PAA US Equity☆

paa-20201231

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

(Mark One)

☑ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2020

OR

☐TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission file number 1-14569

PLAINS ALL AMERICAN PIPELINE, L.P.

(Exact name of registrant as specified in its charter)

(Address of principal executive offices) (Zip Code)

Registrant’s telephone number, including area code: (713) 646-4100

Securities registered pursuant to Section 12(b) of the Act:

Title of Each Class Trading Symbol(s) Name of Each Exchange on Which Registered

Common Units PAA Nasdaq

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes☑ No ☐

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐No☑

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes☑ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes☑ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer ☑ Accelerated filer ☐

Non-accelerated filer ☐ Smaller reporting company ☐

Emerging growth company ☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report.☑

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☑

The aggregate market value of the Common Units held by non-affiliates of the registrant (treating all executive officers and directors of the registrant and holders of 10% or more of the Common Units outstanding, for this purpose, as if they may be affiliates of the registrant) was approximately $4.2 billion on June 30, 2020, based on a closing price of $8.84 per Common Unit as reported on the New York Stock Exchange on such date. As of February 11, 2021, there were 722,052,254 Common Units outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s definitive Proxy Statement to be filed pursuant to Regulation 14A pertaining to the 2021 Annual Meeting of Unitholders are incorporated by reference into Part III hereof. The registrant intends to file such Proxy Statement no later than 120 days after the end of the fiscal year covered by this Form 10-K.

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

FORM 10-K—2020 ANNUAL REPORT

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Page

PART I 5

Items 1 and 2. Business and Properties 5

Item 1A. Risk Factors 44

Item 1B. Unresolved Staff Comments 72

Item 3. Legal Proceedings 72

Item 4. Mine Safety Disclosures 72

Item 6. Selected Financial Data 75

Item 7A. Quantitative and Qualitative Disclosures About Market Risk 106

Item 8. Financial Statements and Supplementary Data 107

Item 9A. Controls and Procedures 107

Item 9B. Other Information 108

Item 11. Executive Compensation 109

Item 14. Principal Accountant Fees and Services 110

Item 15. Exhibits and Financial Statement Schedules 111

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FORWARD-LOOKING STATEMENTS

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

Factors Related Primarily to the COVID-19 Pandemic:

•further declines in global crude oil demand and crude oil prices that correspondingly lead to a significant reduction of North American crude oil, natural gas liquids (“NGL”) and natural gas production (whether due to reduced producer cash flow to fund drilling activities or the inability of producers to access capital, or both, the unavailability of pipeline and/or storage capacity, the shutting-in of production by producers, government-mandated pro-ration orders, or other factors), which in turn could result in significant declines in the actual or expected volume of crude oil and NGL shipped, processed, purchased, stored, fractionated and/or gathered at or through the use of our assets and/or the reduction of commercial opportunities that might otherwise be available to us;

•uncertainty regarding the timing, pace and extent of an economic recovery in the United States and elsewhere, which in turn will likely affect demand for crude oil and therefore the demand for the midstream services we provide and the commercial opportunities available to us;

•uncertainty regarding the future impacts of COVID-19, which may depend on the development, deployment and effectiveness of vaccines; treatments and testing protocols; mutations of the virus resulting in increased transmissibility or severity of the disease or decreasing the effectiveness of vaccines or treatments; the capacity of our healthcare systems and public health infrastructure to manage current and future outbreaks; and various political and economic restrictions;

•the timing of a return to market conditions that are more conducive to an increase in drilling and production activities in the United States and a resulting increase in demand for the midstream services we provide;

•the refusal or inability of our customers or counterparties to perform their obligations under their contracts with us (including commercial contracts, asset sale agreements and other agreements), whether justified or not and whether due to financial constraints (reduced creditworthiness, liquidity issues or insolvency), market constraints, legal constraints (including governmental orders or guidance), the exercise of contractual or common law rights that allegedly excuse their performance (such as force majeure or similar claims) or other factors;

•our inability to perform our obligations under our contracts, whether due to non-performance by third parties, including our customers or counterparties, market constraints, third-party constraints, legal constraints (including governmental orders or guidance), or other factors;

•disruptions to futures markets for crude oil, NGL and other petroleum products, which may impair our ability to execute our commercial or hedging strategies;

General Factors:

•the effects of competition and capacity overbuild in areas where we operate, including contract renewal risk and the risk of loss of business to other midstream operators who are willing or under pressure to aggressively reduce transportation rates in order to capture or preserve customers;

•negative societal sentiment regarding the hydrocarbon energy industry and the continued development and consumption of hydrocarbons, which could influence consumer preferences and governmental or regulatory actions that adversely impact our business;

•unanticipated changes in crude oil and NGL market structure, grade differentials and volatility (or lack thereof);

•environmental liabilities or events that are not covered by an indemnity, insurance or existing reserves;

•fluctuations in refinery capacity in areas supplied by our mainlines and other factors affecting demand for various grades of crude oil, NGL and natural gas and resulting changes in pricing conditions or transportation throughput requirements;

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•maintenance of our credit rating and ability to receive open credit from our suppliers and trade counterparties;

•the occurrence of a natural disaster, catastrophe, terrorist attack (including eco-terrorist attacks) or other event that materially impacts our operations, including cyber or other attacks on our electronic and computer systems;

•weather interference with business operations or project construction, including the impact of extreme weather events or conditions;

•the incurrence of costs and expenses related to unexpected or unplanned capital expenditures, third-party claims or other factors;

•the successful integration and future performance of acquired assets or businesses and the successful operation of joint ventures and joint operating arrangements we enter into from time to time, whether relating to assets operated by us or by third parties;

•failure to implement or capitalize, or delays in implementing or capitalizing, on investment capital projects, whether due to permitting delays, permitting withdrawals or other factors;

•shortages or cost increases of supplies, materials or labor;

•the impact of current and future laws, rulings, governmental regulations, trade policies, accounting standards and statements, and related interpretations, including legislation or regulatory initiatives that prohibit, restrict or regulate hydraulic fracturing or that prohibit the development of oil and gas resources and the related infrastructure on lands dedicated to or served by our pipelines;

•tightened capital markets or other factors that increase our cost of capital or limit our ability to obtain debt or equity financing on satisfactory terms to fund additional acquisitions, investment capital projects, working capital requirements and the repayment or refinancing of indebtedness;

•inability of producers, who have made commitments to our pipelines, to access capital to fund their drilling and completion activities;

•general economic, market or business conditions (both within North America and globally and including the potential for a recession or significant slowdown in economic activity levels) and the amplification of other risks caused by volatile financial markets, capital constraints, liquidity concerns and inflation;

•the availability of, and our ability to consummate, divestitures, joint ventures, acquisitions or other strategic opportunities;

•the use or availability of third-party assets upon which our operations depend and over which we have little or no control;

•the currency exchange rate of the Canadian dollar to the United States dollar;

•continued creditworthiness of, and performance by, our counterparties, including financial institutions and trading companies with which we do business;

•inability to recognize current revenue attributable to deficiency payments received from customers who fail to ship or move more than minimum contracted volumes until the related credits expire or are used;

•significant under-utilization of our assets and facilities;

•increased costs, or lack of availability, of insurance;

•the effectiveness of our risk management activities;

•fluctuations in the debt and equity markets, including the price of our units at the time of vesting under our long-term incentive plans;

•risks related to the development and operation of our assets, including our ability to satisfy our contractual obligations to our customers; and

•other factors and uncertainties inherent in the transportation, storage, terminalling and marketing of crude oil, as well as in the storage of natural gas and the processing, transportation, fractionation, storage and marketing of natural gas liquids.

Other factors described herein, as well as factors that are unknown or unpredictable, could also have a material adverse effect on future results. Please read Item 1A. “Risk Factors.” Except as required by applicable securities laws, we do not intend to update these forward-looking statements and information.

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PART I

Items 1 and 2. Business and Properties

General

Plains All American Pipeline, L.P. is a publicly traded Delaware limited partnership. Our common units are listed on the Nasdaq Global Select Market (“Nasdaq”) under the ticker symbol “PAA.” Our business is based on the fundamental thesis that hydrocarbons are essential to the security and advancement of human quality of life and will continue to play a major long-term role in the world economy. We believe that midstream energy infrastructure provides a critical link between energy supply and demand, and is fundamental to the maintenance and advancement of our modern-day standard of living. Acknowledging the need for multiple forms of energy to meet growing world-wide demand, we believe absolute hydrocarbon demand will increase over time, driven by global population growth and a desire to improve quality of life. As a result, we believe that hydrocarbon energy infrastructure will remain critical and valuable.

Our business model integrates large-scale supply aggregation capabilities with the ownership and operation of critical midstream infrastructure systems that connect major producing regions to key demand centers and export terminals. As one of the largest midstream service providers in North America, we own an extensive network of pipeline transportation, terminalling, storage and gathering assets in key crude oil and natural gas liquids (“NGL”) producing basins (including the Permian Basin) and transportation corridors and at major market hubs in the United States and Canada. Our assets and the services we provide are primarily focused on crude oil, NGL and natural gas.

Our operations are conducted directly and indirectly through our primary operating subsidiaries, which comprise 100% of the assets and operations affiliated with Plains and its subsidiaries. As used in this Form 10-K and unless the context indicates otherwise, the terms “Partnership,” “Plains,” “PAA,” “we,” “us,” “our,” “ours” and similar terms refer to Plains All American Pipeline, L.P. and its subsidiaries.

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Organizational Structure

The diagram below shows our organizational structure as of December 31, 2020 in a summarized format:

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(1)Each Class C share represents a non-economic limited partner interest in PAGP. The number of Class C shares that we own is equal to the number of outstanding common units and Series A Preferred units (“Common Unit Equivalents”) that are entitled to vote, pro rata with the holders of PAGP Class A and Class B shares, for the election of eligible PAGP GP directors. The Class C shares function as a “pass-through” voting mechanism through which we vote at the direction of and as proxy for our common unitholders and Series A preferred unitholders in such director elections. Common units held by AAP and Series B preferred units are not entitled to vote in the election of directors.

(2)The Partnership holds (i) direct and indirect ownership interests in consolidated operating subsidiaries including, but not limited to, Plains Marketing, L.P., Plains Pipeline, L.P., Plains Midstream Canada ULC (“PMCULC”) and PAA Natural Gas Storage, L.P. and (ii) indirect equity interests in unconsolidated entities including, but not limited to, BridgeTex Pipeline Company, LLC, Cactus II Pipeline LLC, Capline Pipeline Company LLC, Diamond Pipeline LLC, Eagle Ford Pipeline LLC, Eagle Ford Terminals Corpus Christi LLC, Saddlehorn Pipeline Company, LLC, STACK Pipeline LLC, White Cliffs Pipeline, L.L.C. and Wink to Webster Pipeline LLC.

Business Strategy

Our principal business strategy is to provide competitive and efficient midstream infrastructure and logistics services to producers, refiners and other customers. We strive to address regional supply and demand imbalances for crude oil and NGL in the United States and Canada by combining the strategic location and capabilities of our transportation, terminalling, storage, processing and fractionation assets with our supply, logistics and distribution expertise. We intend to execute our strategy by:

•Focusing on operational excellence, continuous improvement and running a safe, reliable, environmentally and socially responsible operation;

•Using our well positioned network of midstream infrastructure in conjunction with our commercial capabilities to provide market access, flexibility and value chain solutions to our customers, capture market opportunities, address physical market imbalances, mitigate risks and generate sustainable cash flow and margin;

•Optimizing our asset portfolio and operations to maximize returns on invested capital; and

•Pursuing a balanced, long-term financial strategy that is focused on maintaining an investment grade credit profile and enhancing financial flexibility by making disciplined capital allocation decisions.

We believe successful execution of this strategy will enable us to generate sustainable earnings and cash flow, and will position us to reduce leverage and maintain an investment grade credit profile while increasing returns to equity holders over time.

Competitive Strengths

We believe that the following competitive strengths position us to successfully execute our principal business strategy:

•Strategically located, geographically diverse and interconnected asset base that provides operational flexibility and commercial optionality. The majority of our primary Transportation segment assets are in crude oil service, are located in well-established crude oil producing regions (with our largest asset presence in the Permian Basin) and other transportation corridors and are connected, directly or indirectly, with our Facilities segment assets. The majority of our Facilities segment assets are located at major trading locations and premium markets that serve as gateways to major North American refinery and distribution markets where we have strong business relationships. In addition, our pipeline, rail, barge, truck and storage assets provide our customers and us with significant flexibility and optionality to satisfy demand and balance markets.

•Full-service integrated model and long-term focus attracts broad, diverse and high-quality customer base that supports sustainable fee-based cash flow generation. Our strategically located and interconnected asset base enables us to provide our customers with a wide variety of services, including supply aggregation, quality segregation, flow assurance and market access. We focus on building long-term relationships and alignment of interests with our customers. We believe this approach has helped us build a high-quality portfolio of customers and contracts (including long-term, third-party transportation contracts and acreage dedication contracts) that provide long-term volume support for our assets and, in turn, support long-term fee-based cash flow generation from our assets.

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•We possess specialized crude oil and NGL market knowledge. We believe our business relationships with participants in various phases of the crude oil and NGL distribution chain, from producers to refiners, as well as our own industry expertise (including our knowledge of North American crude oil and NGL flows), provide us with extensive market insight and an understanding of the North American physical crude oil and NGL markets that enables us to provide value chain solutions for our customers.

•Our supply and logistics activities provide us with the opportunity to realize incremental margins. We believe the variety of activities executed within our Supply and Logistics segment provides us with a low-risk opportunity to generate incremental margin, the amount of which may vary depending on market conditions (such as differentials and certain competitive factors).

•We have the strategic and technical skills needed to execute strategic transactions that support our business and financial objectives, including joint ventures, joint ownership arrangements and divestitures. Since 2016, we have consummated over 10 joint venture and/or joint ownership arrangements and completed over $3 billion of divestitures of non-core assets and/or strategic sales of partial interests in selected assets. In addition, although acquisitions and investment capital projects are not currently a focus area, the strategic and technical skills needed to complete such transactions are very similar to those needed for other strategic transactions and since our initial public offering, we have completed and integrated over 90 acquisitions with an aggregate purchase price of approximately $13.7 billion, and we have also implemented investment capital projects totaling approximately $16.7 billion.

•We have an experienced management team whose interests are aligned with those of our unitholders. Our executive management team has an average of 30 years of experience spanning across all sectors of the energy industry, as well as investment banking, and an average of 14 years with us or our predecessors and affiliates. In addition, through their ownership of common units and grants of phantom units, our management team has a vested interest in our continued success.

Financial Strategy

Targeted Credit Profile

We believe that a major factor in our continued success is our ability to maintain significant financial flexibility. An important part of our financial strategy is our commitment to generating positive free cash flow after distributions with a continued priority on deleveraging while also prudently increasing cash returned to our unitholders.

In that regard, we intend to maintain a credit profile that we believe is consistent with investment grade credit ratings. We target a credit profile with the following attributes:

•a long-term debt-to-Adjusted EBITDA multiple averaging between 3.0x and 3.5x (See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations—Non-GAAP Financial Measures” for our definition of Adjusted EBITDA and a discussion of our selected items that impact comparability and our non-GAAP measures.);

•an average long-term debt-to-total capitalization ratio of approximately 50% or less;

•an average total debt-to-total capitalization ratio of approximately 60% or less; and

•an average Adjusted EBITDA-to-interest coverage multiple of approximately 3.3x or better.

The first two of these four metrics include long-term debt as a critical measure, but do not include certain components of our capital structure such as short-term debt, preferred units and operating leases that may be considered by rating agencies in assigning their ratings. At December 31, 2020, our publicly-traded senior notes comprised approximately 97% of our long-term debt. Additionally, we also routinely incur short-term debt primarily in connection with our supply and logistics activities that involve the simultaneous purchase and forward sale of crude oil and NGL. The crude oil and NGL purchased in these transactions are hedged. These borrowings are self-liquidating as they are repaid with sales proceeds. We also incur short-term debt to fund New York Mercantile Exchange (“NYMEX”) and Intercontinental Exchange (“ICE”) margin requirements. In certain market conditions, these routine short-term debt levels may increase above baseline levels. Similar to our working capital borrowings, these borrowings are self-liquidating. We do not consider the working capital borrowings or margin requirements associated with these activities to be part of our long-term capital structure.

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Values and Sustainability

Our Core Values include Safety and Environmental Stewardship, Accountability, Ethics and Integrity and Respect and Fairness. Our Code of Business Conduct sets forth the ways in which these Core Values govern how we conduct ourselves and engage in business relationships. Additional information regarding our Core Values and our commitment to environmental and social responsibility is available in the Sustainability section of our website. See “—Available Information” below.

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.

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. Past experience has demonstrated that discussions and negotiations regarding a potential transaction can advance or terminate in a short period of time. Moreover, the closing of any transaction for which we have entered into a definitive agreement may be subject to customary and other closing conditions, which may not ultimately be satisfied or waived. Accordingly, we can give no assurance that our current or future efforts with respect to any such transactions will be successful, and we can provide no assurance that our financial expectations with respect to such transactions will ultimately be realized. See Item 1A. “Risk Factors—Risks Related to Our Business—Divestitures, joint ventures, joint ownership arrangements and acquisitions involve risks that may adversely affect our business.”

Joint Venture and Joint Ownership Arrangements

We are party to over 25 joint venture (“JV”) and undivided joint interest (“UJI”) arrangements with long-term partners throughout the industry value chain spanning across multiple North American basins. We believe that these capital-efficient arrangements provide strategic alignment with long-term industry partners, adding volume commitments to the systems and improving returns.

The following table summarizes our significant JVs as of December 31, 2020:

Entity (1) Type of Operation JVOwnershipPercentage

BridgeTex Pipeline Company, LLC Crude Oil Pipeline 20%

Cactus II Pipeline LLC Crude Oil Pipeline (2) 65%

Capline Pipeline Company LLC Crude Oil Pipeline (3) 54%

Diamond Pipeline LLC Crude Oil Pipeline (2) 50%

Eagle Ford Pipeline LLC Crude Oil Pipeline (2) 50%

Eagle Ford Terminals Corpus Christi LLC Crude Oil Terminal and Dock (2) 50%

Red River Pipeline Company LLC (4) (5) Crude Oil Pipeline (2) 67%

Saddlehorn Pipeline Company, LLC (4) Crude Oil Pipeline 30%

STACK Pipeline LLC Crude Oil Pipeline (2) 50%

White Cliffs Pipeline, LLC Crude Oil Pipeline 36%

Wink to Webster Pipeline LLC (4) Crude Oil Pipeline 16%

(1)Except for Eagle Ford Terminals, which is reported in our Facilities segment, the financial results from the entities are reported in our Transportation segment.

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(2)Asset is operated by Plains.

(3)The Capline pipeline was taken out of service pending the reversal of the pipeline system.

(4)Entity owns a UJI in the crude oil pipeline.

(5)We consolidate Red River Pipeline Company LLC based on control, with our partner’s 33% interest accounted for as a noncontrolling interest.

The following table summarizes our significant UJIs as of December 31, 2020, excluding UJIs that are indirectly owned by us through JVs (e.g., Wink to Webster, Saddlehorn and Red River JVs):

Asset Operating Segment Type ofOperation UJIOwnershipPercentage

Basin Pipeline (1) Transportation Crude Oil Pipeline 87%

Empress Processing (2) Facilities NGL Facility 50% to 88%

Western Corridor System (2) Transportation Crude Oil Pipeline 21% to 58%

Sarnia NGL Storage and Fractionation (2) Facilities NGL Facility 62% to 84%

Sunrise II Pipeline (1) Transportation Crude Oil Pipeline 80%

(1)Asset is operated by Plains.

(2)Certain of these assets are operated by Plains.

Acquisitions

Since our initial public offering in 1998, the acquisition of midstream assets and businesses has been an important component of our business strategy. Over the last five years, we completed several acquisitions for an aggregate of approximately $2.0 billion, the majority of which related to an acquisition in 2017. While the pace of our acquisition activity has slowed down in recent years, we continue to selectively analyze and pursue assets and businesses that are strategic and complementary to our existing operations.

Divestitures

In 2016, we initiated a program to evaluate potential sales of non-core assets and/or sales of partial interests in assets to strategic joint venture partners to optimize our asset portfolio and strengthen our balance sheet and leverage metrics. Through December 31, 2020, we have completed asset sales totaling more than $3 billion.

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Investment Capital Projects

Our extensive asset base and our relationships with long-term industry partners across the value chain provide us with opportunities for organic growth through the construction of additional assets that are complementary to, and expand or extend, our existing asset base. Our 2021 capital plan consists of capital-efficient, highly contracted projects that help address industry needs. Substantially all of the capital will be invested in our fee-based Transportation and Facilities segments. The following investment capital projects are included in our 2021 capital plan as of February 2021:

Project Description ProjectedIn-Service Date 2021 PlanAmount (1)($ in millions)

Total Projected Investment Capital Expenditures (1) $ 425

(1)Represents the portion of the total project cost expected to be incurred during the year. Potential variation to current capital costs estimates may result from (i) changes to project design, (ii) final cost of materials and labor and (iii) timing of incurrence of costs due to uncontrollable factors such as receipt of permits or regulatory approvals and weather.

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Global Petroleum Market Overview and Fundamental Themes

Current Global Petroleum Market Conditions

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 2016:

Global Petroleum and Other Liquids Supply / Demand Balance (1)

(in millions of barrels per day)

(1)Average barrels produced and consumed per quarter.

Source: U.S. Energy Information Administration (“EIA”), Short-Term Energy Outlook, February 2021

In 2019, global demand for crude oil and other petroleum liquids worldwide averaged approximately 101 million barrels per day and since the year 2000 had grown at an average annual rate of approximately 1.0 to 1.5 million barrels per day. The largest drivers of demand growth were increases in population and rising standards of living in developing nations, particularly in Asia.

In 2020, global demand for crude oil and other petroleum liquids worldwide averaged approximately 92 million barrels per day, representing a significant decrease compared to 2019 as a result of the COVID-19 pandemic. As countries around the globe implemented government mandated shutdowns, demand for refined products such as gasoline, diesel and jet fuel significantly decreased resulting in global crude oil and other petroleum liquids demand falling to approximately 81 million barrels per day in April of 2020.

As global demand decreased, inventories began to build and global crude oil prices reached historic lows. Global supply responded in an attempt to rebalance the market as OPEC enacted production cuts, and North American producers shut-in production and greatly reduced capital spending, leading to a 75% reduction in Lower 48 onshore rig count versus the March 2020 peak and an excess of infrastructure in every major North American producing basin.

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Both the EIA and OPEC currently forecast that global crude oil demand will recover to or near pre-COVID-19 levels by year end 2021. The global retrenchment of capital in both long-cycle and short-cycle supply combined with natural declines may put a constraint on the ability of producers to meet a meaningful recovery in demand. When demand does recover, there may be a need for incremental supply, and United States short-cycle shale is well positioned to meet this need. In the meantime, we as an industry must focus on rationalization and optimization of the existing infrastructure base while ensuring the ability to serve future growth of both supply and demand. Similar to crude oil, we expect demand for NGL to increase as the world population increases and as the population in developing nations seek to improve their quality of life. In addition, the resource base and the existing logistical infrastructure in North America is well situated to supply a meaningful portion of the expected increase in demand for NGL.

Crude Oil Market Overview

Crude oil is a global commodity that serves as feedstock for many of the world’s essential refined products such as transportation fuels (gasoline, diesel, jet fuel) and heating oil, among others. While commodities are typically considered unspecialized, mass-produced and fungible, crude oil is neither unspecialized nor fungible. The crude slate available to North American and world-wide refineries consists of a substantial number of different grades and varieties. Each crude oil grade has distinguishing physical properties. For example, specific gravity (generally referred to as light or heavy), sulfur content (generally referred to as sweet or sour) and metals content, along with other characteristics, collectively result in varying economic attributes. In many cases, these factors result in the need for such grades to be batched or segregated in the transportation and storage processes, blended to precise specifications or adjusted in value.

The lack of fungibility of the various grades of crude oil creates logistical transportation, terminalling and storage challenges and inefficiencies associated with regional volumetric supply and demand imbalances. These logistical inefficiencies are created as certain qualities of crude oil are indigenous to particular regions or countries. Also, each refinery has a distinct configuration of process units designed to handle particular grades of crude oil. The relative yields and the cost to obtain, transport and process the crude oil drive the refinery’s choice of feedstock.

We designed a business model to integrate large-scale supply aggregation capabilities with the ownership and operation of critical infrastructure systems that connect major producing regions (supply) to key demand centers (refineries) and export terminals. Our assets and our business strategy are designed to serve our producer and refiner customers by addressing regional crude oil supply and demand imbalances that exist in the United States and Canada. The nature and extent of supply and demand imbalances change from time to time as a result of a variety of factors, including global demand for exports; regional production declines and/or increases; refinery expansions, modifications and shut-downs; available transportation and storage capacity; and government mandates and related regulatory factors.

NGL Market Overview

NGL primarily includes ethane, propane, normal butane, iso-butane and natural gasoline, and is derived from natural gas production and processing activities, as well as crude oil refining processes. Liquefied petroleum gas (“LPG”) primarily includes propane and butane, which liquefy at moderate pressures making it easier to transport and store than ethane. NGL refers to all NGL products including LPG when used in this Form 10-K.

NGL is the primary feedstock for petrochemical facilities that produce many of the everyday consumer products used in the world. Individual NGL products have varying uses. Described below are the five basic NGL components and their typical uses:

•Ethane (C2). Ethane accounts for the largest portion of the NGL barrel and substantially all of the extracted ethane is used as feedstock in the production of ethylene, one of the basic building blocks for a wide range of plastics and other chemical products. When ethane recovery from a wet natural gas stream is uneconomic, ethane is left in the natural gas stream, subject to pipeline specifications.

•Propane (C3). Propane is used as heating fuel, engine fuel and industrial fuel, for agricultural burning and drying and also as petrochemical feedstock for the production of ethylene and propylene.

•Normal butane (C4). Normal butane is principally used for motor gasoline blending and as fuel gas, either alone or in a mixture with propane, and feedstock for the manufacture of ethylene and butadiene, a key ingredient of synthetic rubber. Normal butane is also used as a feedstock for iso-butane production and as a diluent in the transportation of heavy crude oil and bitumen, particularly in Canada.

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•Iso-butane. Iso-butane is principally used by refiners to produce alkylates to enhance the octane content of motor gasoline.

•Natural Gasoline. Natural gasoline is principally used as a motor gasoline blend stock, a petrochemical feedstock, or as diluent in the transportation of heavy crude oil and bitumen, particularly in Canada.

We source NGL supply from field processing plants that are connected to our Cochrane-to-Edmonton (“Co-Ed”) system and other third-party pipelines that deliver NGL to our storage and processing assets in the Fort Saskatchewan area in Canada, and large processing plants located near Empress, Canada. These plants straddle the TransCanada pipeline system which is a mainline carrier of pipeline quality gas and primarily extract ethane that feeds local petrochemical facilities, and to a lesser extent extract NGL, which can be processed at our Empress or Sarnia fractionators.We expect NGL supply to grow with increased natural gas production in Western Canada when TransCanada completes the expansion of its mainline system in 2021.

Natural Gas Storage Market Overview

North American natural gas storage facilities provide a staging and warehousing function for seasonal swings in demand relative to supply, as well as an essential reliability cushion against disruptions in natural gas supply, demand and transportation by allowing natural gas to be injected into, withdrawn from or warehoused in such storage facilities as dictated by market conditions. Natural gas storage serves as a “shock absorber” that balances the market, serving as a source of supply to meet the consumption demands in excess of daily production capacity and a warehouse for gas when production exceeds daily demand.

Overall market conditions for natural gas storage appear to be improving as several fundamental factors are contributing to growth in North American natural gas demand. These factors include (i) increasing exports of LNG from North America, (ii) increasing exports of natural gas to Mexico, (iii) construction of new natural gas-fired power plants, (iv) sustained fuel switching from coal to natural gas among existing power plants and (v) growth in base-level industrial demand. The increase in both supply and demand has created greater opportunities for natural gas storage operations.

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Description of Segments and Associated Assets

Our business activities are conducted through three segments—Transportation, Facilities and Supply and Logistics. We have an extensive network of pipeline transportation, terminalling, storage and gathering assets in key crude oil and NGL producing basins and transportation corridors and at major market hubs in the United States and Canada. The map and descriptions below highlight our more significant assets (including certain assets under construction or development) as of December 31, 2020. Unless the context requires otherwise, references herein to our “facilities” includes all of the pipelines, terminals, storage and other assets owned by us.

Following is a description of the activities and assets for each of our three business segments.

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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. We generate revenue through a combination of tariffs, pipeline capacity agreements and other transportation fees. Our Transportation segment also includes equity earnings from our investments in entities that own or are developing transportation assets. We account for these investments under the equity method of accounting. See Note 9 to our Consolidated Financial Statements for additional information regarding these investments.

As of December 31, 2020, we employed a variety of owned or, to a much lesser extent, leased long-term physical assets throughout the United States and Canada in this segment, including approximately:

•18,370 miles of active crude oil and NGL pipelines and gathering systems;

•35 million barrels of active, above-ground tank capacity used primarily to facilitate pipeline throughput and help maintain product quality segregation; and

•815 trailers (primarily in Canada).

The following is a tabular presentation of our active crude oil and NGL pipeline assets in the United States and Canada as of December 31, 2020, grouped by geographic location:

(in thousands)

Crude Oil Pipelines:

Permian Basin:

Crude Oil and NGL Pipelines Total 18,370 6,266

(1)Includes total mileage of pipelines in which we own less than 100%.

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(2)Represents average daily volumes for the entire year attributable to our interest. 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. Volumes reflect tariff movements and thus may be included multiple times as volumes move through our integrated system.

(3)Includes pipelines operated by a third party.

A significant portion of our pipeline assets are interconnected and are operated as a contiguous system. The following descriptions are organized by type and geographic location and represent a selection of our most significant assets. Pipeline capacities throughout these descriptions are based on our reasonable estimate of volumes that can be delivered from origin to final destination on our pipeline systems. We report pipeline volumes based on the tariffs charged for individual movements, some of which may only utilize a certain segment of a pipeline system (i.e. two short-haul movements on a pipeline from point A to point B and another from point B to point C would double the pipeline tariff volumes on a particular system versus a single point A to point C movement). As a result, at times, our reported tariff barrel movements may exceed our total capacity.

Crude Oil Pipelines

Our crude oil pipelines are comprised of:

•gathering pipelines that move crude oil from wellhead or central battery connections to regional market hubs;

•intra-basin pipelines that are used as a hub system creating a significant amount of flexibility by creating connections between regional hub locations; and

•long-haul pipelines that move crude oil from (i) regional market hubs to major market hubs such as Cushing, Oklahoma or to export facilities, including our Corpus Christi terminal or (ii) major market hubs to a refinery.

Gathering Pipelines

Permian Basin. We own and operate over 3,200 miles of gathering pipelines in both the Midland Basin and the Delaware Basin that in aggregate represent over 2.5 million barrels per day of pipeline capacity. This gathering capacity includes pipeline capacity that delivers volumes to regional market hubs. Approximately 75% of the capacity of our gathering systems is in the Delaware Basin.

Central. We own and operate gathering pipelines that source crude oil from Western and Central Oklahoma and Southwest Kansas for transportation and delivery into our terminal facilities at Cushing, Oklahoma.

Rocky Mountain. We own and operate pipelines that provide gathering services in the Bakken and the Powder River Basin.

Western. We own and operate a pipeline in the San Joaquin Valley that gathers locally produced crude oil, which is then delivered via our Line 63 pipeline system and/or Line 2000 pipeline for transportation to Los Angeles area refiners.

Canada. We own and operate gathering systems with capacity of approximately 220,000 barrels per day. These gathering systems source crude from truck terminals and pipeline connected facilities to deliver to the Enbridge Mainline system at our Kerrobert and Regina terminals in Saskatchewan.

Intra-basin Pipelines

Permian Basin. We own and operate an intra-basin pipeline system with a capacity of over 2 million barrels per day that connects gathering pipelines and truck injection volumes to our owned and operated as well as third-party mainline pipelines that transport crude oil to major market hubs. This interconnected pipeline system is designed to provide shippers flow assurance, flexibility and access to multiple markets.

Canada. We own and operate intra-basin pipelines with capacity of approximately 290,000 barrels per day that deliver crude from northern and southern Alberta to the Edmonton, Alberta market hub. These pipelines provide shippers with flexibility to access the Enbridge and TransMountain long-haul pipelines along with the Imperial Oil Refinery. In addition, we have three cross-border pipelines that have the flexibility to move up to approximately 60,000 barrels per day of Canadian crude oil to our Rocky Mountain area long-haul pipelines. These intra-basin pipelines also have the ability to deliver up to approximately 105,000 barrels per day of crude oil to third-party pipelines in the Rocky Mountain region.

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Long-haul Pipelines

Permian Basin. We own interests in multiple long-haul pipeline systems that, on a combined basis, represent over 1.5 million barrels per day of currently operational takeaway capacity (net to our ownership interests) out of the Permian Basin to major market hubs in Corpus Christi and Houston, Texas and Cushing, Oklahoma. Below is a description of some of our most significant long-haul pipeline systems within the Permian Basin region.

Permian to Cushing/Mid-Continent

•Basin Pipeline (Permian to Cushing). We own an 87% UJI in and are the operator of Basin Pipeline. Basin Pipeline has three primary origination locations: Jal, New Mexico; Wink, Texas; and Midland, Texas and, in addition to making intra-basin movements, serves as the primary route for transporting crude oil from the Permian Basin to Cushing, Oklahoma. Basin Pipeline also receives crude oil from a facility in southern Oklahoma which aggregates South Central Oklahoma Oil Province (SCOOP) production.

•Sunrise II Pipeline. We operate the Sunrise II Pipeline and, through a UJI arrangement, own 400,000 barrels of the capacity. Our Sunrise II Pipeline transports crude oil from Midland and Colorado City to connecting carriers at Wichita Falls.

Permian to Gulf Coast

•BridgeTex Pipeline (Permian to Houston). We own a 20% interest in the legal entity that owns the BridgeTex Pipeline, with two other partners. The pipeline, operated by a subsidiary of Magellan Midstream Partners, L.P., originates at Colorado City, Texas and extends to Houston, Texas. The pipeline has a capacity of 440,000 barrels per day and is capable of receiving supply from both our Basin and Midland South (formerly Sunrise) pipelines.

•Cactus Pipeline (Permian to Corpus Christi). We own and operate the Cactus Pipeline, which has a capacity of 390,000 barrels per day, originates at McCamey, Texas and extends to Gardendale, Texas. Cactus Pipeline volumes are interconnected to the Corpus Christi, Texas market through a connection at Gardendale to our Eagle Ford joint venture pipeline system.

•Cactus II Pipeline (Permian to Corpus Christi). We own a 65% interest in the legal entity that owns the Cactus II Pipeline (“Cactus II”), which we operate. Cactus II is a Permian mainline system that extends directly to the Corpus Christi, Texas market, and has a capacity of 670,000 barrels per day.

•Wink to Webster Pipeline. We own a 16% interest in the legal entity that owns the Wink to Webster Pipeline (“W2W Pipeline”), which in turn owns 100% of certain segments of the W2W Pipeline and a 71% UJI in the segment from Midland, Texas to Webster, Texas. The W2W Pipeline originates in the Permian Basin in West Texas and transports crude oil to multiple destinations in the Houston and Galveston market areas. The pipeline system, which is currently in partial service, will provide approximately 1.5 million barrels per day of crude oil capacity (1.1 million barrels per day, net to the UJI interest) and is supported by long-term shipper commitments. Phase one of the pipeline system from Midland, Texas to Webster, Texas is currently in service. Phase two, which increases the pipeline system to 1.5 million barrels per day of capacity, is expected to be in service in the fourth quarter of 2021, at which time long-term shipper commitments will become effective. The third phase of the project, which includes the segments from Wink, Texas to Midland, Texas and from Webster, Texas to Baytown, Texas, has been deferred by the partners until the fourth quarter of 2023.

South Texas/Eagle Ford. We own a 50% interest in the legal entity that owns the Eagle Ford Pipeline through a joint venture with a subsidiary of Enterprise. We serve as the operator of the Eagle Ford Pipeline, which has a total capacity of approximately 660,000 barrels per day and connects Permian and Eagle Ford area production to Corpus Christi, Texas refiners and terminals. Additionally, the Eagle Ford Pipeline has connectivity to Houston, Texas via a connection with Enterprise’s pipeline at Lyssy, Texas.

Central. We own and operate various pipeline systems that extend from our Cushing terminal in Oklahoma to various refineries and/or crude oil hubs. Below is a description of some of our most significant pipeline systems in the Central region.

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•Diamond Pipeline(Cushing to Memphis). We own a 50% interest in the legal entity that owns the Diamond Pipeline through a joint venture with Valero Energy Corporation (“Valero”). We operate the Diamond Pipeline, which extends from our Cushing Terminal to Valero’s refinery in Memphis, Tennessee. The Diamond Pipeline is underpinned by a long-term minimum volume commitment and currently has a total capacity of 200,000 barrels per day. Following the successful 2019 open season on the Capline Pipeline system (“Capline”), the joint venture partners sanctioned an expansion and modest extension of the Diamond Pipeline that will expand its capacity to approximately 420,000 barrels per day, connect it to Capline and facilitate the movement of volumes from Cushing, Oklahoma to St. James, Louisiana.

•Red River Pipeline (Cushing to Longview). The Red River Pipeline is an approximately 235,000 barrel per day capacity pipeline that extends from our Cushing Terminal in Oklahoma to Longview, Texas, where it connects with various pipelines. The Red River Pipeline is supported by long-term shipper commitments and we serve as operator. In May 2019, we announced a new joint venture of the Red River Pipeline. Delek Logistics Partners, LP (“Delek”) purchased a 33% ownership interest in the new Red River Pipeline Company LLC (“Red River JV”) joint venture and we retained a 67% interest. In 2020, we put into service an expansion that enables additional volume pull-through from Cushing, Oklahoma and the Permian to the U.S. Gulf Coast markets, providing additional supply optionality for shippers. In support of this expansion, Delek increased its long-term throughput and deficiency agreement on the Red River Pipeline system from an existing 35,000 barrels per day to 100,000 barrels per day. The Red River JV has an approximate 69% UJI in the pipeline segment from Cushing to Hewitt and owns 100% of the segment of the pipeline extending from Hewitt to Longview.

Rocky Mountain. Our pipeline systems in the Rocky Mountain region provide access to our terminal in Cushing, Oklahoma as well as other major market hubs. We own and operate the Bakken North pipeline system that accommodates bidirectional flow and can move crude oil from the Bakken to the Enbridge Mainline system at Regina, Saskatchewan or from the Enbridge Mainline system to our terminal in Trenton, North Dakota. We own a UJI in a pipeline system that extends from the Canadian border to our terminal in Guernsey, Wyoming. This pipeline system receives crude oil from our Rangeland and Milk River Pipelines in Canada. In addition to these assets, our largest Rocky Mountain area systems include the following joint venture pipelines, both of which connect to our terminal in Cushing, Oklahoma.

•Saddlehorn Pipeline. We own a 30% interest in the legal entity that owns the Saddlehorn Pipeline and, through a UJI arrangement, owns 290,000 barrels per day of capacity in the Saddlehorn Pipeline, which includes a recent expansion of 100,000 barrels per day. The pipeline extends from the Niobrara and Denver-Julesburg (“DJ”) Basin to Cushing and is operated by Magellan. The Saddlehorn Pipeline is supported by minimum volume commitments.

•White Cliffs Pipeline. We own an approximate 36% interest in the entity that owns the White Cliffs Pipeline system through a joint venture with three other partners. The White Cliffs Pipeline system consists of one crude oil pipeline with approximately 100,000 barrels per day of capacity that extends from the DJ Basin to Cushing, Oklahoma and one NGL pipeline with approximately 90,000 barrels per day of capacity that extends from the DJ Basin to a tie-in location with the Southern Hills Pipeline in Oklahoma. The NGL pipeline is supported by a long-term capacity lease and long-term throughput agreements. A subsidiary of Energy Transfer LP serves as the operator of the pipelines.

Western. We own and operate the Line 63 and Line 2000 pipelines in California. Line 2000 is a mainline system that has the capacity to transport approximately 110,000 barrels per day from the San Joaquin Valley to refineries and terminal facilities in the Los Angeles area. Line 63 is used as a gathering and distribution system. The pipeline gathers crude oil in the San Joaquin Valley for delivery to Line 2000 and local refiners. In the Los Angeles area, the Line 63 distribution lines are used to move crude oil from Line 2000 to local refiners.

Canadian NGL Pipelines

Supply lines. Our supply lines transport NGL from producing locations to downstream processing facilities. Our primary supply system, the Co-Ed NGL pipeline system, has transportation capacity of approximately 70,000 barrels per day and gathers NGL from Southwest and Central Alberta (Cardium, Deep Basin, and Alberta Montney) for delivery to our Fort Saskatchewan, Alberta NGL fractionation facilities. In addition, we own a 50% UJI in a supply line with capacity of approximately 50,000 barrels per day that carries NGL from our Empress, Alberta fractionation facility to cavern storage assets in Kerrobert, Saskatchewan.

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Market lines. Market lines are typically used to transport NGL from production locations to further downstream market distribution and storage terminals. We own and operate one market pipeline, the Plains Petroleum Transmission Company (“PPTC”) pipeline system, which has approximately 15,500 barrels per day of capacity. The pipeline extends from our Empress, Alberta fractionation facility to our Fort Whyte terminal in Winnipeg, Manitoba. The pipeline also delivers NGL to various terminals and rail loading facilities along the pipeline system.

Hub lines. Hub lines connect regional hub locations, such as processing assets to storage and petrochemical facilities. We own and operate hub lines in eastern Canada with approximately 130,000 barrels per day of capacity that transport propane and butane from our Sarnia, Ontario fractionation facility to our St. Clair, Michigan and Windsor, Ontario storage, rail and truck terminals, as well as third-party locations, and ethane from the Kinder Morgan Utopia pipeline to Nova Chemicals’ Corunna petrochemical complex in Sarnia, Ontario.

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. We generate revenue through a combination of month-to-month and multi-year agreements and processing arrangements.

Revenues generated in this segment include (i) storage and throughput fees at our crude oil, NGL and natural gas storage facilities, (ii) fees from natural gas and condensate processing services and from NGL fractionation and isomerization services and (iii) loading and unloading fees at our rail terminals.

As of December 31, 2020, we owned, operated or employed a variety of long-term physical assets throughout the United States and Canada in this segment, including:

•approximately 75 million barrels of crude oil storage capacity primarily at our terminalling and storage locations;

•approximately 28 million barrels of NGL storage capacity;

•approximately 68 billion cubic feet (“Bcf”) of natural gas storage working gas capacity;

•approximately 26 Bcf of owned base gas;

•five natural gas processing plants located throughout Canada and the Gulf Coast area of the United States;

•a condensate processing facility located in the Eagle Ford area of South Texas with an aggregate processing capacity of approximately 120,000 barrels per day;

•eight fractionation plants located throughout Canada and the United States with an aggregate net processing capacity of approximately 206,500 barrels per day, and an isomerization and fractionation facility in California with an aggregate processing capacity of approximately 15,000 barrels per day;

•22 crude oil and NGL rail terminals located throughout the United States and Canada;

•five marine facilities in the United States; and

•approximately 330 miles of active pipelines that support our facilities assets.

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The following discussion contains a detailed description of our more significant Facilities segment assets.

Crude Oil Storage and Terminalling Facilities

Our largest crude oil terminals are located in key market hubs, including Cushing, Oklahoma, St. James, Louisiana, Midland, Texas and Patoka, Illinois, and have connectivity to all major inbound and outbound pipelines and other terminals at these hubs.

We are the largest provider of crude oil terminalling services in Cushing, Oklahoma, which is one of the largest physical trading hubs in the United States and is the delivery point for crude oil futures contracts traded on the NYMEX. Our Cushing Terminal has been designated by the NYMEX as an approved delivery location for crude oil delivered under the NYMEX light sweet crude oil futures contract.

Our Cushing terminal is connected to our long-haul pipelines from the Permian Basin and Rocky Mountain regions, as well as to our Central region gathering pipelines. Additionally the terminal supplies crude oil to all four of our joint venture, Central region long-haul pipelines.

Our Midland terminal has access to all of our Permian Basin gathering pipelines, either through direct connections, or through our intra-basin pipelines in the Permian Basin. Likewise, the terminal is also either directly connected, or connected through our intra-basin pipelines to all four of our Permian Basin long-haul pipelines.

Our terminals at Corpus Christi, Texas, St. James, Louisiana and Mobile, Alabama all have docks and the capacity to export crude oil. In addition, our St James terminal has a rail unload facility that can move crude from rail cars to pipelines that service local refiners, or to our dock for export.

Our Patoka and St. James terminals are both connected to Capline pipeline, and the terminals will be a receipt and destination facility, respectively, once Capline is placed into service in 2022.

Our crude oil terminals have significant flexibility and operational capabilities, including large-scale multi-grade handling and segregation capabilities and multiple marine transportation loading and unloading capabilities. The table below presents our crude oil storage capacity by location as of December 31, 2020:

Crude Oil Storage Facilities Total Capacity(MMBbls)

St. James 15

Patoka 7

Permian Basin Area 8

Mobile and Ten Mile 5

Corpus Christi (1) 1

(1)We own 50% of this storage capacity through our investment in Eagle Ford Terminals Corpus Christi LLC.

(2)Amount includes approximately 2 million barrels of storage capacity associated with our crude oil rail terminal operations.

NGL Storage, Fractionation and Isomerization and Natural Gas Processing Facilities

We have a large integrated network of NGL storage and fractionation and natural gas processing facilities throughout Canada, as well as NGL storage and fractionation facilities in the United States. The tables below present volumes and capacities for these facilities as of December 31, 2020 and our most significant assets are described further below.

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NGL Storage Facilities Total Capacity(MMBbls)

Fort Saskatchewan 11

Sarnia Area 7

Empress Area 4

Other 6

United States Gulf Coast Area 100 % 0.2 0.3

(1)Represents average volumes net to our share for the entire year.

(2)While natural gas processing volumes are presented, they are not indicative of revenues generated by these assets as fees associated with our natural gas processing activities are generally fixed.

Fort Saskatchewan. The Fort Saskatchewan facility is located near Edmonton, Alberta in one of the key North American NGL hubs. The facility is a receipt, storage, fractionation and delivery facility for NGL and is connected to other major NGL plants and pipeline systems in the area. The facility’s primary assets include 28 storage caverns. The facility includes assets operated by us and assets operated by a third party. Our ownership in the various facility assets ranges from approximately 21% to 100%. Our Fort Saskatchewan fractionation facility has a design capacity of 85,000 barrels per day and is able to produce up to approximately 50,000 barrels per day of spec propane, butane and condensate. The remaining capacity is used to produce a propane and butane mix, which is sent to our Sarnia facility for further fractionation. Through our 21% ownership in the Keyera Fort Saskatchewan fractionation plant, we have additional fractionation capacity of approximately 17,300 barrels per day.

Sarnia Area. Our Sarnia Area facilities in Southwestern Ontario consist of (i) our Sarnia facility, (ii) our Windsor storage terminal and (iii) our St. Clair, Michigan terminal. The Sarnia facility is a large NGL fractionation and storage facility located in the Sarnia Chemical Valley that contains multiple rail and truck loading spots. The Sarnia Area facilities are served by a network of multiple pipelines connected to various refineries, chemical plants and other pipeline systems in the area. This pipeline network also delivers product between our Sarnia facility and our Windsor storage terminal in addition to the delivery capability from our Sarnia facility to our St. Clair terminal. The Sarnia Fractionator is the largest fractionation plant in Eastern Canada and receives NGL feedstock primarily from the Enbridge pipeline system. The fractionation unit is able to produce approximately 120,000 barrels per day of spec NGL products. Our ownership in the various processing units at the Sarnia Fractionator ranges from 62% to 84%.

Empress Area. We own and/or operate four straddle plants located in the Empress Area, capable of processing up to 6.0 Bcf of natural gas per day, however, supply available to these plants are typically in the 2.5 to 3.5 Bcf per day range. These plants produce approximately 30,000 to 40,000 barrels per day of NGL which can be fractionated at either our Empress or Sarnia fractionators. Our Empress fractionation facility is capable of processing and producing up to 23,300 barrels per day of spec NGL products and is connected to our PPTC pipeline system.

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Other. We have a long-term liquids supply and profit sharing contract with a third-party owned straddle plant, near Cochrane, Alberta, with gross processing capacity of approximately 2.5 Bcf per day. NGL produced from this facility are transported on our Co-Ed pipeline system to our Fort Saskatchewan area assets, and then to our Sarnia fractionator via the Enbridge pipeline system. In addition, we own a facility located near Bakersfield, California that provides approximately 15,000 barrels per day of isomerization and fractionation services to producers and customers.

Natural Gas Storage Facilities

We own two natural gas storage facilities with an aggregate commercial working gas capacity of approximately 68 Bcf in service as of December 31, 2020. Our natural gas storage facilities are strategically located within the Gulf Coast market and have a diverse group of customers, including liquefied natural gas (“LNG”) exporters, utilities, pipelines, producers, power generators and marketers whose storage needs vary from traditional seasonal storage services to hourly balancing. We are located near several major market hubs and our facilities have multiple physical interconnects with third-party interstate pipelines, intrastate pipelines and direct connect customers, serving markets in the Gulf Coast, Mid-Atlantic, Northeast, and Southeast regions of the United States.

Condensate Processing Facility

Our Gardendale condensate processing facility is located in La Salle County, Texas. The facility stabilizes condensate that is primarily sourced from our Eagle Ford area gathering systems. The NGL extracted at this facility is delivered to a third-party pipeline that delivers the NGL to Mont Belvieu, Texas. The facility has a total processing capacity of 120,000 barrels per day and usable storage capacity of 160,000 barrels. Throughput at the Gardendale processing facility is supplied by long-term commitments from producers.

Crude Oil Rail Facilities

We own crude oil rail loading facilities located at or near Carr, Colorado; Tampa, Colorado; Manitou, North Dakota; and Kerrobert, Saskatchewan. We own crude oil rail unloading facilities in St. James, Louisiana, Yorktown, Virginia and Bakersfield, California. The table below presents aggregate loading and unloading capacity for these facilities as of December 31, 2020:

Ownership Interest LoadingCapacity (Bbls/d) UnloadingCapacity (Bbls/d)

NGL Rail Facilities

We own 18 operational NGL rail facilities (including our Fort Saskatchewan rail facility, as well as facilities that can provide both crude oil and NGL service) strategically located near our NGL facilities as well as third-party distribution centers throughout Canada and the United States. Our NGL rail terminals are predominately utilized for internal purposes specifically for our supply and logistics activities. See our “Supply and Logistics Segment” discussion following this section for further discussion regarding the use of our rail terminals. The table below presents additional information regarding our NGL rail facilities as of December 31, 2020:

Ownership Interest Number ofRack Spots Number ofStorage Spots

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Supply and Logistics Segment

Our Supply and Logistics segment activities include the purchase, logistics and resale of crude oil and NGL in North America. Through these transactions, we seek to maintain a position that is substantially balanced between purchases and sales and future delivery obligations. The segment owns a significant volume of crude oil and NGL required to conduct our commercial activities. The crude oil and NGL used to support our ongoing commercial activities is classified as long-term assets and linefill or minimum inventory requirements. A summary of the assets employed to support our commercial activities, December 31, 2020, include approximately:

•16 million barrels of crude oil and NGL linefill in pipelines owned by us;

•4 million barrels of crude oil and NGL utilized as linefill in pipelines owned by third parties or otherwise required as long-term inventory;

•680 trucks and 840 trailers; and

•6,000 crude oil and NGL railcars.

Our crude oil activities generally include the purchase of crude oil at the wellhead or at central tank batteries typically owned by the crude oil producer. We may also purchase crude oil at market hubs, such as our Cushing terminal, or in-transit in a pipeline. We typically transport our crude oil supply to market hub locations, or directly to refiners using our pipeline or trucking assets and, to a lesser extent, pipelines owned by third parties. We may also optimize the value of our supply by executing exchanges with third parties, where we may exchange qualities of crude oil or the location of our crude oil, and we would either pay or receive a fee for the differential in value for the quality or location of the crude oil. We may use derivative instruments such as the NYMEX futures market to hedge our exposure to crude oil prices. We also hedge the currency differential between the U.S. and Canadian dollar for crude oil purchased on a Canadian dollar basis and sold on a U.S. dollar basis.

Our crude oil supplies are typically sold to refiners, crude oil exporters, traders or other market participants. All crude oil sales arrangements are subject to credit approval. In certain circumstances, where the market value for prompt deliveries of crude oil is discounted to the value for deferred delivery (such conditions are referred to as a “Contango Market”) we may store crude oil in tanks included in our Facilities or Transportation segments and use a NYMEX futures contract to hedge the value of the stored crude oil.

Our NGL activities include the purchase of both NGL and the spec components propane and butane (“spec products”). Our NGL supply is typically sourced at our Empress facility, where we acquire the rights to extract NGL from producers and/or shippers of the gas streams that pass through our Empress facility. The extraction rights that we acquire allow us to process that gas at our Empress facility and extract the higher valued NGL from the gas stream. We then purchase natural gas to replace the thermal content attributable to the NGL that was extracted. Our NGL supply at Empress is then either fractionated into spec products at our Empress fractionator, or transported on a third-party pipeline and fractionated into spec products at our Sarnia fractionator. Often times we will use derivative instruments to hedge the differential between natural gas prices and the spec product prices to ensure that we are able to extract and fractionate NGL, and deliver spec products to markets at a profitable margin.

We also acquire spec products from third parties. The majority of the spec products we purchase are at the end (“tailgate”) of our Fort Saskatchewan fractionator; however, we may also purchase butane from refiners and propane and/or butane from third-party processors. Some of the spec product we purchase at Fort Saskatchewan is combined into a propane/butane mix and transported on a third-party pipeline to our Sarnia fractionator. The spec products that we own are transported by pipeline, rail or truck and either delivered to one of our storage facilities, or delivered and sold to a third party. Similar to our crude oil activities, spec products may be profitably stored when there is a Contango Market. The value of the stored product is hedged using various derivative instruments.

Credit. Our supply and logistics activities require significant extensions of credit by our suppliers. In order to assure our ability to perform our obligations under the purchase agreements, various credit arrangements are negotiated with our suppliers. These arrangements include open lines of credit and, to a lesser extent, standby letters of credit issued under our hedged inventory facility or our senior unsecured revolving credit facility. In addition, storing crude oil, NGL or spec products in a Contango Market, or otherwise, requires us to have credit facilities to finance both the purchase of these products in the prompt month as well as margin requirements that may be required for the derivative instruments used to hedge our price exposure.

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When we sell crude oil and NGL, we must determine the amount, if any, of credit to be extended to any given customer. Because our typical sales transactions can involve large volumes of crude oil, the risk of nonpayment and nonperformance by customers is a major consideration in our business. We believe our sales are made to creditworthy entities or entities with adequate credit support. We also have credit risk exposure related to our sales of NGL (principally propane); however, because our sales are typically in relatively small amounts to individual customers, we do not believe that these transactions pose a material concentration of credit risk. Typically, we enter into annual contracts to sell NGL on a forward basis, as well as to sell NGL on a current basis to local distributors and retailers. In certain cases our NGL customers prepay for their purchases, in amounts ranging up to 100% of their contracted amounts. See Note 3 to our Consolidated Financial Statements for further discussion of our credit review process and risk management procedures.

The following table shows the average daily volume of our supply and logistics activities for the year ended December 31, 2020:

Volumes(MBbls/d)

Crude oil lease gathering purchases (1) 1,174

Supply and Logistics segment total volumes 1,318

(1)Of this amount, approximately 862 MBbls/d were purchased in the Permian Basin.

Impact of Commodity Price Volatility and Dynamic Market Conditions on Our Business Model

Crude oil, NGL and natural gas commodity prices have historically been very volatile. For example, in the last year, the prompt month NYMEX light, sweet futures contract (commonly referred to as “WTI”) price ranged from a low of approximately minus $38 per barrel to a high of approximately $63 per barrel. Similarly, there has also been volatility within the propane and butane markets as seen through the North American benchmark price located at Mont Belvieu, Texas, as well as with the basis differentials between Mont Belvieu prices and prices realized at various market hubs in North America.

While our objective is to position the Partnership such that our overall annual cash flow is not materially adversely affected by the absolute level of energy prices, market volatility associated with shifts between demand-driven markets and supply-driven markets or other similar dynamics has in the past, and may in the future create market conditions that are more challenging to our business model. In extended periods of lower crude oil and/or NGL prices, or periods where the supply and demand fundamentals compress regional location differentials, our financial results may be adversely impacted. In such market conditions, product flows on our pipelines in our Transportation segment may be adversely impacted and/or our Supply and Logistics segment may not fully recover its costs on certain transactions. Alternatively, in periods where supply exceeds regional demand and/or pipeline egress, product flows on our pipelines may be favorably impacted and/or our Supply and Logistics segment may be able to capture additional margins. In executing our business model, we employ a variety of financial risk management tools and techniques, predominantly in our Supply and Logistics segment. These are discussed in greater detail in the “—Risk Management” section below.

Relative contribution levels will vary from quarter-to-quarter due to seasonality, particularly with respect to our NGL activities in our Supply and Logistics segment. However, we expect that (absent material outperformance in our Supply and Logistics segment) our fee-based Transportation and Facilities segments should comprise more than 90% of our aggregate segment results.

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Risk Management

In order to hedge margins involving our physical assets and manage risks associated with our various commodity purchase and sale obligations and, in certain circumstances, to realize incremental margin during volatile market conditions, we use derivative instruments. We also use various derivative instruments to manage our exposure to interest rate risk and currency exchange rate risk. In analyzing our risk management activities, we draw a distinction between enterprise-level risks and trading-related risks. Enterprise-level risks are those that underlie our core businesses and may be managed based on management’s assessment of the cost or benefit of doing so. Conversely, trading-related risks (the risks involved in trading in the hopes of generating an increased return) are not inherent in our core business; rather, those risks arise as a result of engaging in trading activities. Our policy is to manage the enterprise-level risks inherent in our core businesses by using financial derivatives to protect our ability to generate cash flow and optimize asset profitability, rather than trying to profit from trading activity. Our commodity risk management policies and procedures are designed to monitor NYMEX, ICE and over-the-counter positions, as well as physical volumes, grades, locations, delivery schedules and storage capacity, to help ensure that our hedging activities address our risks. Our interest rate and currency exchange rate risk management policies and procedures are designed to monitor our derivative positions and ensure that those positions are consistent with our objectives and approved strategies. We have a risk management function that has direct responsibility and authority for our risk policies, related controls around commercial activities and procedures and certain other aspects of corporate risk management. Our risk management function also approves all new risk management strategies through a formal process. Our approved strategies are intended to mitigate and manage enterprise-level risks that are inherent in our core businesses.

Our policy is generally to structure our purchase and sales contracts so that price fluctuations do not materially affect our operating income, and not to acquire and hold physical inventory or derivatives for the purpose of speculating on outright commodity price changes. Although we seek to maintain a position that is substantially balanced within our supply and logistics activities, we purchase crude oil, NGL and natural gas from thousands of locations and may experience net unbalanced positions for short periods of time as a result of production, transportation and delivery variances as well as logistical issues associated with inclement weather conditions and other uncontrollable events that may occur. When unscheduled physical inventory builds or draws do occur, they are monitored constantly and managed to a balanced position over a reasonable period of time. This activity is monitored independently by our risk management function and must take place within predefined limits and authorizations.

Customers

Marathon Petroleum Corporation and its subsidiaries accounted for 13%, 12% and 14% of our revenues for the years ended December 31, 2020, 2019 and 2018, respectively. ExxonMobil Corporation and its subsidiaries accounted for 12%, 12% and 14% of our revenues for the years ended December 31, 2020, 2019 and 2018, respectively. Phillips 66 Company and its subsidiaries accounted for 11% of our revenues for the year ended December 31, 2019. No other customers accounted for 10% or more of our revenues during any of the three years ended December 31, 2020. The majority of revenues from these customers pertain to our supply and logistics operations. The sales to these customers occur at multiple locations and we believe that the loss of these customers would have only a short-term impact on our operating results. There is risk, however, that we would not be able to identify and access a replacement market at comparable margins. For a discussion of customers and industry concentration risk, see Note 16 to our Consolidated Financial Statements.

Competition

Competition among pipelines is based primarily on transportation charges, access to producing areas and supply regions and demand for crude oil and NGL by end users. Although new pipeline projects represent a source of competition for our business, there are also existing third-party owned pipelines with excess capacity in the vicinity of our operations that expose us to significant competition based on the relatively low operating cost associated with moving an incremental barrel of crude oil or NGL through such unutilized capacity. In areas where additional infrastructure is being built or has been built to accommodate new or increased production or changing product flows, we face competition in providing the required infrastructure solutions as well as the risk that capacity in the area will be overbuilt for the foreseeable future. As a result of multiple pipeline expansions that have occurred or are being completed in the Permian Basin and other areas, together with meaningful reductions in expected production growth due to COVID-19 impacts, we anticipate competition for uncommitted barrels and contract renewals and extensions will be amplified in the coming years, increasing our contract renewal and customer retention risk.

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In addition, depending upon the specific movement, pipelines, which generally offer the lowest cost of transportation, may also face competition from other forms of transportation, such as truck, rail and barge. Although these alternative forms of transportation are typically higher cost, they can provide access to alternative markets at which a higher price may be realized for the commodity being transported, thereby overcoming the increased transportation cost.

We also face competition with respect to our supply and logistics and facilities services. Our competitors include other crude oil and NGL pipeline and terminalling companies, other NGL processing and fractionation companies, the major integrated oil companies and their marketing affiliates, independent gatherers, private equity backed entities, banks that have established a trading platform, brokers and marketers of widely varying sizes, financial resources and experience. Some of these competitors have capital resources greater than ours. The addition of new pipelines supported by minimum volume commitments and/or acreage dedications could also amplify the level of competition for purchasing wellhead barrels, especially in the Permian Basin and thus impact our margins.

Regulation

Our assets, operations and business activities are subject to extensive legal requirements and regulations under the jurisdiction of numerous federal, state, provincial and local agencies. Many of these agencies are authorized by statute to issue, and have issued, requirements binding on the pipeline industry, related businesses and individual participants. The failure to comply with such legal requirements and regulations can result in substantial fines and penalties, expose us to civil and criminal claims, and cause us to incur significant costs and expenses. See Item 1A. “Risk Factors—Risks Related to Laws and Regulations—Our operations are subject to laws and regulations relating to protection of the environment and wildlife, operational safety, climate change and related matters that may expose us to significant costs and liabilities. The current laws and regulations affecting our business are subject to change and in the future we may be subject to additional laws, executive orders and regulations, which could adversely impact our business.” At any given time there may be proposals, provisional rulings or proceedings in legislation or under governmental agency or court review that could affect our business. The regulatory burden on our assets, operations and activities increases our cost of doing business and, consequently, affects our profitability. We can provide no assurance that the increased costs associated with any new or proposed laws, rules or regulations will not be material. We may at any time also be required to apply significant resources in responding to governmental requests for information and/or enforcement actions.

The following is a summary of certain, but not all, of the laws and regulations affecting our operations.

Health, Safety and Environmental Regulation

General

Our operations involving the storage, treatment, processing and transportation of liquid and gaseous hydrocarbons, including crude oil, are subject to stringent federal, state, provincial and local laws and regulations governing the discharge of materials into the environment or otherwise relating to protection of the environment, including wildlife. As with the industry generally, compliance with these laws and regulations increases our overall cost of doing business, including our capital costs to construct, maintain and upgrade equipment and facilities as regulations are updated or new regulations are invoked. Failure to comply with these laws and regulations could result in the assessment of administrative, civil and criminal penalties, the imposition of investigatory and remedial liabilities and the issuance of injunctions or other orders that may subject us to additional operational constraints. Failure to comply with these laws and regulations could also result in negative public perception of our operations or the industry in general, which may adversely impact our ability to conduct our business. Environmental and safety laws and regulations are subject to changes that may result in more stringent requirements, and we cannot provide any assurance that compliance with current and future laws and regulations will not have a material effect on our results of operations or earnings. A discharge of hazardous liquids into the environment could, to the extent such event is not insured, subject us to substantial expense, including both the cost to comply with applicable laws and regulations and any claims made by third parties. The following is a summary of some of the environmental, health and safety laws and regulations to which our operations are subject.

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Pipeline Safety/Integrity Management

A substantial portion of our petroleum pipelines and our storage tank facilities in the United States are subject to regulation by the Department of Transportation’s (“DOT”) Pipeline and Hazardous Materials Safety Administration (“PHMSA”) pursuant to the Hazardous Liquids Pipeline Safety Act of 1979, as amended (the “HLPSA”). The HLPSA imposes safety requirements on the design, installation, testing, construction, operation, replacement and management of pipeline and tank facilities. Federal regulations implementing the HLPSA require pipeline operators to adopt measures designed to reduce the environmental impact of oil discharges from onshore oil pipelines, including the maintenance of comprehensive spill response plans and the performance of extensive spill response training for pipeline personnel. These regulations also require pipeline operators to develop and maintain a written qualification program for individuals performing covered tasks on pipeline facilities. Comparable regulation exists in some states in which we conduct intrastate common carrier or private pipeline operations. Regulation in Canada is under the Canada Energy Regulator (“CER”), formerly the National Energy Board, and provincial agencies.

United States

The HLPSA was amended by the Pipeline Safety Improvement Act of 2002 and the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006. These amendments have resulted in the adoption of rules by the DOT that require transportation pipeline operators to implement integrity management programs, including frequent inspections, correction of identified anomalies and other measures, to ensure pipeline safety in “high consequence areas” such as high population areas, areas unusually sensitive to environmental damage, and commercially navigable waterways. In the United States, our costs associated with the inspection, testing and correction of identified anomalies were approximately $41 million in 2020. Based on currently available information, our preliminary estimate for 2021 is that we will incur approximately $32 million in expenditures associated with our required pipeline integrity management program. However, significant additional expenses could be incurred if new or more stringently interpreted pipeline safety requirements are implemented. In addition to required activities, our integrity management program includes several voluntary, multi-year initiatives designed to prevent incidents. Costs incurred in connection with these voluntary initiatives were approximately $24 million in 2020, and our preliminary estimate for 2021 is that we will incur approximately $18 million of such costs.

PHMSA was reauthorized and the HLPSA was amended in 2011, 2016 and 2020. The regulatory changes precipitated by these actions have increased our cost to operate. For example, in October 2019, PHMSA published three final rules that create or expand reporting, inspection, maintenance and other pipeline safety obligations. Additionally, in the Fiscal Year 2021 Omnibus Appropriations Bill, Congress reauthorized PHMSA through fiscal year 2023 and directed the agency to move forward with several regulatory actions, including the “Pipeline Safety: Class Location Change Requirements” and the “Pipeline Safety: Safety of Gas Transmission and Gathering Pipelines” proposed rulemakings. Congress has also instructed PHMSA to issue final regulations that will require operators of non-rural gas gathering lines and new and existing transmission and distribution pipeline facilities to conduct certain leak detection and repair programs and to require facility inspection and maintenance plans to align with those regulations.

In October 2015, the Governor of California signed the Oil Spill Response: Environmentally and Ecologically Sensitive Areas Bill (“AB-864”) which requires new and existing pipelines located near environmentally and ecologically sensitive areas (“EESA”) connected to or located in the coastal zone to use best available technologies (“BAT”) to reduce the amount of oil released in an oil spill to protect state waters and wildlife. BAT includes, but is not limited to, installation of leak detection technologies, automatic shutoff systems, or remote controlled sectionalized block valves, or any combination of these technologies based on a risk analysis conducted by the operator. The Regulation became effective on October 1, 2020. Milestone dates include: May 1, 2021 – Requests for exemption (for pipelines located outside the Coastal Zone, if the operator can show through spill modeling / risk analysis that a release would not impact the coastal zone portion of an EESA) or deferral (pipeline already employing BAT) from the provisions of this Article shall be submitted to the State Fire Marshal no later than this date; October 1, 2021 – Submittal of Risk analysis, BAT evaluation, and implementation plan for existing pipelines; and April 1, 2023 – Completion of retrofit of existing pipelines with BAT is due. Compliance with these requirements will impact our pipeline operations in California and add to the cost to operate the pipelines subject to these rules.

The DOT has issued guidelines with respect to securing regulated facilities against terrorist attack. We have instituted security measures and procedures in accordance with such guidelines to enhance the protection of certain of our facilities; however, we cannot provide any assurance that these security measures would fully protect our facilities from an attack.

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The DOT has generally adopted American Petroleum Institute Standard (“API”) 653 as the standard for the inspection, repair, alteration and reconstruction of steel above ground petroleum storage tanks subject to DOT jurisdiction. API 653 requires regularly scheduled inspection and repair of tanks remaining in service. In the United States, our costs associated with this program were approximately $27 million in 2020. For 2021, we have budgeted approximately $30 million in connection with continued API 653 compliance activities and similar new EPA regulations for tanks not regulated by the DOT. Certain storage tanks may be taken out of service if we believe the cost of compliance will exceed the value of the storage tanks or replacement tankage may be constructed.

Canada

In Canada, the CER and provincial agencies regulate the safety and integrity management of pipelines and storage tanks used for hydrocarbon transmission. We have incurred and will continue to incur costs related to such regulatory requirements.

We continue to implement Pipeline, Facility and Cavern Integrity Management Programs to comply with applicable regulatory requirements and assist in our efforts to mitigate risk. Costs incurred for such integrity management activities were approximately $69 million in 2020. We are increasing our integrity dig and pipeline replacement projects to ensure safe and reliable operations as we seek to expand volumes on certain of our systems. Our preliminary estimate for 2021 is that we will incur approximately $81 million of costs on such projects.

We cannot predict the potential costs associated with additional, future regulation. Significant additional expenses could be incurred, and additional operational requirements and constraints could be imposed, if new or more stringently interpreted pipeline safety requirements are implemented.

Occupational Safety and Health

United States

In the United States, we are subject to the requirements of the Occupational Safety and Health Act, as amended (“OSHA”) and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that certain information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities and citizens. Certain of our facilities are subject to OSHA Process Safety Management (“PSM”) regulations, which are designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals. These regulations apply to any process which involves a chemical at or above specified thresholds or any process that involves 10,000 pounds or more of a flammable liquid or gas in one location.

Canada

Similar regulatory requirements exist in Canada under the federal and provincial Occupational Health and Safety Acts, Regulations and Codes. The agencies with jurisdiction under these regulations are empowered to enforce them through inspection, audit, incident investigation or investigation of a public or employee complaint. In some jurisdictions, the agencies have been empowered to administer penalties for contraventions without the company first being prosecuted. Additionally, under the Criminal Code of Canada, organizations, corporations and individuals may be prosecuted criminally for violating the duty to protect employee and public safety.

Solid Waste

We generate wastes, including hazardous wastes, which are subject to the requirements of the federal Resource Conservation and Recovery Act, as amended (“RCRA”), and analogous state and provincial laws. Many of the wastes that we generate are not subject to the most stringent requirements of RCRA because our operations generate primarily oil and gas wastes, which currently are excluded from consideration as RCRA hazardous wastes. It is possible, however, that in the future, the exclusion for oil and gas waste under RCRA may be revisited and our wastes subject to more rigorous and costly disposal requirements, resulting in additional capital expenditures or operating expenses.

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Hazardous Substances

The federal Comprehensive Environmental Response, Compensation and Liability Act, as amended (“CERCLA”), also known as “Superfund,” and comparable state laws impose liability, without regard to fault or the legality of the original act, on certain classes of persons that contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of the site or sites where the release occurred and companies that disposed of, or arranged for the disposal of, the hazardous substances found at the site. Such persons may be subject to strict, joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain health studies. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. In the course of our ordinary operations, we may generate waste that falls within CERCLA’s definition of a “hazardous substance.” Canadian federal and provincial laws also impose liabilities for releases of certain substances into the environment.

We are subject to the Environmental Protection Agency’s (“EPA”) Risk Management Plan regulations at certain facilities. These regulations are intended to work with OSHA’s PSM regulations to minimize the offsite consequences of catastrophic releases. The regulations require us to develop and implement a risk management program that includes a five-year accident history, an offsite consequence analysis process, a prevention program and an emergency response program. In January 2016, the EPA finalized revisions to the Risk Management Plan (“RMP”) rules, including requirements for the use of third-party compliance audits, root cause analyses for facilities that experience releases, process hazard analyses and enhanced information-sharing provisions, effective March 2017. In November 2019, the EPA finalized revisions to the RMP rules, removing requirements related to public disclosure, third-party audits and post-incident root cause analyses, among others. However, several environmental groups and trade unions have challenged the EPA’s revised rule. OSHA has announced that it is considering similar revisions to the PSM rule, but, to date, has not issued a Notice of Proposed Rulemaking. The potential for further revisions to either the RMP or PSM rule is uncertain at this time.

Environmental Remediation

We currently own or lease, and in the past have owned or leased, properties where potentially hazardous liquids, including hydrocarbons, are or have been handled. These properties may be subject to CERCLA, RCRA and state and Canadian federal and provincial laws and regulations. Under such laws and regulations, we could be required to remove or remediate potentially hazardous liquids or associated wastes (including wastes disposed of or released by prior owners or operators) and to clean up contaminated property (including contaminated groundwater).

We maintain insurance of various types with varying levels of coverage that we consider adequate under the circumstances to cover our operations and properties. The insurance policies are subject to deductibles and retention levels that we consider reasonable and not excessive. Consistent with insurance coverage generally available in the industry, in certain circumstances our insurance policies provide limited coverage for losses or liabilities relating to gradual pollution, with broader coverage for sudden and accidental occurrences.

Assets we have acquired or will acquire in the future may have environmental remediation liabilities for which we are not indemnified. We have in the past experienced and in the future may experience releases of hydrocarbon products into the environment from our pipeline, rail, storage and other facility operations. We may also discover environmental impacts from past releases that were previously unidentified. The costs and liabilities associated with any such releases or environmental impacts could be significant and may not be covered by insurance; accordingly, such costs and liabilities could have a material adverse impact on our results of operations and/or financial position.

Air Emissions

Our United States operations are subject to the United States Clean Air Act (“Clean Air Act”), comparable state laws and associated federal, state and local regulations. Our Canadian operations are also subject to federal and provincial air emission regulations, which are discussed in subsequent sections.

As a result of the changing air emission requirements in both Canada and the United States, we may be required to incur certain capital and operating expenditures in the next several years to install air pollution control equipment and otherwise comply with more stringent federal, state, provincial and regional air emissions control requirements when we attempt to obtain or maintain permits and approvals for sources of air emissions. We can provide no assurance that future air compliance obligations will not have a material adverse effect on our financial condition or results of operations.

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Climate Change Initiatives

United States

The EPA has adopted rules for reporting the emission of carbon dioxide, methane and other greenhouse gases (“GHG”) from certain sources. Fewer than ten of our facilities are presently subject to the federal GHG reporting requirements. These include facilities with combustion GHG emissions and potential fugitive emissions above the reporting thresholds. We import sufficient quantities of finished fuel products into the United States to be required to report that activity as well.

In 2016, the EPA finalized regulations affecting new, modified and reconstructed sources of air emission in the oil and natural gas sectors (NSPS Subpart OOOOa) that required significant reductions in fugitive methane emissions from certain upstream and midstream oil and gas facilities. We had one natural gas storage facility for which a portion was subject to this regulation.In late 2020, the EPA rescinded the methane requirements of this rule, such that no Plains facility is now affected.There is a possibility that the Biden administration may reverse these changes, and we will continue to monitor these developments.For the period during which our single facility was subject to these requirements, compliance costs were not material.

California has implemented a GHG cap-and-trade program, authorized under Assembly Bill 32 (“AB32”). Since its start in 2014, California’s cap-and-trade program has only applied to large industrial facilities with carbon dioxide equivalent emissions over 25,000 metric tons. The California Air Resources Board has published a list of facilities that are subject to this program. At this time, the list only includes one of our facilities, the Lone Star Gas Liquids facility in Shafter, California because it is a significant combustion and propane fractionation source. As a result, compliance instruments for GHG emissions have been purchased since 2013.

Effective January 1, 2015, the AB32 regulations also covered finished fuel providers and importers. California finished fuels providers (refiners and importers) are required to purchase GHG emission credits for finished fuel sold in or imported into California. Plains Marketing was included in this portion of the regulation due to propane imports and completed its first year of compliance in 2016. Effective January 1, 2018, importers of finished fuels responsible for compliance costs associated with GHG has changed from the consignee to the importer on title of the product. Plains Midstream Canada is now included in this change to the rule due to its imports of propane into California and submitted its first compliance report in 2019.

California has also implemented several climate change initiatives via executive order. Executive Order B-30-15 was signed by California’s Governor in mid-2015. This Executive Order requires a 40% reduction in GHG emissions from the 1990 baseline level by 2030. Compliance with this reduction requirement may necessitate the lowering of the threshold for industrial facilities required to participate in the GHG cap and trade program. In late 2020, the governor of California issued an executive order setting targets on the limitation or phase-out of the sale of petroleum-fueled passenger, commercial, and off-road vehicles over the next 15 to 25 years.A number of other states are working to implement zero-emission vehicle requirements or targets. Separately, in October 2020, the Governor of California signed another executive order that establishes a state goal to conserve at least 30% of California’s land and coastal waters by 2030 and directs state agencies to implement other measures to mitigate climate change and strengthen biodiversity.

Certain other states where we operate, such as Colorado, have also adopted, or are considering adopting, regulations related to GHG emissions. While it is not possible at this time to predict how federal or state governments may choose to regulate GHG emissions, any new regulatory restrictions on GHG emissions could result in material increased compliance costs, additional operating restrictions, an increase in the cost of feedstock and products produced by our refinery customers, and a reduced demand for petroleum-based fuels.

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In December 2015, the Paris Agreement was signed at the 21st annual Conference of Parties to the United Nations Framework Convention on Climate Change (“UNFCCC”). The Paris Agreement, which came into effect in November 2016, requires signatory parties to develop and implement carbon emission reduction policies with a goal of limiting the rise in average global temperatures to 2°C or less. The United States is currently a signatory to the Paris Agreement. The Paris Agreement is likely to become a significant driver for future potential GHG reduction programs in participating countries, including the United States. President Biden has announced that climate change policy will be a focal point of his administration, and legislative or regulatory initiatives may be developed that may impose additional restrictions on our operations. In January 2021, President Biden signed an executive order directing the Secretary of the Interior to pause new oil and gas leases on public lands and in offshore waters of the United States. The Biden administration could also pursue the imposition of more restrictive requirements for the establishment of pipeline infrastructure or more restrictive GHG emissions limitations for oil and gas facilities. There is also a risk that financial institutions may be required to adopt policies that have the effect of reducing the funding available to the hydrocarbon energy sector. The Federal Reserve recently announced that it has joined the Network for Greening the Financial System, a consortium of financial regulators focused on addressing climate-related risks in the financial sector. Finally, to the extent increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods and other climatic events, such events could have a material adverse effect on our assets, particularly those located in coastal or flood prone areas.

Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations could result in increased compliance costs or additional operating restrictions, and could have a material adverse effect on our business, demand for our services, financial condition, results of operations and cash flows.

Canada

Federal Regulations. Large emitters of GHG have been required to report their emissions under the Canadian Greenhouse Gas Emissions Reporting Program since 2004. Effective January 1, 2018, the Federal Department of Environment and Climate Change lowered the reporting threshold for all facilities from 50 thousand tonnes per year (“kt/y”) to 10 kt/y GHG emissions. This has resulted in one additional PMC facility (for a total of four locations) being currently required to prepare annual reports of their emissions. The associated cost with this reporting requirement is not considered to be material.

In December 2015, the UNFCCC ratified the Paris Agreement to accelerate climate change initiatives and to intensify the actions of member nations in the reduction of GHG emissions. This ratification also included requirements that all parties report on their emissions status and agreement for a review every five years to assess success among member nations in attaining objectives and targets under this agreement. The Government of Canada has implemented a pan-Canadian approach to pricing carbon pollution requiring all Canadian provinces and territories to have carbon pricing in place by 2018, which is now in effect. The provinces and territories were granted flexibility in deciding how they implement carbon pricing either by placing a direct price on carbon pollution or adopting a cap and trade system. The Provincial programs that fail to meet the Federal government’s requirements for their programs are required to adopt the Federal program. The Federal program includes two components: a direct price on carbon pollution (the Federal price on carbon pollution will start at CAD$20 per tonne in 2019 and rise by CAD$10 per year to reach CAD$50 per tonne in 2022) and an output based pricing system (“OBPS”) designed to address competitiveness risk for large emitters. However, legislation has been proposed which, if enacted, may increase the carbon prices charged on businesses in jurisdictions subject to the federal program.

In November 2020, the Federal government introduced proposed legislation that would commit the government to reach net-zero GHG emissions by 2050 through setting legally-binding, five-year emissions reduction targets (2030, 2035, 2040 and 2045). The impact of this proposed legislation on PMC operations cannot be determined until the legislation is passed and details of emission reduction targets are disclosed.

In December 2020, the Federal government released a Climate Plan signaling its intent to increase the Federal price on carbon pollution from CAD$30 per tonne to CAD$50 per tonne in 2022 with a further annual increase of CAD$15 per year up to CAD$170 per tonne in 2030. Legislation has not yet been passed for the increase in price on carbon. Costs for compliance with any increase in cost of carbon will be budgeted annually as part of ordinary operating cost processes.

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In April 2018, the Federal Department of Environment and Climate Change introduced regulations designed to reduce methane emissions by up to 45% by 2025 (from 2012 levels) from oil and natural gas facilities. The scope and requirements of the proposed rule are similar to the EPA methane rules described above. Effective June 2017, the Federal Department of Environment and Climate Change has introduced the Multi Sector Air Pollutants Regulations which set air pollution emission standards across Canada for several industrial sectors that utilize applicable equipment regulated under this program. The regulations establish specific limits to the amount of nitrogen oxides emitted from gas fueled boilers, heaters and stationary spark-ignition engines above a specified power rating. Based on these regulations, reporting obligations exist that are associated with seven facilities with equipment that meets specifications of the program. The implications of these regulations coming into effect are not believed to be material.

Provincial Regulations

Ontario. In February 2015, the Ontario Ministry of Environment and Climate Change issued a discussion paper that identified carbon pricing as a critical action necessary to reduce emissions of GHGs. In April 2015, the Ontario government announced it would be implementing a GHG cap and trade program, which would be implemented through the Western Climate Initiative (“WCI”), which included Quebec and California. Mandatory participants for the program were responsible for their emissions starting January 1, 2017. PMC’s facility at Sarnia was considered a mandatory participant in the program. Compliance with the federal OBPS is not expected to have a material adverse effect on our operations.

In July 2019, the Ontario government implemented the Emissions Performance Standards (“EPS”) regulation as a successor program to the repealed GHG cap and trade program. In September 2020, the Federal government accepted the EPS program as equivalent to the OBPS which allows Ontario to move forward with implementing the EPS. Ontario has yet to specify the start date of the EPS and must update regulations to bring the EPS program into effect. Until the EPS comes into force, the PMC Sarnia facility is subject to the OBPS program. Costs for compliance with the OBPS or EPS is budgeted annually and is not expected to have a material effect on operations.

In 2018, the Ontario government introduced an updated Sulphur Dioxide (“SO2”) standard which requires the reduction of SO2 from the current one hour average emission rate of 690 micrograms per cubic meter of air (“μg/m3”) to the new one hour standard of 100 μg/m3 by 2023 at industrial facilities. The introduction of this reduction measure requires evaluation of current emissions and may require equipment upgrades at our Sarnia facility. The evaluation process has not been concluded and the impact of the standard is still under review.

Alberta. The Alberta Climate Change and Emissions Management Act provided a framework for managing GHG emissions with the intent of reducing specified gas emissions to 50% of 1990 levels by December 31, 2020. The Specified Gas Emitters Regulation (“SGER”) was the initial program introduced which imposed GHG emissions limits on large emitters and required reductions in GHG emissions intensity. In January 2018, the SGER was replaced with the Carbon Competitive Incentive Regulation (“CCIR”) for compliance years 2018 and 2019. In January 2020, the Emissions Management and Climate Resilience Act replaces the Climate Change and Emissions Management Act and the CCIR was replaced with the Technology Innovation and Emissions Reduction (“TIER”) regulation. Compliance options under the TIER are similar to those under the previous SGER and CCIR programs such that a GHG fund credit purchase will be required if reduction targets identified under the program are not attained.PMC’s Empress VI facility is a mandatory participant under the TIER. For economic reasons, Ft. Saskatchewan and six other PMC facilities have opted in to be a part of the TIER program for 2020. By opting in, the fuel consumption at these asset locations avoid being subject to the federal fuel charge.

Alberta repealed the provincial “Climate Leadership Act” in May 2019 and removed its provincial carbon pricing program. The province is now subject to the federal carbon pricing program. Assets within the TIER program are exempt from the federal carbon pricing program but other fuel consumption as part of operations is subject to the federal levies. The federal fuel charge cost increase has been captured as part of the annual budgeting cycle.

In association with the federal methane reduction targets, the Alberta Energy Regulator amended Directive 60 to outline reduction requirements. New reporting measures and requirements for fugitive emission surveys and methane emission reduction came into force in January 2020. Cost for reporting and completing surveys have been captured within the 2020 and beyond annual operational budgets.

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Other Canadian Jurisdictions. Nova Scotia and Quebec Cap and Trade programs cover propane supplied by PMC into the Nova Scotia and Quebec markets. PMC is required to purchase GHG emission credits and submit annual compliance reports under each province’s respective Cap and Trade program. Program compliance costs will be passed along to the purchaser. Effective April 1, 2019, the federal carbon pricing program came into effect for provinces that do not have a carbon pricing program in place. This includes Saskatchewan, Manitoba, Ontario and New Brunswick. Program compliance costs will be passed along to the purchaser.

Water

The U.S. Federal Water Pollution Control Act, as amended, also known as the Clean Water Act (“CWA”), and analogous state and Canadian federal and provincial laws impose restrictions and strict controls regarding the discharge of pollutants into navigable waters of the United States and Canada, as well as state and provincial waters. Federal, state and provincial regulatory agencies can impose administrative, civil and/or criminal penalties for non-compliance with discharge permits or other requirements of the CWA, and can also pursue injunctive relief to enforce compliance with the CWA and analogous laws.

The U.S. Oil Pollution Act of 1990 (“OPA”) amended certain provisions of the CWA as they relate to the release of petroleum products into navigable waters. OPA subjects owners of facilities to strict, joint and potentially unlimited liability for containment and removal costs, natural resource damages and certain other consequences of an oil spill. State and Canadian federal and provincial laws also impose requirements relating to the prevention of oil releases and the remediation of areas.

In addition, for over 35 years, the U.S. Army Corps of Engineers (the “Corps”) has authorized construction, maintenance and repair of pipelines under a streamlined nationwide permit program under the CWA known as Nationwide Permit 12 (“NWP”). The NWP program is supported by strong statutory and regulatory history and was originally approved by Congress in 1977. From time to time, environmental groups have challenged the NWP program; however, to date, federal courts have upheld the validity of the NWP program under the CWA. In April 2020, the U.S. District Court for the District of Montana invalidated the 2017 decision by the Corps to reissue the NWP; however, industry groups appealed the decision, and the NWP was reinstated by the U.S. Supreme Court, pending a U.S. Circuit Court appeal process. We anticipate that the appeal will be decided in 2021. Additionally, in response to the vacatur, the Corps has announced a reissuance of the NWP 12 for oil and natural gas pipeline activities, including certain revisions to the conditions for the use of NWP 12; however, the rule has not been officially published and, with President Biden taking office in January 2021, may be subject to further revisions or suspension. While the full extent and impact of the vacatur is unclear at this time, we could face significant delays and financial costs when seeking project approvals from the Corps if we cannot obtain coverage under NWP 12.

In May 2015, the EPA published a final rule that attempted to clarify federal jurisdiction under the CWA over waters of the United States (“WOTUS”). This clarification greatly expanded the definition of WOTUS, thus increasing the jurisdiction of the Corps. Following the issuance of a presidential executive order to review the rule in January 2017, the EPA and the Corps proposed a rulemaking in June 2017 to repeal the May 2015 rule. The EPA and Corps also announced their intent to issue a new rule defining the CWA’s jurisdiction and finalized a stay delaying implementation of the 2015 rule for two years. Several states and environmental organizations announced their intent to challenge the stay and any attempt by the EPA and the Corps to rescind or revise the rule. However, on April 21, 2020, the EPA and the Corps announced the 2020 Final Rule concerning the redefinition of WOTUS. The 2020 Final Rule provides the outer bounds of the federal waters covered under the CWA’s key permitting programs such as Section 404 dredge and fill permits, Section 402 discharge permits and Section 311 oil spill prevention plans. The Final Rule took effect on June 22, 2020. In general, the 2020 Final Rule resulted in fewer federally regulated waters under the CWA offering a streamlined list of only four clear categories of jurisdictional waters and 12 exclusions. A decrease in mitigation requirements is expected, with traditional wetland states (e.g., Louisiana) and states in the arid west (e.g., Texas) expected to be among the most affected by the new rule. However, legal challenges to this rulemaking are ongoing, and it is possible that the new presidential administration could propose a broader interpretation of WOTUS.

Endangered Species

New projects may require approvals and environmental analysis under federal, state and provincial laws, including the National Environmental Policy Act and the Endangered Species Act in the United States and the Species at Risk Act in Canada. The resulting costs and liabilities associated with lengthy regulatory review and approval requirements could materially and negatively affect the viability of such projects.

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Other Regulations

Transportation Regulation

Our transportation activities are subject to regulation by multiple governmental agencies. Our historical operating costs reflect the recurring costs resulting from compliance with these regulations. The following is a summary of the types of transportation regulation that may impact our operations.

General Interstate Regulation in the United States. Our interstate common carrier liquids pipeline operations are subject to rate regulation by the U.S. Federal Energy Regulatory Commission (“FERC”) under the Interstate Commerce Act (“ICA”). The ICA requires that tariff rates for liquids pipelines, which include both crude oil pipelines and refined products pipelines, be just and reasonable and non-discriminatory. Failure to comply with the requirements of the ICA could result in the imposition of civil or criminal penalties.

State Regulation in the United States. Our intrastate liquids pipeline transportation activities are subject to various state laws and regulations, as well as orders of state regulatory bodies, including the Railroad Commission of Texas (“TRRC”) and the California Public Utility Commission (“CPUC”). The CPUC prohibits certain of our subsidiaries from acting as guarantors of our senior notes and credit facilities.

U.S. Energy Policy Act of 1992 and Subsequent Developments. In October 1992, Congress passed the Energy Policy Act of 1992 (“EPAct”), which, among other things, required the FERC to issue rules to establish a simplified and generally applicable ratemaking methodology for petroleum pipelines and to streamline procedures in petroleum pipeline proceedings. The FERC responded to this mandate by establishing a formulaic methodology for petroleum pipelines to change their rates within prescribed ceiling levels that are tied to an inflation index. The FERC reviews the formula every five years. Pursuant to a December 2020 Order, commencing July 1, 2021, the annual index adjustment for the five year period ending June 30, 2026 will equal the producer price index for finished goods for the applicable year plus an adjustment factor of 0.78%. Rehearing of the December 2020 Order has been requested, and the requests remain pending before FERC. Pipelines may raise their rates to the rate ceiling level generated by application of the annual index adjustment factor each year; however, a shipper may challenge such increase if the increase in the pipeline’s rates is substantially in excess of the actual cost increases incurred by the pipeline during the relevant year. If the FERC’s annual index adjustment reduces the ceiling level such that it is lower than a pipeline’s filed rate, the pipeline must reduce its rate to conform with the lower ceiling. Indexing is the default methodology to change rates. The FERC, however, retained cost-of-service ratemaking, market-based rates and settlement rates as alternatives to the indexing approach that may be used in certain specified circumstances. Because the indexing methodology for the next five-year period is tied in part to an inflation index and is not based on our specific costs, the indexing methodology could hamper our ability to recover cost increases.

Under the EPAct, petroleum pipeline rates in effect for the 365-day period ending on the date of enactment of EPAct are deemed to be just and reasonable under the ICA if such rates had not been subject to complaint, protest or investigation during such 365-day period. Generally, complaints against such “grandfathered” rates may only be pursued if the complainant can show that a substantial change has occurred since the enactment of EPAct in either the economic circumstances of the oil pipeline or in the nature of the services provided that were a basis for the rate. EPAct places no such limit on challenges to a provision of an oil pipeline tariff rate or rules as unduly discriminatory or preferential.

Pipeline Rate Regulation in the United States. The FERC historically has not investigated rates of liquids pipelines on its own initiative when those rates have not been the subject of a protest or complaint by a shipper. The majority of our Transportation segment profit in the United States is produced by rates that are either grandfathered or set by agreement with one or more shippers. These rates remain regulated by FERC and are subject to challenge or review and modification by FERC consistent with the requirements of the ICA, which requires that tariff rates for liquids pipelines, which include both crude oil pipelines and refined products pipelines, be just and reasonable and non-discriminatory. See Item 1A. “Risk Factors—Risks Related to Laws and Regulations—Our assets are subject to federal, state and provincial regulation. Rate regulation or a successful challenge to the rates we charge on our U.S. and Canadian pipeline systems may reduce the amount of cash we generate.” for additional discussion on how our rates could be impacted by this policy change.

Canadian Regulation. Our Canadian pipeline assets are subject to regulation by the CER and by provincial authorities. With respect to a pipeline over which it has jurisdiction, the relevant regulatory authority has the power, upon application by a third party, to determine the rates we are allowed to charge for transportation on, and set other terms of access to, such pipeline. In such circumstances, if the relevant regulatory authority determines that the applicable terms and conditions of service are not just and reasonable, the regulatory authority can impose conditions it considers appropriate.

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Trucking Regulation

United States

We operate a fleet of trucks to transport crude oil and oilfield materials as a private, contract and common carrier. We are licensed to perform both intrastate and interstate motor carrier services. As a motor carrier, we are subject to certain safety regulations issued by the Federal Motor Carrier Safety Association of the DOT. The trucking regulations cover, among other things: (i) driver operations, (ii) log book maintenance, (iii) truck manifest preparations, (iv) safety placard placement on the trucks and trailer vehicles, (v) drug and alcohol testing and (vi) operation and equipment safety. We are also subject to OSHA with respect to our U.S. trucking operations.

Canada

Our trucking assets in Canada are subject to regulation by both federal and provincial transportation agencies in the provinces in which they are operated. These regulatory agencies do not set freight rates, but do establish and administer rules and regulations relating to other matters including equipment, facility inspection, reporting and safety. We are licensed to operate both intra- and inter-provincially under the direction of the National Safety Code (“NSC”) that is administered by Transport Canada. Our for-hire service is primarily the transportation of crude oil, condensates and NGL. We are required under the NSC to, among other things, monitor: (i) driver operations, (ii) log book maintenance, (iii) truck manifest preparations, (iv) safety placard placement on the trucks and trailers, (v) operation and equipment safety and (vi) many other aspects of trucking operations. We are also subject to Occupational Health and Safety regulations with respect to our Canadian trucking operations.

Railcar Regulation

We own and operate a number of railcar loading and unloading facilities in the United States and Canada. In connection with these rail terminals, we own and lease a significant number of railcars. Our railcar operations are subject to the regulatory jurisdiction of the Federal Railroad Administration of the DOT, the OSHA, as well as other federal and state regulatory agencies and Canadian regulatory agencies for operations in Canada.

Railcar accidents involving trains carrying crude oil from North Dakota’s Bakken shale formation have led to increased regulatory scrutiny. PHMSA issued a safety advisory warning that Bakken crude may be more flammable than other grades of crude oil and reinforcing the requirement to properly test, characterize, classify, and, where appropriate, sufficiently degasify hazardous materials prior to and during transportation. PHMSA also initiated “Operation Classification,” a compliance initiative involving unannounced inspections and testing of crude oil samples to verify that offerors of the materials have properly classified, described and labeled the hazardous materials before transportation. In December 2015, Congress passed the Fixing America’s Surface Transportation (“FAST”) Act which was subsequently signed by the President. This legislation clarified the parameters around the timeline and requirements for railcars hauling crude oil in the United States. We believe our railcar fleet is in compliance in all material respects with current standards for crude oil moved by rail.

In December 2014, the North Dakota Industrial Commission adopted new standards to improve the safety of Bakken crude oil for transport. The new standard, Commission Order 25417, was effective April 1, 2015, and requires operators/producers to condition Bakken crude oil to certain vapor pressure limits. Under the order, all Bakken crude oil produced in North Dakota will be conditioned with no exceptions. The order requires operators/producers to separate light hydrocarbons from all Bakken crude oil to be transported and prohibits the blending of light hydrocarbons back into oil supplies prior to shipment. We are not directly responsible for the conditioning or stabilization of Bakken crude oil; however, under the order, it is our responsibility to notify the State of North Dakota upon discovering that Bakken crude oil received at our rail facility exceeds the permitted vapor pressure limits.

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Indigenous Protections

Part of our operations cross land that has historically been apportioned to various Native American/First Nations tribes (“Indigenous Peoples”), who may exercise significant jurisdiction and sovereignty over their lands. Indigenous Peoples may also have certain treaty rights and rights to consultation on projects that may affect such lands. Our operations may be impacted to the extent these tribal governments are found to have and choose to act upon such jurisdiction over lands where we operate. For example, in 2020, the Supreme Court ruled in McGirt v. Oklahoma that the Muscogee (Creek) Nation reservation in Eastern Oklahoma has not been disestablished (i.e., officially unrecognized). Prior to the court’s ruling, the prevailing view was that all reservations within Oklahoma had been disestablished prior to statehood in 1907. Although the court’s ruling indicates that it is limited to criminal law as applied within the Muscogee (Creek) Nation reservation, the ruling has significant potential implications for civil law within the Muscogee (Creek) Nation reservation, as well as other reservations that may similarly be found to not have been disestablished. Later in 2020, state courts in Oklahoma, applying the analysis in McGirt, ruled that the Cherokee, Chickasaw, Seminole, and Choctaw reservations likewise had not been disestablished.

On October 1, 2020, the EPA granted approval to the State of Oklahoma under Section 10211(a) of the Safe, Accountable, Flexible, Efficient Transportation Equity Act of 2005 (the “SAFETE Act”) to administer all of the State’s existing EPA-approved regulatory programs to Indian Country within the State except: Indian allotments to which Indian titles have not been extinguished; lands that are held in trust by the United States on behalf of any Indian or Tribe; lands that are owned in fee by any Tribe where title was acquired through a treaty with the United States to which such Tribe is a party and that have never been allotted to any citizen or member of such Tribe. The approval extends the State’s authority for existing EPA-approved regulatory programs to all lands within the State to which the State applied such programs prior to the U.S. Supreme Court’s ruling regarding the Muscogee (Creek) Nation reservation. However, several Tribes have expressed dissatisfaction with the consultation process performed in relation to this approval, and it is possible that EPA’s approval under the SAFETE Act could be challenged. Additionally, the SAFETE Act provides that any Tribe in Oklahoma may seek “Treatment as a State” by the EPA, and it is possible that one or more of the Tribes in Oklahoma may seek such an approval from EPA. At this time, we cannot predict how these jurisdictional issues may ultimately be resolved.

Cross Border Regulation

As a result of our cross border activities, including transportation and importation of crude oil, NGL and natural gas between the United States and Canada, we are subject to a variety of legal requirements pertaining to such activities including presidential permit requirements, export/import license requirements, tariffs, Canadian and U.S. customs and taxes and requirements relating to toxic substances. U.S. legal requirements relating to these activities include regulations adopted pursuant to the Short Supply Controls of the Export Administration Act (“EAA”), the North American Free Trade Agreement (“NAFTA”) replacement, the United States-Mexico-Canada Agreement (“USMCA”) (July 1, 2020) and the Toxic Substances Control Act (“TSCA”), as well as presidential permit requirements of the U.S. Department of State. In addition, the importation and exportation of natural gas from and to the United States and Canada is subject to regulation by U.S. Customs and Border Protection, U.S. Department of Energy and the CER. Violations of these licensing, tariff and tax reporting requirements or failure to provide certifications relating to toxic substances could result in the imposition of significant administrative, civil and criminal penalties. Furthermore, the failure to comply with U.S. federal, state and local tax requirements, as well as Canadian federal and provincial tax requirements, could lead to the imposition of additional taxes, interest and penalties.

Market Anti-Manipulation Regulation

In November 2009, the Federal Trade Commission (“FTC”) issued regulations pursuant to the Energy Independence and Security Act of 2007, intended to prohibit market manipulation in the petroleum industry. Violators of the regulations face civil penalties of up to approximately $1.25 million per violation per day, subject to the FTC’s annual inflation adjustment. In July 2010, Congress passed the Dodd-Frank Act, which incorporated an expansion of the authority of the Commodity Futures Trading Commission (“CFTC”) to prohibit market manipulation in the markets regulated by the CFTC. This authority, with respect to crude oil swaps and futures contracts, is similar to the anti-manipulation authority granted to the FTC with respect to crude oil purchases and sales. In July 2011, the CFTC issued final rules to implement their new anti-manipulation authority. The rules subject violators to a civil penalty of up to the greater of approximately $1.23 million, subject to the CFTC’s annual inflation adjustment, or triple the monetary gain to the person for each violation.

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Natural Gas Storage Regulation

Our natural gas storage operations are subject to regulatory oversight by numerous federal, state and local regulatory agencies, many of which are authorized by statute to issue, and have issued, rules and regulations binding on the natural gas storage and pipeline industry, related businesses and market participants. The failure to comply with such laws and regulations can result in substantial penalties and fines.

The following is a summary of the kinds of regulation that may impact our natural gas storage operations. However, our unitholders should not rely on such discussion as an exhaustive review of all regulatory considerations affecting our natural gas storage operations.

Our natural gas storage facilities provide natural gas storage services in interstate commerce and are subject to comprehensive regulation by the FERC under the Natural Gas Act of 1938 (“NGA”). Pursuant to the NGA and FERC regulations, storage providers are prohibited from making or granting any undue preference or advantage to any person or subjecting any person to any undue prejudice or disadvantage or from maintaining any unreasonable difference in rates, charges, service, facilities, or in any other respect. The terms and conditions for services provided by our facilities are set forth in natural gas tariffs on file with the FERC. We have been granted market-based rate authorization for the services that our facilities provide. Market-based rate authority allows us to negotiate rates with individual customers based on market demand.

The FERC also has authority over the siting, construction, and operation of United States pipeline transportation and storage facilities and related facilities used in the transportation, storage and sale for resale of natural gas in interstate commerce, including the extension, enlargement or abandonment of such facilities. The FERC’s authority extends to maintenance of accounts and records, terms and conditions of service, acquisition and disposition of facilities, initiation and discontinuation of services, imposition of creditworthiness and credit support requirements applicable to customers and relationships among pipelines and storage companies and certain affiliates. Our natural gas storage entities are required by the FERC to post certain information daily regarding customer activity, capacity and volumes on their respective websites. Additionally, the FERC has jurisdiction to impose rules and regulations applicable to all natural gas market participants to ensure market transparency. FERC regulations require that buyers and sellers of more than a de minimis volume of natural gas report annual numbers and volumes of relevant transactions to the FERC. Our natural gas storage facilities are subject to these annual reporting requirements.

Under the Energy Policy Act of 2005 (“EPAct 2005”) and related regulations, it is unlawful in connection with the purchase or sale of natural gas or transportation services subject to FERC jurisdiction to use or employ any device, scheme or artifice to defraud; to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or to engage in any act or practice that operates as a fraud or deceit upon any person. EPAct 2005 gives the FERC civil penalty authority to impose penalties for certain violations of up to approximately $1.31 million per day for each violation, subject to FERC’s annual inflation adjustment. FERC also has the authority to order disgorgement of profits from transactions deemed to violate the NGA and the EPAct 2005.

In January 2020, PHMSA finalized a rule regarding the safety of underground natural gas storage facilities, which was published in the Federal Register on February 12, 2020. This rule maintains several elements from the earlier interim rule, incorporating API Recommended Practices 1170 and 1171 in PHMSA regulations; revises the definition of underground natural gas storage facility; and clarifies certain reporting and notification criteria. We do not anticipate that compliance with the final rule will have a significant adverse effect on our operations.

The natural gas industry historically has been heavily regulated. New rules, orders, regulations or laws may be passed or implemented that impose additional costs, burdens or restrictions on us. We cannot give any assurance regarding the likelihood of such future rules, orders, regulations or laws or the effect they could have on our business, financial condition, and results of operations or ability to make distributions to our unitholders.

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Operational Hazards and Insurance

Pipelines, terminals, trucks or other facilities or equipment may experience damage as a result of an accident, natural disaster, terrorist attack, cyber event or other event. These hazards can cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage and suspension of operations. We maintain various types and varying levels of insurance coverage to cover our operations and properties, and we self-insure certain risks, including gradual pollution, cybersecurity and named windstorms. However, such insurance does not cover every potential risk that might occur, associated with operating pipelines, terminals and other facilities and equipment, including the potential loss of significant revenues and cash flows.

The occurrence of a significant event not fully insured, indemnified or reserved against, or the failure of a party to meet its indemnification obligations, could materially and adversely affect our operations and financial condition. We believe that we maintain adequate insurance coverage, although insurance will not cover many types of interruptions that might occur, will not cover amounts up to applicable deductibles and will not cover all risks associated with certain of our assets and operations. With respect to our insurance coverage, our policies are subject to deductibles and retention levels that we consider reasonable and not excessive. Additionally, no assurance can be given that we will be able to maintain adequate insurance in the future at rates we consider reasonable. As a result, we may elect to self-insure or utilize higher deductibles in certain other insurance programs. In addition, although we believe that we have established adequate reserves and liquidity to the extent such risks are not insured, costs incurred in excess of these reserves may be higher or we may not receive insurance proceeds in a timely manner, which may potentially have a material adverse effect on our financial conditions, results of operations or cash flows.

Title to Properties and Rights-of-Way

Our real property holdings generally consist of: (i) parcels of land that we own in fee, (ii) surface leases and underground storage leases and (iii) easements, rights-of-way, permits, crossing agreements or licenses from landowners or governmental authorities permitting the use of certain lands for our operations. In all material respects, we believe we have satisfactory title or the right to use the sites upon which our significant facilities are located, subject to (a) customary liens, restrictions or encumbrances and (b) challenges that we do not regard as material relative to our overall operations. Some of our real property rights may be subject to termination under agreements that provide for one or more of: periodic payments, term periods, renewal rights, abandonment of use, continuous operation requirements, revocation by the licensor or grantor and possible relocation obligations.

Human Capital

General

Our primary human capital management objective is to attract, retain and develop a high quality workforce that will enable us to maintain and enhance a culture that is consistent with our core values of safety and environmental stewardship; ethics and integrity; accountability; and respect and fairness. To support this objective, we seek to attract, reward and support employees through competitive pay, benefits and other programs; develop employees and encourage internal talent mobility to prepare employees for critical roles and leadership positions for the future; facilitate the development of a workplace culture that is diverse, engaging and inclusive; and promote efficiency and a high performance culture by investing in technology and systems and providing tools and resources that enable employees at work.

As a limited partnership, we do not directly have officers and employees. Our operations and activities are managed by Plains All American GP LLC (“GP LLC”), which employs our management and operational personnel (other than our Canadian personnel, who are employed by our subsidiary, PMCULC). As of December 31, 2020, GP LLC and PMCULC employed approximately 4,400 people in North America, of which approximately 3,200 were employed in the U.S. and approximately 1,200 were employed in Canada. Approximately 68% of our workforce (approximately 3,000 employees) are field employees, which includes approximately 880 employees in our trucking division. Our employees are located in 29 states in the U.S. and in 4 provinces in Canada. Approximately 136 employees are covered by five separate collective bargaining agreements, which run through 2023 and 2024.

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Health and Safety