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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, 2021
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 approximately 467.6 million 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 are affiliates of the registrant) on June 30, 2021 was approximately $5.3 billion, based on a closing price of $11.36 per Common Unit as reported on the Nasdaq Global Select Market on such date.
As of February 22, 2022, there were 705,043,477 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 2022 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—2021 ANNUAL REPORT
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Page
PART I 5
Items 1 and 2. Business and Properties 5
Item 1A. Risk Factors 42
Item 1B. Unresolved Staff Comments 69
Item 3. Legal Proceedings 69
Item 4. Mine Safety Disclosures 69
Item 6. Reserved 72
Item 7A. Quantitative and Qualitative Disclosures About Market Risk 100
Item 8. Financial Statements and Supplementary Data 101
Item 9A. Controls and Procedures 101
Item 9B. Other Information 102
Item 11. Executive Compensation 103
Item 14. Principal Accountant Fees and Services 104
Item 15. Exhibits and Financial Statement Schedules 105
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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:
•declines in global crude oil demand and crude oil prices (whether due to the COVID-19 pandemic, future pandemics or other factors) that correspondingly lead to a significant reduction of North American crude oil and natural gas liquids (“NGL”) 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;
•the effects of competition and capacity overbuild in areas where we operate, including downward pressure on rates and margins, 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);
•general economic, market or business conditions in the United States and elsewhere (including the potential for a recession or significant slowdown in economic activity levels, the risk of persistently high inflation and continued supply chain issues, the impact of coronavirus variants on demand and growth, and the timing, pace and extent of economic recovery) that impact (i) demand for crude oil, drilling and production activities and therefore the demand for the midstream services we provide, and (ii) commercial opportunities available to us;
•the impact of current and future laws, rulings, governmental regulations, executive orders, trade policies, accounting standards and statements, and related interpretations, including legislation, executive orders or regulatory initiatives that arise out of pandemic related concerns, 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;
•environmental liabilities, litigation or other events that are not covered by an indemnity, insurance or existing reserves;
•loss of key personnel and inability to attract and retain new talent;
•fluctuations in refinery capacity in areas supplied by our mainlines and other factors affecting demand for various grades of crude oil and NGL and resulting changes in pricing conditions or transportation throughput requirements;
•the availability of, and our ability to consummate, divestitures, joint ventures, acquisitions or other strategic opportunities;
•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, and the successful integration and future performance of acquired assets or businesses;
•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;
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•significant under-utilization of our assets and facilities;
•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 (such as 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, supply chain issues, legal constraints (including governmental orders or guidance), or other factors or events;
•the incurrence of costs and expenses related to unexpected or unplanned capital expenditures, third-party claims 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;
•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;
•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;
•the amplification of other risks caused by volatile financial markets, capital constraints, liquidity concerns and inflation;
•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;
•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;
•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; and
•other factors and uncertainties inherent in the transportation, storage, terminalling and marketing of crude oil, as well as in the processing, transportation, fractionation, storage and marketing of NGL.
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 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 and NGL.
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 further 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 in lesser developed countries throughout the world. Furthermore, we believe existing energy infrastructure will play a critical role in supporting emerging energy and energy transition initiatives. As a result, we believe that midstream energy infrastructure will remain critical and valuable.
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, 2021 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”), Plains Oryx Permian Basin LLC (the “Permian JV”) and Red River Pipeline Company LLC (“Red River”) 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, 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 commercial 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 our customers with market access, flexibility and value chain solutions, capture market opportunities, address physical market imbalances, mitigate risks and generate sustainable cash flow and margin;
•Optimizing our asset portfolio and operations (including for emerging energy opportunities) 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.
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Competitive Strengths
We believe that the following competitive strengths position us to successfully execute our principal business strategy:
•We own a strategically located, geographically diverse and interconnected large-scale asset base that provides operational flexibility and commercial optionality. The majority of our primary transportation 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 terminals and facilities assets. The majority of our terminals and facilities assets are located at major trading locations and premium markets that serve as gateways to major North American refinery and distribution markets and key export terminals where we have strong business relationships. In addition, our pipeline, rail, truck and storage assets provide our customers and us with significant flexibility and optionality to satisfy demand and balance markets, and participate in emerging energy opportunities.
•Our 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.
•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 merchant activities provide us with the opportunity to realize incremental margins. We believe the variety of our merchant activities 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 financial, strategic and technical skills needed to execute strategic transactions that support our business and financial objectives, including joint ventures, joint ownership arrangements, acquisitions and divestitures. Since 2016, we have consummated over 10 joint venture and/or joint ownership arrangements, including the Permian JV formation completed in October 2021, and completed over $4.5 billion of divestitures of non-core assets and/or strategic sales of partial interests in selected assets. In addition, although acquisitions and capital projects are not the primary focus of our current capital allocation priorities, since the completion of our initial public offering in 1998, we have completed and integrated over 90 acquisitions with an aggregate purchase price of approximately $13.7 billion and implemented investment capital projects totaling approximately $16.9 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 15 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.
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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 maximizing free cash flow, continuing to reduce leverage and 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 leverage multiple averaging between 3.75x to 4.25x, which is calculated as total debt plus 50% of preferred units, divided by Adjusted EBITDA attributable to PAA (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 reconciliation to Adjusted EBITDA attributable to PAA.);
◦this is roughly equivalent to a long-term debt-to-Adjusted EBITDA attributable to PAA multiple of between 3.0x and 3.5x;
•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.
At December 31, 2021, our publicly-traded senior notes comprised approximately 99% of our long-term debt. Additionally, we also routinely incur short-term debt primarily in connection with our merchant activities that involve the simultaneous purchase and forward sale of crude oil and NGL. The crude oil and NGL purchased in these transactions are volumetrically 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.
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. Our approach to sustainability involves integrating prudent environmental, social and governance (“ESG”) practices throughout the organization with a focus on transparency and building trust among stakeholders, managing operating and business risks and minimizing environmental and climate-related impacts, and levering our people, assets and systems to maximize long-term value for our stakeholders. The tenets of sustainability align with our values, underpin our business strategy and offer a framework to measure and report our progress. Annual environmental, safety and operational performance targets help us measure progress toward meeting our sustainability objectives. Performance against such targets is also a factor in determining annual bonus compensation for our employees, which further incentivizes desired behaviors and outcomes. In addition, in 2021 we established a new Health, Safety, Environmental and Sustainability (“HSES”) Board Committee to provide additional oversight and perspectives with respect to HSES and ESG matters. 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.
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Description of Segments and Associated Assets
Our business activities are conducted through two segments—Crude Oil and Natural Gas Liquids (“NGL”). Prior to the fourth quarter of 2021, our reporting segments were Transportation, Facilities and Supply and Logistics. The change in our segments is reflective of a change in how our Chief Operating Decision Maker (“CODM”) (our Chief Executive Officer) views our business and stems primarily from (i) a multi-year transition in the midstream energy industry driven by increased competition that has reduced the stand alone earnings opportunities of our supply and logistics activities such that those activities now primarily support our effort to increase the utilization of our Crude Oil and NGL assets and (ii) internal changes regarding the oversight and reporting of our assets and related results of operations. See Note 20 to our Consolidated Financial Statements for additional information.
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, 2021. 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 segments.
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Crude Oil Segment
Crude Oil Market and Business 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 of a particular grade or type of crude oil. 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, combined with the value of finished goods created, drive a refinery’s choice of feedstock.
Our business model integrates 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.
Our Crude Oil segment operations generally consist of gathering and transporting crude oil using pipelines, gathering systems, trucks and at times on barges or railcars, in addition to providing terminalling, storage and other facilities-related services utilizing our integrated assets across the United States and Canada. Our assets serve third parties and are also supported by our merchant activities. Our merchant activities include the purchase of crude oil supply and the movement of this supply on our assets to sales locations, including our terminals, third-party connecting carriers, regional hubs or to refineries. Our merchant activities are subject to our risk-management policies and may include the use of derivative instruments to hedge our exposure. Crude oil sales arrangements are also subject to our credit policies.
The figure below provides an illustrative and simplified overview of the assets and activities associated with our Crude Oil segment:
With respect to the transportation assets in this segment, we primarily generate revenue through a combination of tariffs, pipeline capacity agreements and other transportation fees. With respect to our facilities assets in this segment, we primarily generate revenue through a combination of month-to-month and multi-year agreements and arrangements which include (i) storage, throughput and loading/unloading fees at our crude oil facilities, and (ii) fees from condensate processing services. We also generate significant revenue through our commercial and merchant activities that supply volumes to our transportation and storage assets, although such activities are generally low margin.
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Crude Oil Segment Assets Overview
As of December 31, 2021, in this segment we employed a variety of owned or, to a much lesser extent, leased long-term physical transportation and facilities assets throughout the United States and Canada, including approximately:
•18,300 miles of active crude oil transportation pipelines and gathering systems, and an additional 110 miles of pipelines that support our crude oil storage and terminalling facilities;
•74 million barrels of commercial crude oil storage capacity at our terminalling and storage locations;
•38 million barrels of active, above-ground tank capacity used to facilitate pipeline throughput and help maintain product quality segregation;
•four marine facilities in the United States;
•a condensate processing facility located in the Eagle Ford area of South Texas with an aggregate processing capacity of 120,000 barrels per day;
•seven crude oil rail terminals and 2,100 crude oil railcars; and
•640 trucks and 1,275 trailers.
Additionally, our assets include the linefill associated with our commercial activities, including approximately:
•15 million barrels of crude oil linefill in pipelines and tanks owned by us; and
•3 million barrels of crude oil utilized as linefill in pipelines owned by third parties or otherwise required as long-term inventory.
Crude Oil Pipelines
The following table presents active miles and average daily volumes for our crude oil pipelines in the United States and Canada as of December 31, 2021, grouped by geographic location:
(in thousands)
Permian Basin:
(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 for pipelines owned by unconsolidated entities or through undivided joint interests. 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. Volumes associated with acquisitions represent total volumes for the number of days we actually owned the assets divided by the number of days in the period.
(3)All of our gathering pipelines in the Permian Basin are owned by the Permian JV, a consolidated entity in which we own a 65% interest. The Permian JV has a 40% interest in an unconsolidated entity that owns one of the gathering pipelines in the Permian Basin.
(4)Includes pipelines operated by a third party.
A significant portion of our crude oil 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.
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 allowing for 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) a refinery or other major market hubs, such as the Houston market.
Gathering Pipelines
Permian Basin. We operate approximately 4,900 miles of gathering pipelines in both the Midland Basin and the Delaware Basin that in aggregate represent approximately 3.7 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. All of our gathering pipelines in the Permian Basin are owned by the Permian JV, a consolidated entity in which we own a 65% interest.
South Texas/Eagle Ford. We own and operate various gathering systems in the Eagle Ford that connect into our Eagle Ford joint venture pipeline system that can deliver crude oil into markets in the Corpus Christi area, or to third-party pipelines with access to Houston area refiners.
Mid-Continent. 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 that source crude oil from truck terminals and pipeline-connected facilities to deliver to the Enbridge Mainline system at our Kerrobert and Regina terminals in Saskatchewan.
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Intra-basin Pipelines
Permian Basin. Our intra-basin pipeline system in the Permian Basin has a capacity of approximately 3.1 million barrels per day and 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. A majority of the intra-basin pipeline system is owned by the Permian JV, a consolidated entity in which we own a 65% interest.
Canada. We own and operate intra-basin pipelines with capacity of approximately 300,000 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 one cross-border pipeline that has the flexibility to move up to 40,000 barrels per day of Canadian crude oil to our Rocky Mountain area long-haul pipelines.
Long-haul Pipelines
Permian Basin. We own interests in multiple long-haul pipeline systems that, on a combined basis, represent approximately 1.7 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% undivided joint interest (“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 an 80% UJI, which equates to 400,000 barrels of the capacity of the pipeline. 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. The pipeline, operated by a subsidiary of Magellan Midstream Partners, L.P., originates at Colorado City, Texas and extends to Houston, Texas. The BridgeTex 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. The Cactus Pipeline connects to our Eagle Ford joint venture pipeline system at Gardendale for access to the Corpus Christi, Texas market. Movements to Corpus Christi are made on a joint tariff with the Eagle Ford joint venture pipeline.
•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 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 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, was placed in service in the first quarter of 2022, at which time long-term shipper commitments became effective. The third phase of the project, which includes the segments from Wink,
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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.
Mid-Continent. 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 Mid-Continent region.
•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.
•Red River Pipeline (Cushing to Longview). We own 67% of the legal entity that owns the Red River Pipeline through a joint venture with Delek Logistics Partners, LP (“Delek”). 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. 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.
Gulf Coast. We own an approximate 54% interest in the legal entity that owns the Capline Pipeline. Upon completion of its reversal project in 2021, the Capline Pipeline extends from Patoka, Illinois to various terminals in St. James, Louisiana. The Capline Pipeline is supported by long-term shipper commitments, and a subsidiary of Marathon Petroleum Corporation serves as the operator.
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 the Western Corridor pipeline system that extends from the Canadian border to our terminal in Guernsey, Wyoming. This pipeline system receives crude oil from our Rangeland Pipeline 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 which, through a UJI arrangement, owns 290,000 barrels per day of capacity in the Saddlehorn Pipeline. 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.
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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 Mid-Continent region gathering pipelines. Additionally, the terminal supplies crude oil to all of our joint venture, Mid-Continent region long-haul pipelines.
Our Midland terminal has access to all of the Permian JV gathering pipelines, either through direct connections, or through the Permian JV intra-basin pipelines. Likewise, the terminal is also either directly connected, or connected through the Permian JV intra-basin pipelines to all 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.
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 commercial crude oil storage capacity by location as of December 31, 2021:
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.
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 stabilized condensate is delivered to a third-party pipeline that delivers into 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.
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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. Our crude oil rail facilities have aggregate loading and unloading capacity of 264,000 and 350,000 barrels per day, respectively.
Natural Gas Liquids (“NGL”) Segment
NGL Market and Business 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. The individual NGL components are used for various purposes including heating, engine and industrial fuels, a component of motor gasoline and as the primary feedstock for petrochemical facilities that produce many everyday consumer products, including a wide range of plastics and synthetic rubber.
Our NGL segment operations involve natural gas processing and NGL fractionation, storage, transportation and terminalling. Our NGL revenues are primarily derived from a combination of (i) providing gathering, fractionation, storage, and/or terminalling services to third-party customers for a fee, and (ii) our merchant activities that support the assets. Our merchant activities include the acquisition of extraction rights from producers and/or shippers of the gas streams that pass through our Empress facility. The extraction rights 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. We also acquire NGL mix supply and use our assets to store and fractionate it into finished products to sell to third party customers. We may also acquire finished NGL products to be seasonally stored in our storage caverns, which is then resold to third-party customers. Often times we will use derivative instruments to hedge the margins related to these merchant activities. Such hedging activity is governed by our risk management policies. NGL sales arrangements are also subject to our credit policies.
The figure below provides an illustrative and simplified overview of the assets and activities associated with our NGL segment:
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NGL Segment Assets Overview
We operate a highly integrated network of assets, strategically positioned across Canada and the United States, with a particular focus on serving production from the liquids-rich Western Canadian Sedimentary Basin. As of December 31, 2021, the assets utilized in our NGL segment included the following:
•four natural gas processing plants;
•nine fractionation plants located throughout Canada and the United States with an aggregate useable capacity of approximately 200,100 barrels per day;
•NGL storage facilities with approximately 28 million barrels of capacity;
•approximately 1,620 miles of active NGL transportation pipelines and an additional 55 miles of pipeline that support our NGL storage facilities;
•16 NGL rail terminals and approximately 3,900 NGL rail cars; and
•approximately 220 trailers.
Additionally, our assets include the linefill associated with our commercial activities, including approximately:
•2 million barrels of NGL linefill in pipelines and tanks owned by us; and
•1 million barrels of NGL utilized as linefill in pipelines owned by third parties or otherwise required as long-term inventory.
The tables below present volumes and capacities for our NGL assets and activities as of December 31, 2021 and our natural gas processing and NGL infrastructure and activities are described further below.
NGL Storage Facilities StorageCapacity (1)(MMBbls)
Fort Saskatchewan 11
Sarnia 7
Empress 4
Other 6
Ownership Interest Approximate System Miles (3) Average Volumes (2)(MBbls/d)
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Ownership Interest Number ofRack Spots Number ofStorage Spots
(1)Represents total average annual capacity of the facilities, net to our ownership interest.
(2)Average daily volumes are calculated as the total volumes for the year, net to our share, divided by the number of days in the year.
(3)Includes total mileage of pipelines in which we own less than 100%.
Natural Gas Processing and NGL Infrastructure
Our network of liquids infrastructure includes NGL fractionation facilities, underground NGL storage caverns, above ground storage tanks, NGL pipelines, and rail and truck terminals. With these assets, we process, fractionate, store and transport NGL such as ethane, propane, butane and condensate. The unique integrated and geographically diverse nature of our infrastructure provides the opportunity to maximize margins across the NGL value chain for both us and our customers, by enabling the movement of product from liquids rich producing regions to fractionators, refineries, export facilities and high-value market hubs across Canada. The most significant of these assets include the following:
Empress Facility
We own and/or operate four gas processing facilities near Empress, Alberta, with our ownership ranging from 66% to 100%. These facilities, referred to as straddle plants because they “straddle” gas transportation pipelines, process natural gas to extract ethane and NGL mix entrained in the gas stream before returning the gas to the transportation pipelines. We acquire the rights to extract the NGL from producers and/or shippers of the gas streams that pass through our Empress facility and then purchase natural gas to replace the thermal content attributable to the NGL that was extracted. The NGL mix can be fractionated at our Empress facility or transported along the Enbridge pipeline system for fractionation at our Sarnia facility.
Our Empress plants are capable of processing up to 5.5 Bcf of natural gas per day; however, supply available to these plants is typically in the 2.5 to 4.0 Bcf per day range. These plants produce approximately 50,000 to 85,000 barrels per day of ethane, and 30,000 to 50,000 barrels per day of NGL mix. Our Empress fractionation facility is capable of processing and producing up to 23,300 barrels per day of NGL products and is connected to rail loading infrastructure at Empress and our PPTC pipeline system which enables NGL to be transported to storage and loading terminals in Saskatchewan and Manitoba.
Co-Ed Pipeline
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.
Fort Saskatchewan Complex
Our 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 44,400 barrels per day of fractionation capacity, 12 storage caverns, and truck and rail loading capability. Our Fort Saskatchewan fractionation facility has a design capacity of 88,400 barrels per day and is able to produce up to approximately 44,400 barrels per day of propane, butane and condensate. The remaining throughput capacity is used to produce a propane and butane mix, which is transported via the Enbridge pipeline system to our Sarnia facility for further fractionation.
Within the Fort Saskatchewan area, we also hold an approximately 21% ownership in the Keyera Fort Saskatchewan facility, which includes fractionation capacity of approximately 17,300 barrels per day, net to our interest, and 16 storage caverns.
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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 with rail and truck loading capabilities. The Sarnia Area facilities are served by a network of multiple pipelines connected to various refineries, chemical plants, and other pipeline and railroad systems in the area. This pipeline network also delivers product between our Sarnia facility and our Windsor and St. Clair storage facilities. The Sarnia fractionator receives NGL feedstock primarily from the Enbridge pipeline system and, to a lesser extent, from our rail unloading facility. The fractionation unit is able to produce an average of approximately 100,000 barrels per day of NGL products. Our ownership in the various processing units at the Sarnia fractionator ranges from 62% to 84%.
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 $48 per barrel to a high of approximately $85 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 or through our facilities may be adversely impacted. Alternatively, in periods where supply exceeds regional demand and/or pipeline egress, product flows on our pipelines or through our facilities may be favorably impacted. In executing our business model, we employ a variety of financial risk management tools and techniques to manage our financial risk, predominantly related to our merchant activities. These are discussed in greater detail in the “—Risk Management” section below.
In addition, relative contribution levels will vary from quarter-to-quarter due to seasonality, particularly with respect to our NGL merchant activities.
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.
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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 merchant 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.
Credit
Our merchant activities in our Crude Oil and NGL segments 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.
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 or NGL, 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. See Note 3 to our Consolidated Financial Statements for further discussion of our credit review process and risk management procedures.
Customers
ExxonMobil Corporation and its subsidiaries accounted for 15%, 12% and 12% of our revenues for the years ended December 31, 2021, 2020 and 2019, respectively. Marathon Petroleum Corporation and its subsidiaries accounted for 12%, 13% and 12% of our revenues for the years ended December 31, 2021, 2020 and 2019, respectively. BP p.l.c. and its subsidiaries accounted for 10% of our revenues for the year ended December 31, 2021. 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, 2021. The majority of revenues from these customers pertain to our Crude Oil segment merchant activities, and sales to these customers occur at multiple locations. If we were to lose one or more of these customers, there is risk that we would not be able to identify and access a replacement market at a comparable margin. For a discussion of credit 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 in the Permian Basin and other areas, together with meaningful changes and delays in expected production growth due to COVID-19 impacts, we anticipate competition for uncommitted barrels and contract renewals and extensions will continue to be amplified in the coming years, increasing our contract renewal and customer retention risk and putting downward pressure on tariffs and margins.
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.
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We also face competition with respect to our merchant activities 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. In addition, recently constructed 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.
Ongoing Activities Related to Strategic Transactions
We are continuously engaged in the evaluation of potential transactions that support our current business strategy. In the past, such transactions have included the sale of non-core assets, the sale of partial interests in assets to strategic joint venture partners, acquisitions and large investment capital projects. With respect to a potential divestiture or acquisition, we may conduct an auction process or participate in an auction process conducted by a third party or we may negotiate a transaction with one or a limited number of potential buyers (in the case of a divestiture) or sellers (in the case of an acquisition). Such transactions could have a material effect on our financial condition and results of operations.
We typically do not announce a transaction until after we have executed a definitive agreement. 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 and acquisitions involve risks that may adversely affect our business.”
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Joint Venture and Joint Ownership Arrangements
We are party to more than 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 our systems and improving returns.
In October 2021, we and Oryx Midstream Holdings LLC (“Oryx Midstream”) completed the merger, in a cashless, debt-free transaction, of our respective Permian Basin assets, operations and commercial activities into a newly formed joint venture, the Permian JV. The Permian JV includes all of Oryx Midstream’s Permian Basin assets and, with the exception of our long-haul pipeline systems and certain of our intra-basin terminal assets, the vast majority of our assets located within the Permian Basin. We own 65% of the Permian JV, operate the combined assets and reflect the entity as a consolidated subsidiary in our consolidated financial statements. See Note 7 to our Consolidated Financial Statements for additional information.
The following table summarizes our significant JVs as of December 31, 2021:
Entity Type of Operation JVOwnershipPercentage
BridgeTex Pipeline Company, LLC Crude Oil Pipeline 20%
Cactus II Pipeline LLC Crude Oil Pipeline (1) 65%
Capline Pipeline Company LLC Crude Oil Pipeline 54%
Diamond Pipeline LLC Crude Oil Pipeline (1) 50%
Eagle Ford Pipeline LLC Crude Oil Pipeline (1) 50%
Eagle Ford Terminals Corpus Christi LLC Crude Oil Terminal and Dock (1) 50%
Red River Pipeline Company LLC (2) (4) Crude Oil Pipeline (1) 67%
Saddlehorn Pipeline Company, LLC (4) Crude Oil Pipeline 30%
White Cliffs Pipeline, LLC Crude Oil Pipeline 36%
Wink to Webster Pipeline LLC (4) Crude Oil Pipeline 16%
(1)Assets are operated by Plains.
(2)We consolidate the entity based on control, with our partner’s interest accounted for as a noncontrolling interest.
(3)Entity owns a 40% interest in OMOG JV LLC, an unconsolidated entity that owns a crude oil pipeline.
(4)Entity owns a UJI in the crude oil pipeline.
The following table summarizes our significant UJIs as of December 31, 2021, excluding UJIs that are indirectly owned by us through JVs (e.g., Wink to Webster, Saddlehorn and Red River JVs):
Asset Type ofOperation UJIOwnershipPercentage
Basin Pipeline (1) Crude Oil Pipeline 87%
Empress Processing (1) NGL Facility 66% to 92%
Fort Saskatchewan NGL Storage and Fractionation (2) NGL Facility 21% to 48%
Western Corridor System (2) Crude Oil Pipeline 21% to 58%
Sarnia NGL Storage and Fractionation (2) NGL Facility 62% to 84%
Sunrise II Pipeline (1) Crude Oil Pipeline 80%
(1)Asset is operated by Plains.
(2)Certain of these assets are operated by Plains.
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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, 2021, we have completed asset sales totaling more than $4.5 billion.
Acquisitions
Since our initial public offering in 1998, the acquisition of midstream assets and businesses has been an important component of our business strategy. While the pace of our acquisition activity has slowed down in recent years, we continue to selectively analyze and pursue the acquisition of assets and businesses that are strategic and complementary to our existing operations. Over the last five years, we completed several acquisitions for an aggregate of approximately $2.0 billion. Such amount does not include the Permian JV formed in October 2021. See “Joint Venture and Joint Ownership Arrangements” above for additional information.
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 2022 capital plan consists of capital-efficient, highly contracted projects that help address industry needs.
Total investment capital for the year ending December 31, 2022 is projected to be approximately $330 million, of which approximately half is expected to be associated with the Permian JV. Additionally, maintenance capital for 2022 is projected to be $220 million. Note that 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.
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.
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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 or remedial obligations or the incurrence of capital expenditures, imposition of restrictions, delays or cancellations in the permitting or performance of projects, 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 or other materials 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.
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”) with respect to crude oil and NGL. 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”) and provincial agencies.
United States
Pursuant to the authority under the HLPSA, as amended from time to time, PHMSA has promulgated regulations 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 locations where a pipeline leak or rupture could affect higher risk areas, known as high consequence areas (“HCAs”). The HCAs for crude oil and NGL pipelines are based on 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 $21 million in 2021. Based on currently available information, our preliminary estimate for 2022 is that we will incur approximately $30 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 $10 million in 2021, and our preliminary estimate for 2022 is that we will incur approximately $15 million of such costs.
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Legislation in the past decade has resulted in more stringent mandates for pipeline safety and has charged PHMSA with developing and adopting regulations that impose increased pipeline safety requirements on pipeline operators. In particular, the HLPSA was amended over the past decade by the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, the Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2016 and, most recently, the Protecting Our Infrastructure of Pipelines and Enhancing Safety (“PIPES”) Act of 2020. Each of these laws imposed increased pipeline safety obligations on pipeline operators, with the PIPES Act of 2020 reauthorizing PHMSA programs through fiscal year 2023. The regulatory changes precipitated by these actions have increased our cost to operate. For example, in October 2019, PHMSA published a final rule for hazardous liquid transmission and gathering pipelines that significantly extends and expands the reach of certain of its integrity management requirements, use of in-line inspection tools by 2039 (unless the pipeline cannot be modified to permit such use), increased annual, accident and safety-related conditional reporting requirements, and expanded use of leak detection systems beyond HCAs. Separately, in June 2021, PHMSA issued an Advisory Bulletin advising pipeline and pipeline facility operators of applicable requirements to update their inspection and maintenance plans for the elimination of hazardous leaks and minimization of natural gas released from pipeline facilities. PHMSA, together with state regulators, are expected to commence inspection of operator plans in 2022.
Pursuant to the Oil Spill Response: Environmentally and Ecologically Sensitive Areas Bill (“AB-864”), signed by the Governor of California in 2015, operators of hazardous liquid pipelines located near environmentally and ecologically sensitive areas (“EESA”) connected to or located in the coastal zone are now required 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. Affected pipeline operators were required by May 1, 2021 to make requests for exemption (for pipelines located outside the Coastal Zone, if the operator could show through spill modeling / risk analysis that a release would not impact the coastal zone portion of an EESA) or deferral (for pipelines already employing BAT) from the provisions of this Article. Additionally, by October 1, 2021 affected operators were required to submit a risk analysis, BAT evaluation, and implementation plan for existing pipelines. Also, by April 1, 2023, affected operators must complete retrofits of existing pipelines with BAT. 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.
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 $15 million in 2021. For 2022, we have budgeted approximately $38 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 $66 million in 2021. 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 2022 is that we will incur approximately $96 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.
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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, and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the U.S. Occupational Safety and Health Administration (“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 may become subject to more rigorous and costly disposal requirements, resulting in additional capital expenditures or operating expenses.
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 (“RMP”) 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 2016, the EPA finalized revisions to the 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. In December 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 and President Biden issued an executive order in January 2021 that, among other things, calls for EPA’s review of the current version of the RMP rule, which included hosting listening sessions and receiving comments on the rule from the public during 2021. 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.
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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.
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. Two 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 recent years, there has been considerable uncertainty surrounding regulation of methane emissions. In 2020, the Trump Administration revised performance standards for methane established in 2016 to lessen the impact of those standards and remove the transmission and storage segments from the source category for certain regulations. However, shortly after taking office, President Biden issued an executive order calling on the EPA to revisit federal regulations regarding methane and establish new or more stringent standards for existing or new sources in the oil and gas sector, including the transmission and storage segments. The U.S. Congress also passed, and President Biden signed into law, a revocation of the 2020 rulemaking, effectively reinstating the 2016 standards. In response to President Biden’s executive order, in November 2021, the EPA issued a proposed rule that, if finalized, would establish standards of performance for methane and volatile organic compound (“VOC”) emissions for new sources and existing sources in the crude oil and natural gas source category. This proposed rule would apply to upstream and midstream facilities at oil and natural gas well sites, natural gas gathering and boosting compressor stations, natural gas processing plants, and transmission and storage facilities. Owners or operators of affected emissions units or processes would have to comply with specific standards of performance that may include leak detection using optical gas imaging and subsequent repair requirements, reduction of emissions by 95% through capture and control systems, zero-emission requirements, operations and maintenance requirements, and so-called green well completion requirements. The EPA plans to issue a supplemental proposal enhancing this proposed rulemaking in 2022 that will contain additional requirements that were not included in the November 2021 proposed rule. EPA anticipates issuing a final rule by the end of 2022.
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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 “30x30” 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. A draft of potential strategies in pursuing this “30x30” state goal was released in late 2021 with public comments to be solicited through early 2022. In May 2021, the Governor of California together with the federal government announced that the Department of Interior, Bureau of Ocean Energy Management, and the Department of Defense have reached an agreement with the State of California to lease 399-square miles off California’s central coast for offshore wind development. In furtherance of this agreement, the Governor signed legislation, AB 525, in September 2021 that will require the California Energy Commission to establish offshore wind goals for 2030 and 2045 as well as to develop a strategic plan to develop the industry off California’s coast. In July 2021, the Governor of California issued a plan outlining the state’s goals to achieve a 100% clean electricity system by 2045 that supports long-term clean energy reliability, which includes objectives for increasing the diversity of the state’s energy focus, to include, for example, offshore wind, modernizing the state power grid and incorporating distributed energy resources, increasing long-duration energy storage projects, pursuing grid hardening and resiliency projects to make transmission and distribution lines more fire resistant and enhance strategic placement of remote grids in vulnerable communities, and increasing the electrification of state transportation systems, homes and businesses.
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.
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 non-binding carbon emission reduction policies through individually-determined reduction goals every five years after 2020, 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. President Biden announced in April 2021 a new, more rigorous nationally determined contribution (“NDC”) emissions reduction level of 50-52% reduction from 2005 levels in economy-wide net GHG emissions by 2030. Moreover, the international community gathered again in Glasgow in November 2021 at the 26th Conference of the Parties (“COP26”), during which multiple announcements were made, including a call for parties to eliminate certain fossil fuel subsidies and pursue further action on non-CO2 GHGs. Relatedly, at COP26, the United States and European Union jointly announced the launch of a Global Methane Pledge, an initiative which over 100 countries joined, committing to a collective goal of reducing global methane emissions by at least 30 percent from 2020 levels by 2030, including “all feasible reductions” in the energy sector. The impacts of these orders, pledges, agreements and any legislation or regulation promulgated to fulfill the United States’ commitments under the Paris Agreement, COP26 or other international conventions cannot be predicted at this time.
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Governmental, scientific, and public concern over the threat of climate change arising from GHG emissions has resulted in increasing political risks in the United States. For example, President Biden has issued several executive orders calling for more expansive action to address climate change, including suspension of new oil and gas operations on federal lands and waters. The suspension of the federal leasing activities prompted legal action by several states against the Biden Administration, resulting in issuance of a nationwide preliminary injunction by a federal district judge in Louisiana in June 2021, effectively halting implementation of the leasing suspension; however, the federal government is appealing the district court decision. 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. Litigation risks are also increasing as a number of cities, local governments and other plaintiffs have sought to bring lawsuits against oil and natural gas exploration and production companies in state or federal court, alleging, among other things, that such companies created public nuisances by producing fuels that contributed to global warming effects, such as rising sea levels, and therefore are responsible for roadway and infrastructure damages as a result, or alleging that the companies have been aware of the adverse effects of climate change for some time but defrauded their investors by failing to adequately disclose those impacts.
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. Institutional lenders who provide financing to fossil-fuel energy companies also have become more attentive to sustainable lending practices that favor “clean” power sources, such as wind and solar, making those sources more attractive, and some of them may elect not to provide funding for fossil fuel energy companies. Many of the largest U.S. banks have made “net zero” carbon emission commitments and have announced that they will be assessing financed emissions across their portfolios and taking steps to quantify and reduce those emissions. At COP26, the Glasgow Financial Alliance for Net Zero (“GFANZ”) announced that commitments from over 450 firms across 45 countries had resulted in over $130 trillion in capital committed to net zero goals. The various sub-alliances of GFANZ generally require participants to set short-term, sector-specific targets to transition their financing, investing, and/or underwriting activities to net zero emissions by 2050. These and other developments in the financial sector could lead to some lenders restricting access to capital for or divesting from certain industries or companies, including the oil and natural gas sector, or requiring that borrowers take additional steps to reduce their GHG emissions. Additionally, there is the possibility that financial institutions may be pressured or required to adopt policies that limit funding for fossil fuel energy companies. In late 2020, the Federal Reserve announced that it has joined the Network for Greening the Financial System (“NGFS”), a consortium of financial regulators focused on addressing climate-related risks in the financial sector. More recently, in November 2021, the Federal Reserve issued a statement in support of the efforts of the NGFS to identify key issues and potential solutions for the climate-related challenges most relevant to central banks and supervisory authorities. While we cannot predict what policies may result from these announcements, a material reduction in the capital available to the fossil fuel industry could make it more difficult to secure funding for exploration, development, production, transportation, and processing activities, which could impact our business and operations.
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, as well as chronic shifts in temperature and precipitation patterns. These climatic developments have the potential to cause physical damage to our assets and thus could have an adverse effect on our operations. Additionally, changing meteorological conditions, particularly temperature, may result in changes to the amount, timing, or location of demand for energy or our customer’s production, which could reduce the need for our services. While our consideration of changing climatic conditions and inclusion of safety factors in design is intended to reduce the uncertainties that climate change and other events may potentially introduce, our ability to mitigate the adverse impacts of these events depends in part on the effectiveness of our facilities, particularly those located in coastal or flood prone areas, and our disaster preparedness and response and business continuity planning, which may not have considered or be prepared for every eventuality.
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 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.
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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 after 2020 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 began at CAD$20 per tonne in 2019 and has risen by CAD$10 per year, reaching CAD$50 per tonne beginning in 2022) and an output based pricing system (“OBPS”) designed to address competitiveness risk for large emitters.
In regards to the federal pricing on carbon pollution, in December 2021, the federal government published an update to the federal carbon pricing benchmark beyond 2022. Under the updated scheme, the minimum national carbon pollution price has been proposed for 2023 to 2030 with the carbon price set at CAD$65/tonne in 2023 with a further annual increase of CAD$15 per year up to $170/tonne in 2030. Costs for compliance in respect of the cost of carbon will be budgeted annually as part of ordinary operating cost processes.
Canada passed the Canadian Net-Zero Emissions Accountability Act in June 2021 which formally establishes the country’s 2050 net zero target. The act requires the setting of legally-binding, five-year emissions reduction targets (2030, 2035, 2040 and 2045). Pursuant to this act, in July 2021, the federal government announced an enhanced NDC emissions reduction level for Canada of 40‐45 percent below 2005 levels by 2030. Moreover, in accord with this act, Canada must set the subsequent 2035, 2040 and 2045 targets at least 10 years in advance. The 2030 Emissions Reduction Plan has yet to be published. The deadline for the federal government to establish the plan is March 29, 2022. The impact of this legislation on our Canadian operations will be addressed and budgeted annually as part of ordinary operating costs processes.
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, with certain of those requirements becoming effective in January 2020 and the remainder by 2023. 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 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 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 specified January 1, 2022 as the start date of the EPS. Our Sarnia facility will be shifting to the EPS from the OBPS program. Costs for compliance with the OBPS or EPS are budgeted annually and are 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.
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Alberta. The Alberta Climate Change and Emissions Management Act (2003) 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 (2007) (“SGER”) was the initial program introduced which imposed GHG emission limits on large emitters and required reduction in GHG emission intensity. In January 2018, the SGER was replaced with the Carbon Competitive Incentive Regulation (2018) (“CCIR”) for compliance years 2018 and 2019. In January 2020, Alberta implemented the newly adopted Technology Innovation and Emissions Reduction (“TIER”) regulation, which brought in yet another version of a GHG reduction program to replace the GHG program under CCIR. Compliance options under TIER are similar to those under the previous CCIR program such that a GHG fund credit purchase will be required if reduction targets identified under the program are not attained. As was the case under SGER and CCIR, our Fort Saskatchewan and Empress VI facilities are mandatory participants under TIER. For economic reasons, Empress I - V and five of our other Canadian facilities opted in to be part of the TIER program for 2021. Under TIER, Alberta’s price on carbon was initially set at $30/tonne and was subsequently increased to $50/tonne for 2022 through Alberta Minister of Environment and Park’s Ministerial Order 87/2021. The price increase aligns with the carbon pricing established by the federal Greenhouse Gas Pollution Pricing Act.
Assets within the Alberta TIER program are also exempt from the federal fuel charge but other fuel consumption as part of Alberta 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 both January 2020 and January 2022. The cost for reporting and completing these requirements has been captured within the annual operational budgets.
Other Canadian Jurisdictions. Nova Scotia and Quebec cap and trade programs cover propane supplied by us to the Nova Scotia and Quebec markets. We are 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 Alberta. 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.
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The construction or expansion of pipelines often requires authorizations under the CWA, which authorizations may be subject to challenge. 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 federal district court for the District of Montana vacated the Corps’ NWP 12 after determining that it failed to comply with consultation requirements under the Endangered Species Act. While the district court’s order has subsequently been limited pending appeal, we cannot predict the ultimate outcome of this case and its impacts to the NWP program. In response to the vacatur, in January 2021, the Corps published a reissuance of a restructured NWP 12 for oil and natural gas pipeline activities that separated certain utilities formerly covered under the permit into other NWPs. An October 2021 decision by the District Court for the Northern District of California resulted in a vacatur of a 2020 rule revising the Clean Water Act Section 401 certification process, following which the Corps announced that it had temporarily suspended finalization of certain permitting decisions, including under NWP 12, that rely on a Section 401 certification or waiver under the 2020 rule. However, in November 2021, after a temporary pause on permit decisions reliant on a Section 401 water quality certification or waiver completed under the vacated regulations, Corps districts resumed making decisions on all permit applications and requests for nationwide permit verifications; as part of that decision making process, districts will coordinate with certifying authorities on water quality certifications that are potentially impacted by the vacatur order. While the full extent and impact of these recent developments is unclear at this time, any disruption in our ability to obtain coverage under NWP 12 or other general permits may result in increased costs and project delays if we are forced to seek individual permits from the Corps.
Also, there continues to be uncertainty on the federal government’s applicable jurisdictional reach under the Clean Water Act over waters of the United States, including wetlands, as the EPA and the Corps under the Obama, Trump and Biden Administrations have pursued multiple rulemakings since 2015 in an attempt to determine the scope of such reach. While the EPA and Corps under the Trump Administration issued a final rule in April 2020 narrowing federal jurisdictional reach over waters of the United States, President Biden issued an executive order in January 2021 to further review and assess these regulations consistent with the new administration’s policy objectives, following which the EPA and Corps announced plans in June 2021 to initiate a new rulemaking process that would repeal the 2020 rule and restore protections that were in place prior to 2015. Although the EPA and Corps did not seek to vacate the 2020 rule on an interim basis, two federal district courts in Arizona and New Mexico have vacated the 2020 rule in decisions announced during the third quarter of 2021. While these district court decisions may be appealed, it is clear that the EPA and Corps intend to adopt a more expansive definition for waters of the United States. As an initial step, the agencies published on December 7, 2021 a proposed rulemaking that would put back into place the pre-2015 definition of “waters of the United States” in effect prior to 2015 rule issued under the Obama Administration and updated to reflect consideration of Supreme Court decisions. The proposed rule, if adopted would serve as an interim approach to “waters of the United States” and provide the agency with time to develop a subsequent rule that builds upon the currently proposed rule based, in part, on additional stakeholder involvement. To the extent that the EPA and the Corps under the Biden Administration issues a final rule that expands the scope of the Clean Water Act’s jurisdiction in areas where we or our customers conduct operations, such developments could delay, restrict or halt permitting or development of projects, result in longer permitting timelines, or increased compliance expenditures or mitigation costs for our and our customers’ operations, which may reduce the rate of production from operators.
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.
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.
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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 petroleum products pipelines, be just and reasonable and not unduly 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 liquids pipelines and to streamline procedures in liquids 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 equals 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. The Commission received requests for rehearing of its December 2020 order and on January 20, 2022, granted rehearing and modified the oil index. Specifically, FERC granted rehearing of its December 2020 order and ordered that for the five-year period commencing July 1, 2021 and ending June 30, 2026, common carriers charging indexed rates will be permitted to adjust their indexed ceilings annually by Producer Price Index minus 0.21%. FERC directed oil pipelines to recompute their ceiling levels for the five-year period ending June 30, 2022 based on the new index level. Where an oil pipeline’s filed rates exceed its ceiling levels, FERC ordered such oil pipelines to reduce the rate to bring it into compliance with the recomputed ceiling level to be effective March 1, 2022. We have filed to adjust our FERC-regulated rates where applicable. The January 20, 2022 FERC order adjusting the current five-year index is currently under appeal to the U.S.Court of Appeals for the Fifth Circuit. 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 liquids pipeline 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 indexing 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, liquids 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 liquids 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 a liquids 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 pipeline profits in the United States are based on rates that are either grandfathered in part 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 under the ICA, which requires that tariff rates for liquids pipelines, which include both crude oil pipelines and petroleum products pipelines, be just and reasonable and not unduly 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 (“FRA”) of the DOT, 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 late 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 late 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.
Transportation Security Administration Security Directives
In 2021, in response to the Colonial Pipeline cybersecurity incident, The United States Department of Homeland Security’s Transportation Security Administration (“TSA”) issued two comprehensive security directives with various cyber security and reporting requirements for critical infrastructure pipeline owners and/or operators. Compliance with these security directives may have a significant impact on our operations and results of operations.
Cross Border Regulation
As a result of our cross border activities, including transportation and importation of crude oil and NGL 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.
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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 $1.3 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.
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. 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. 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.
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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, 2021, GP LLC and PMCULC employed approximately 4,100 people in North America, of which approximately 2,900 were employed in the U.S. and approximately 1,200 were employed in Canada. Approximately 69% of our workforce (approximately 2,800 employees) are field employees, which includes approximately 525 employees in our trucking division. Our employees are located in 23 states in the U.S. and in 5 provinces in Canada. Approximately 185 employees are covered by six separate collective bargaining agreements, one of which is currently being negotiated, while the remaining five are open for renegotiation in 2023 and 2024.
Health and Safety
Our people are our most valuable asset. We prioritize the health and safety of our employees and we are committed to protecting our employees and conducting our operations in a safe, reliable and responsible manner. We support our commitment to health and safety through extensive education and training and investment in necessary equipment, systems, processes and other resources, and we have a number of safety programs and campaigns that are shared across our operations, such as “Good Catch-Close Call” communications, periodic and situation specific safety stand-downs, lessons learned sharing and stop work authorization for all employees. We also have a number of programs that are focused on employee wellness, including an employee assistance program that provides free mental and behavioral support for employees. In addition, in order to incentivize performance in the areas of safety and environmental responsibility, our performance-based annual bonus program includes a safety component that is based on year-over-year reductions in our recordable injury rate, and an environmental responsibility component that is tied to year-over-year reductions in the number of federally reportable releases we experience. Although we failed to achieve our targeted reductions in these two areas in 2021, since 2017, for each of these metrics, we have achieved cumulative three-year reductions of more than 50%. In addition, in 2021 we established a new HSES Board Committee to provide additional oversight and perspectives with respect to HSES and ESG matters.
Diversity and Inclusion
We are committed to providing a professional work environment where all employees are treated with respect and dignity and provided with equal opportunities. To that end, we strive to develop a culture of inclusion and diversity in our workforce and aspire to employ a workforce that reflects the diversity of the communities where we operate. As of December 31, 2021, approximately 21% of our overall workforce was female (45% exclusive of field employees), and minorities represented approximately 31% of our U.S. workforce (37% exclusive of field employees).
To support diversity and inclusion efforts at Plains and across the broader industry, we created and sponsor an employee resource group called Cultivating Connections. This group is dedicated to encouraging diversity, inclusion and advancement of women in the industry through networking, mentoring, sharing experiences and ideas, training, and furthering the development of leadership skills. Through Cultivating Connections, an employee mentorship program was also established to encourage professional growth through the development of core competencies.
Training and Leadership Development