primarily for crude oil, NGL and natural gas, as well as NGL fractionation and isomerization services and natural gas and condensate processing services.

The Facilities segment generates revenue through a combination of month-to-month and multi-year agreements.

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

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

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.

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

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

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

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, Variance

Year Ended December 31, 2021-2020 2020-2019

2021 2020 2019 $ % $ %

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(71) (66) (81) (5) (8) % 15 19 %

Equity earnings in unconsolidated entities 5 — 5 N/A

Adjustments (3) :

Depreciation and amortization of unconsolidated entities

Gains from derivative activities

(5) (13) 8 **

Deficiencies under minimum volume commitments, net

Equity-indexed compensation expense

Segment Adjusted EBITDA

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

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

Maintenance capital

Long-term inventory costing adjustments

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

Segment Adjusted EBITDA per barrel

Net (gain)/loss on foreign currency revaluation

(1) (1) 3 — ** (4) **

Year Ended December 31, Variance

2020 2019 Volumes %

Liquids storage (average monthly capacity in millions of barrels) (5)

Segment Adjusted EBITDA

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

Natural gas storage (average monthly working capacity in billions of cubic feet) 66 63 3 5 %

NGL fractionation (average volumes in thousands of barrels per day) 129 144 (15) (10) %

Facilities segment total volumes (average monthly volumes in millions of barrels) (6)

Maintenance capital

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

Year Ended December 31, 2021-2020 2020-2019

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

2021 2020 2019 Volumes % Volumes %

NGL fractionation 129 129 144 — — % (15) (10) %

NGL pipeline tariff 179 184 192 (5) (3) % (8) (4) %

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

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

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See Note 20 to our Consolidated Financial Statements for additional discussion of such adjustments.

(4) Average monthly volumes are calculated as total volumes for the year divided by the number of months in the year.

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

(6) Facilities segment total volumes are calculated as the sum of:

(i) liquids storage capacity;

(ii) natural gas storage working capacity divided by 6 to account for the 6:1 mcf of natural gas to crude Btu equivalent ratio and further divided by 1,000 to convert to monthly volumes in millions;

and (iii) NGL fractionation volumes multiplied by the number of days in the year and divided by the number of months in the year.

The following is a discussion of items impacting Facilities segment operating results.

Revenues, Purchases and Related Costs and Volumes.

Variances in revenues, purchases and related costs, and average monthly volumes were primarily driven by the following:

• Rail Terminals.

Revenues from our rail terminals decreased by $33 million for the year ended December 31, 2020 compared to the year ended December 31, 2019, primarily due to decreased activity at certain of our rail terminals resulting from less favorable market conditions, as well as lower volumes due to voluntary shut-ins and curtailments of crude oil production by producers.

• NGL Operations.

Revenues from our NGL operations decreased by $21 million for the year ended December 31, 2020 compared to the year ended December 31, 2019, primarily due to the sale of certain NGL terminals in the fourth quarter of 2019 and the second quarter of 2020, net unfavorable foreign exchange impacts of approximately $4 million and lower revenues from our NGL processing facilities.

Such unfavorable impacts were partially offset by the favorable impact of the receipt of a deficiency payment in 2020 of approximately $20 million upon the expiration of a multi-year contract.

• Natural Gas and Condensate Processing.

Net revenues from our U.S.

natural gas and condensate processing operations decreased by $11 million for the year ended December 31, 2020 compared to the year ended December 31, 2019 primarily due to the unfavorable impact of a $5 million payment to resolve a contractual dispute as well as a decrease in condensate processing volumes and rates.

• Crude Oil Storage.

Revenues from our crude oil storage operations increased by $33 million for the year ended December 31, 2020 compared to the year ended December 31, 2019, primarily due to the addition of an aggregate of approximately 3 million barrels of storage capacity at our Cushing, Oklahoma, St.

James, Louisiana and Midland, Texas terminals and increased activity at certain of our Mid-Continent terminals.

Additionally, the unfavorable impact on revenues from the sale of our Los Angeles Basin terminals in October 2020 was largely offset by increased spot activity at certain of these terminals during the first three quarters of 2020.

The increase in equity earnings over the comparative period was from our 50% interest in Eagle Ford Terminals, which owns a crude oil storage facility in Corpus Christi, Texas that was placed in service in September of 2019.

Field Operating Costs.

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) lower maintenance activities due to timing changes, (ii) reduced activity at our rail terminals and the divestiture of certain NGL terminals, (iii) reductions in compensation costs including the benefit of wage subsidies received by our Canadian subsidiary and (iv) lower property taxes.

Such favorable impacts were partially offset by lower mark-to-market gains in the current 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).

Maintenance Capital.

The decrease in maintenance capital spending for the year ended December 31, 2020 compared to the year ended December 31, 2019 was primarily due to timing changes, the impact of asset sales, the completion of multi-year reliability improvement programs and application of updated regulatory guidance, among other factors.

Index to Financial Statements

Supply and Logistics Segment

Revenues from our Supply and Logistics segment activities reflect the sale of gathered and bulk-purchased crude oil, as well as sales of NGL volumes.

Generally, our segment results are impacted by (i) increases or decreases in our Supply and Logistics segment volumes (which consist of lease gathering crude oil purchases volumes and NGL sales volumes), (ii) the overall strength, weakness and volatility of market conditions, including regional differentials, and (iii) the effects of competition on our lease gathering and NGL margins.

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

The following tables set forth our operating results from our Supply and Logistics segment:

Operating Results (1)

(in millions, except per barrel data)

Year Ended December 31, Variance

2020 2019 $ %

Revenues $ 22,059 $ 32,276 $ (10,217) (32) %

Purchases and related costs (22,099) (31,276) 9,177 29 %

(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.

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:

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.

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).

Segment General and Administrative Expenses.

(89) (110) 21 19 %

Adjustments (3) :

Losses from derivative activities net of inventory valuation adjustments 484 173 311 **

Long-term inventory costing adjustments 44 (20) 64 **

Deficiencies under minimum volume commitments, net 1 — 1 **

Equity-indexed compensation expense 4 4 — **

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

Segment Adjusted EBITDA $ 210 $ 803 $ (593) (74) %

Maintenance capital $ 29 $ 29 $ — — %

Segment Adjusted EBITDA per barrel $ 0.43 $ 1.61 $ (1.18) (73) %

Average Daily Volumes (4)

(in thousands of barrels per day)

Year Ended December 31, Variance

2020 2019 Volume %

Crude oil lease gathering purchases 1,174 1,162 12 1 %

NGL sales 144 207 (63) (30) %

Supply and Logistics segment total volumes 1,318 1,369 (51) (4) %

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

(1) Revenues and costs include intersegment amounts.

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

The proportional allocations by segment require judgment by management and are based on the business activities that exist during each period.

(3) Represents adjustments included in the performance measure utilized by our CODM in the evaluation of segment results.

See Note 21 to our Consolidated Financial Statements for additional discussion of such adjustments.

(4) Average daily volumes are calculated as the total volumes for the period divided by the number of days in the period.

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

The following table presents the range of the NYMEX West Texas Intermediate (“WTI”) benchmark price of crude oil (in dollars per barrel):

Crude Oil Price

During the Year Ended December 31, Low High

2020 $ (38) $ 63

2019 $ 46 $ 66

Our crude oil and NGL supply, logistics and distribution operations are not directly affected by the absolute level of prices.

Because the commodities that we buy and sell are generally indexed to the same pricing indices for both sales and purchases, revenues and costs related to purchases will fluctuate with market prices.

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

Additionally, net revenues are impacted by net gains and losses from certain derivative activities during the periods.

Segment Adjusted EBITDA and Volumes.

The following summarizes the significant items impacting our Supply and Logistics Segment Adjusted EBITDA:

• Crude Oil Operations.

Net revenues from our crude oil operations decreased for year ended December 31, 2020 compared to the year ended December 31, 2019, primarily due to a combination of (i) less favorable crude oil differentials, particularly the differential between the value of crude oil in the Permian Basin compared to the Gulf Coast market and (ii) the impact of lower volumes in higher margin areas, partially offset by volume increases in lower margin areas.

Such unfavorable impacts were partially offset by the favorable impact of contango market conditions during the last three quarters of 2020.

• NGL Operations.

Net revenues from our NGL operations 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 fractionation spreads between the price of natural gas and the extracted NGL, (iii) lower border flows through our straddle plants and (iv) the absence of the favorable impact from certain non-recurring items recorded in the second quarter of 2019.

• Impact from Certain Derivative Activities, Net of 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), losses on derivatives that are related to investing activities (such as the purchase of linefill) and inventory valuation adjustments, as applicable.

• 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.

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• Long-Term Inventory Costing Adjustments.

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

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

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.

• Foreign Exchange Impacts.

Our net revenues are impacted by fluctuations in the value of CAD to USD, resulting in foreign exchange gains and losses on U.S.

denominated net assets within our Canadian operations.

These non-cash 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.

Index to Financial Statements

• Field Operating Costs.

The decrease in field operating costs for the year ended December 31, 2020 compared to the year ended December 31, 2019 was primarily driven by 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.

• Segment General and Administrative Expenses.

The decrease in segment general and administrative expenses for the year ended December 31, 2020 compared to the year ended December 31, 2019 was primarily driven by (i) lower compensation costs including the benefit of wage subsidies received by our Canadian subsidiary, (ii) decreased travel and entertainment costs, (iii) a decrease in equity-based compensation costs on liability-classified awards (which are not included as an “Adjustment” in the table above) due to a decrease in our common unit price and (iv) general cost reductions associated with exiting low margin, high administrative cost businesses.

Other Income and Expenses

Depreciation and Amortization

Gains/Losses on Asset Sales and Asset Impairments, Net

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.

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

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

Index to Financial Statements

Interest Expense

Interest expense is primarily impacted by:

• our weighted average debt balances;

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

• market interest rates and our interest rate hedging activities;

• interest capitalized on capital projects.

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

Weighted Average

Interest Rate (1)

Interest expense for the year ended December 31, 2019

$ 425 2.2 % 4.4 %

Impact of lower capitalized interest 10

Impact of borrowings under credit facilities and PAA commercial paper program 3

Impact of issuance and retirement of PAA senior notes (4)

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

(1) Excludes commitment and other fees.

Interest expense increased for the year ended December 31, 2020 compared to the year ended December 31, 2019 primarily due to (i) a higher weighted average debt balance during 2020 driven by higher commercial paper and credit facility borrowings and (ii) lower capitalized interest in the 2020 period resulting from fewer capital projects under construction, partially offset by (iii) the impact from lower weighted average rates.

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

Other Income, Net

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

Year Ended December 31,

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

Net gain on foreign currency revaluation (2)

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

(2) The activity during 2020 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.

Index to Financial Statements

Income Tax (Expense)/Benefit

The decrease in current income tax expense for the year ended December 31, 2020 compared to the year ended December 31, 2019 was primarily due to lower taxable earnings from our Canadian operations.

The increase in the deferred income tax benefit for the year ended December 31, 2020 compared to the year ended December 31, 2019 was primarily due to (i) the impact of lower earnings at PAA on income attributable to PAGP and (ii) lower year-over-year income as impacted by fluctuations in the derivative mark-to-market valuations in our Canadian operations, partially offset by 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.

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.

Liquidity and Capital Resources

Our primary sources of liquidity are (i) cash flow from operating activities (ii) borrowings under PAA’s credit facilities or commercial paper program and (iii) funds received from sales of equity and debt securities.

In addition, we may supplement these sources of liquidity with proceeds from our divestiture program.

Our primary sources of liquidity are (i) cash flow from operating activities and (ii) borrowings under PAA’s credit facilities or commercial paper program.

In addition, we may supplement these primary sources of liquidity with proceeds from asset sales, and in the past have utilized funds received from sales of equity and debt securities.

Our primary cash requirements include, but are not limited to, (i) ordinary course of business uses, such as the payment of amounts related to the purchase of crude oil, NGL and other products, other expenses and interest payments on outstanding debt, (ii) investment and maintenance capital activities, (iii) acquisitions of assets or businesses, (iv) repayment of principal on long-term debt and (v) distributions to our Class A shareholders and noncontrolling interests.

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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, 2020, although we had a working capital deficit of $587 million, we had approximately $2.2 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, 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):

December 31, 2021

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“Risk Factors—Risks Related to PAA’s Business—Loss of PAA’s investment grade credit rating or the ability to receive open credit could negatively affect its borrowing costs, ability to purchase crude oil, NGL and natural gas supplies or to capitalize on market opportunities.”

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 has caused liquidity issues impacting many energy companies;

however, we believe that we have, and will continue to have, the ability to access PAA’s commercial paper program and credit facilities, which we use to meet our short-term cash needs.

We believe that we have, and will continue to have, the ability to access PAA’s commercial paper program and credit facilities, which we use to meet our short-term cash needs.

We believe that our financial position remains strong and we have sufficient liquid assets, cash flow from operating activities and borrowing capacity under PAA’s credit agreements to meet our financial commitments, debt service obligations, contingencies and anticipated capital expenditures.

however, extended disruptions in the financial markets and/or energy price volatility that adversely affect our business may have a materially adverse effect on our financial condition, results of operations or cash flows.

We are, however, subject to business and operational risks that could adversely affect our cash flow, including extended disruptions in the financial markets and/or energy price volatility resulting from current macroeconomic and geopolitical conditions associated with the COVID-19 pandemic and/or actions by OPEC.

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

“Risk Factors” for further discussion regarding risks that may impact our liquidity and capital resources.

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

These include PAA’s $1.6 billion senior unsecured revolving credit facility maturing in 2024, $1.4 billion senior secured hedged inventory facility maturing in 2022 (excluding aggregate commitments of $45 million, which mature in 2021) and $3.0 billion unsecured commercial paper program that is backstopped by PAA’s revolving credit facility and its hedged inventory facility.

Additionally, PAA has two $100 million term loans.

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

These include PAA’s $1.35 billion senior unsecured revolving credit facility maturing in 2026, $1.35 billion senior secured hedged inventory facility maturing in 2024 and $2.7 billion unsecured commercial paper program that is backstopped by PAA’s revolving credit facility and its hedged inventory facility.

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

A default under PAA’s credit agreements or indentures would permit the lenders to accelerate the maturity of the outstanding debt.

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Index to Financial Statements

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.

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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.

During 2018, our cash provided by operating activities was favorably impacted by approximately $250 million of cash received for transactions for which the revenue has been deferred pending the completion of future performance obligations.

The favorable impact was partially offset by an increase in the volume of crude oil inventory that we held, which was funded from earnings from our operations and proceeds from asset sales.

Investing Activities

In addition to our operating needs discussed above, we also use cash for our investment capital projects, maintenance capital activities and acquisition activities.

Historically, we have financed these expenditures primarily with cash generated by operating activities discussed in “—Cash Flow from Operating Activities” above and the financing activities discussed in “—Financing Activities” below.

In recent years, we have also used proceeds from our divestiture program, as discussed further below.

We have made and will continue to make capital expenditures for investment capital projects, maintenance activities and acquisitions.

However, in the near term, we do not plan to issue common equity to fund such activities.

Capital Expenditures

The following table summarizes our expenditures for acquisition capital, investment capital and maintenance capital (in millions):

In addition to our operating needs, we also use cash for our investment capital projects, maintenance capital activities and acquisition activities.

We fund these expenditures with cash generated by operating activities, financing activities and/or proceeds from asset sales.

In the near term, we do not plan to issue common equity to fund such expenditures.

The following table summarizes our investment, maintenance and acquisition capital expenditures (in millions):

Year Ended December 31,

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(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) “Investment capital” was previously termed “expansion capital.” We consider the term “investment capital” to be more descriptive.

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

(4) Acquisition capital for 2020 primarily includes a crude oil gathering system located in the Delaware Basin.

Index to Financial Statements

(3) 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

Our investment capital programs consist of investments in midstream infrastructure projects that build upon our core assets and operations.

For the years presented, substantially all of the investment capital was invested in our fee-based Transportation and Facilities segments.

The majority of this investment capital consists of highly-contracted projects that complement our broader system capabilities and support the long-term needs of the upstream and downstream sectors of the industry value chain.

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

Index to Financial Statements

Year Ended December 31,

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Total $ 237 $ 921 $ 1,340

(1) These projects will continue into 2021.

See “—2021 Investment Capital Projects below.”

(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.

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

(3) Includes projects at our St.

James and Cushing terminals.

2021 Investment Capital Projects.

In April 2020, in response to the current dynamic and uncertain market conditions, we announced our plan to significantly reduce and continue to challenge our capital program.

The majority of our 2021 investment capital program will be invested in our fee-based Transportation and Facilities segments.

We expect that our investments will have minimal contributions to our 2021 results, but will provide growth for 2022 and beyond.

Our 2021 capital program includes the following projects as of February 2021 with the estimated cost for the entire year (in millions):

Projects 2021

Permian Basin Takeaway Pipeline Projects $ 140

Long-Haul Pipeline Projects (Non-Permian) 115

Complementary Permian Basin Projects 85

Selected Facilities/Downstream Projects 50

Other Projects 35

Total Projected 2021 Investment Capital $ 425

We continue to evaluate potential sales of non-core assets and/or sales of partial interests in assets to strategic joint venture partners.

The following table summarizes the proceeds received for sales of such assets, which were previously reported in our Transportation and Facilities segments:

James, Cushing and Fort Saskatchewan terminals.

Projected 2022 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).

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).

We expect to fund our 2022 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):

Year Ended December 31,

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$ 875 $ 451 $ 205

(1) Includes proceeds from (i) a multi-year supply agreement related to the sale of certain NGL terminals in April 2020 and (ii) our formation of Red River Pipeline Company LLC in May 2019.

(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.

Index to Financial Statements

Proceeds from asset sales were used to fund our investment capital projects and reduce debt levels.

See Note 7 to our Consolidated Financial Statements for additional detail regarding our divestiture transactions.

Ongoing Activities Related to Strategic Transactions

We are continuously engaged in the evaluation of potential transactions that support our current business strategy.

While in the past such transactions have included acquisitions and large capital projects, consistent with our current strategic focus on capital discipline, leverage reduction, portfolio optimization and free cash flow generation, we are currently primarily focused on evaluating whether we should (i) sell assets that we regard as non-core or that we believe might be a better fit with the business and/or assets of a third-party buyer or (ii) sell partial interests in assets to strategic joint venture partners, in each case to optimize our asset portfolio and strengthen our balance sheet and leverage metrics.

With respect to a potential divestiture, we may also conduct an auction process or may negotiate a transaction with one or a limited number of potential buyers.

Such transactions could involve assets that, if sold or put into a joint venture or joint ownership arrangement, could have a material effect on our financial condition and results of operations.

In the past, such transactions have included the sale of non-core assets, the sale of partial interests in assets to strategic joint venture partners, acquisitions and large investment capital projects.

With respect to a potential divestiture or acquisition, we may conduct an auction process or participate in an auction process conducted by a third party or we may negotiate a transaction with one or a limited number of potential buyers (in the case of a divestiture) or sellers (in the case of an acquisition).

Such transactions could have a material effect on our financial condition and results of operations.

We typically do not announce a transaction until after we have executed a definitive agreement.

However, in certain cases in order to protect our business interests or for other reasons, we may defer public announcement of a transaction until closing or a later date.

In certain cases, in order to protect our business interests or for other reasons, we may defer public announcement of a transaction until closing or a later date.

Past experience has demonstrated that discussions and negotiations regarding a potential transaction can advance or terminate in a short period of time.

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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, joint ventures, joint ownership arrangements and acquisitions involve risks that may adversely affect PAA’s business.”

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

Index to Financial Statements

Financing Activities

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Borrowings and Repayments Under Credit Arrangements

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.

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

During the year ended December 31, 2018, we had net repayments on the PAA credit facilities and commercial paper program of $901 million.

In August 2018, PAA entered into an agreement for two $100 million term loans from the remarketing of its two $100 million bonds.

The purchasers of the two term loans have the right to put, at par, the term loans in July 2023.

The bonds mature by their terms in May 2032 and August 2035, respectively.

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

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.

During 2020 and 2019, PAA issued senior unsecured notes as summarized in the table below (in millions):

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

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Repayments of PAA Senior Notes.

During 2020 and 2019, PAA repaid the following senior unsecured notes in full (in millions):

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):

Year Description Repayment Date

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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.

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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.

Registration Statements

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PAA periodically accesses the capital markets for both equity and debt financing.

PAA has filed with the SEC a universal shelf registration statement that, subject to effectiveness at the time of use, allows PAA to issue up to an aggregate of $1.1 billion of debt or equity securities (“PAA Traditional Shelf”).

PAA did not conduct any offerings under the PAA Traditional Shelf during the years ended December 31, 2020, 2019 or 2018.

At December 31, 2020, PAA had approximately $1.1 billion of unsold securities available under the PAA Traditional Shelf.

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

Index to Financial Statements

amount of debt and equity securities, subject to market conditions and capital needs.

The offering of PAA’s $750 million, 3.80% senior notes in June 2020 was conducted under the PAA WKSI Shelf.

PAA has filed with the SEC a universal shelf registration statement that, subject to effectiveness at the time of use, allows PAA to issue up to a specified amount of debt or equity securities (“PAA Traditional Shelf”), under which PAA had approximately $1.1 billion of unsold securities available at December 31, 2021.

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 6.2 million common units under the Program through open market purchases that settled during the year ended December 31, 2020.

The total purchase price of these repurchases was $50 million, including commissions and fees.

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.

The remaining available capacity under the Program as of December 31, 2021 was $272 million.

Additionally, PAA repurchased 350,000 common units under the Program for $3 million through open market purchases at the end of December 2020 that settled in January 2021.

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 law 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 available cash and distributions.

In response to the challenging near-term market conditions, we took steps to further strengthen our balance sheet, liquidity and long-term financial flexibility.

In this regard, beginning with the May 2020 distribution, PAA’s distribution per common unit and our distribution per Class A share were reduced by 50% versus the distributions paid in February 2020, which reflects a reduction of $525 million on an annualized basis.

See “—Executive Summary—Recent Events and Outlook” for further discussion.

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.

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

On February 14, 2022, we paid a quarterly distribution of $0.18 per Class A share ($0.72 per Class A share on an annualized basis).

The distribution was paid to Class A shareholders of record as of January 31, 2022, with respect to the quarter ended December 31, 2021.

See Note 12 to our Consolidated Financial Statements for details of distributions paid during the three years ended December 31, 2021.

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, 2020, 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 21% limited partner interest in AAP and (iii) a 33% interest in Red River Pipeline Company LLC.

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.

See Note 12 to our Consolidated Financial Statements for details of distributions paid to noncontrolling interests during the three years ended December 31, 2021.

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.

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

Index to Financial Statements

Distributions to PAA’s Series B preferred unitholders.

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On February 14, 2022, PAA paid a quarterly distribution of $0.18 per common unit ($0.72 per common unit on an annualized basis).

The total distribution of $127 million was paid to common unitholders of record as of January 31, 2022, with respect to the quarter ended December 31, 2021.

See Note 12 to our Consolidated Financial Statements for details of distributions paid during the three years ended December 31, 2021.

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For a discussion of contingencies that may impact us, see Note 19 to our Consolidated Financial Statements.

Contractual Obligations.

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.

Purchase Obligations

In the ordinary course of doing business, we purchase crude oil and NGL from third parties under contracts, the majority of which range in term from thirty-day evergreen to five years, with a limited number of contracts with remaining terms extending up to 14 years.

We establish a margin for these purchases by entering into various types of physical and financial sale and exchange transactions through which we seek to maintain a position that is substantially balanced between purchases on the one hand and sales and future delivery obligations on the other.

The table below includes purchase obligations related to these activities.

Where applicable, the amounts presented represent the net obligations associated with our counterparties (including giving effect to netting buy/sell contracts and those subject to a net settlement arrangement).

We do not expect to use a significant amount of internal capital to meet these obligations, as the obligations will be funded by corresponding sales to entities that we deem creditworthy or who have provided credit support we consider adequate.

The following table includes our best estimate of the amount and timing of these payments as well as other amounts due under the specified contractual obligations as of December 31, 2020 (in millions):

2021 2022 2023 2024 2025 Thereafter Total

Long-term debt and related interest payments (1)

$ 406 $ 1,183 $ 1,662 $ 1,083 $ 1,300 $ 8,337 $ 13,971

108 100 77 63 49 304 701

Other obligations (3)

542 368 325 281 254 934 2,704

Subtotal 1,056 1,651 2,064 1,427 1,603 9,575 17,376

Index to Financial Statements

The following table includes our best estimate and the timing of these payments as of December 31, 2021 (in millions):

2022 2023 2024 2025 2026 2027 and Thereafter Total

Crude oil, NGL and other purchases (1)

$ 22,842 $ 20,165 $ 19,215 $ 16,022 $ 15,215 $ 47,079 $ 140,538

Total $ 12,621 $ 12,004 $ 11,707 $ 10,462 $ 9,110 $ 36,420 $ 92,324

(1) Includes debt service payments, interest payments due on PAA’s senior notes and the commitment fee on assumed available capacity under the PAA credit facilities, as well as long-term borrowings under PAA’s credit agreements and commercial paper program, if any.

Although there may be short-term borrowings under PAA’s credit agreements and commercial paper program, we historically repay and borrow at varying amounts.

As such, we have included only the maximum commitment fee (as if no short-term borrowings were outstanding on PAA’s credit agreements or commercial paper program) in the amounts above.

For additional information regarding our debt obligations, see Note 11 to our Consolidated Financial Statements.

(2) Includes both operating and finance leases as defined by FASB guidance.

Leases are primarily for (i) railcars, (ii) land, (iii) office space, (iv) storage tanks, (v) tractor trailers and (vi) vehicles.

See Note 14 to our Consolidated Financial Statements for additional information.

Index to Financial Statements

(3) Includes (i) other long-term liabilities, (ii) storage, processing and transportation agreements (including certain agreements for which the amount and timing of expected payments is subject to the completion of underlying construction projects), (iii) certain rights-of-way easements and (iv) noncancelable commitments related to our investment capital projects, including projected contributions for our share of the capital spending of our equity method investments.

The storage, processing and transportation agreements include approximately $2.0 billion associated with agreements to store crude oil at facilities and transport crude oil on pipelines owned by equity method investees at posted tariff rates or prices that we believe approximate market.

A portion of our commitment to transport is supported by crude oil buy/sell or other agreements with third parties with commensurate quantities.

(1) Amounts are primarily based on estimated volumes and market prices based on average activity during December 2021.

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Letters of Credit.

In connection with supply and logistics activities, we provide certain suppliers with irrevocable standby letters of credit to secure our obligation for the purchase and transportation of crude oil, NGL and natural gas.

In connection with our merchant activities, we provide certain suppliers with irrevocable standby letters of credit to secure our obligation for the purchase and transportation of crude oil, NGL and natural gas.

Our liabilities with respect to these purchase obligations are recorded in accounts payable on our balance sheet in the month the product is purchased.

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Certain of these entities are borrowers under credit facilities.

We are neither a co-borrower nor a guarantor under any facilities of such entities.

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

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

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50% $ 217 $ 5 $ —

Red Oak Pipeline LLC Crude Oil Pipeline 50% $ 205 $ — $ —

Saddlehorn Pipeline Company, LLC Crude Oil Pipeline 30% $ 662 $ 40 $ —

STACK Pipeline LLC Crude Oil Pipeline (1)

OMOG JV LLC Crude Oil Pipeline (1)

40% $ 344 $ 10 $ 5

Saddlehorn Pipeline Company, LLC Crude Oil Pipeline 30% $ 639 $ 31 $ —

White Cliffs Pipeline, LLC Crude Oil Pipeline 36% $ 463 $ 10 $ —

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Index to Financial Statements

Critical Accounting Policies and Estimates

Such estimates and assumptions also affect the reported amounts of revenues and expenses during the reporting period.

Although we believe these estimates are reasonable, actual results could differ from these estimates.

On a regular basis, we evaluate our assumptions, judgments and estimates.

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

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

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.

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

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

In accordance with Financial Accounting Standards Board (“FASB”) guidance regarding business combinations, with each acquisition, we allocate the cost of the acquired entity to the assets acquired and liabilities assumed based on their estimated fair values at the date of acquisition.

If the initial accounting for the business combination is incomplete when the combination occurs, an estimate will be recorded.

We also expense the transaction costs as incurred in connection with each acquisition, except for acquisitions of equity method investments.

In addition, we are required to recognize intangible assets separately from goodwill.

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

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.