EDGAR 10-K Filing

Company CIK: 1581990
Filing Year: 2021
Filename: 1581990_10-K_2021_0001581990-21-000007.json

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ITEM 1. BUSINESS
Items 1 and 2. Business and Properties
General
Plains GP Holdings, L.P. is a publicly traded Delaware limited partnership that has elected to be taxed as a corporation for United States federal income tax purposes. PAGP’s Class A shares are listed on the Nasdaq Global Select Market (“Nasdaq”) under the ticker symbol “PAGP.” PAGP does not directly own any operating assets; as of December 31, 2020, its principal sources of cash flow are derived from an indirect investment in Plains All American Pipeline, L.P (“PAA”), a publicly traded Delaware limited partnership, through its 100% managing member member interest in Plains All American GP LLC (“GP LLC”) and its limited partner interest in Plains AAP, L.P. (“AAP”).
PAA’s business is based on the fundamental thesis that hydrocarbons are essential to the security and advancement of human quality of life and will continue to play a major long-term role in the world economy. We believe that midstream energy infrastructure provides a critical link between energy supply and demand, and is fundamental to the maintenance and advancement of our modern-day standard of living. Acknowledging the need for multiple forms of energy to meet growing world-wide demand, we believe absolute hydrocarbon demand will increase over time, driven by global population growth and a desire to improve quality of life. As a result, we believe that hydrocarbon energy infrastructure will remain critical and valuable.
PAA’s 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, PAA owns 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. PAA’s assets and the services it provides are primarily focused on crude oil, NGL and natural gas.
PAA’s operations are conducted directly and indirectly through its primary operating subsidiaries, which comprise 100% of the assets and operations affiliated with PAA and its subsidiaries. As used in this Form 10-K and unless the context indicates otherwise (taking into account the fact that PAGP has no operating activities apart from those conducted by PAA and its subsidiaries), the terms “Partnership,” “Plains,” “we,” “us,” “our,” “ours” and similar terms refer to PAGP and its subsidiaries.
Organizational Structure
The diagram below shows our organizational structure as of December 31, 2020 in a summarized format:
(1)Each Class C share represents a non-economic limited partner interest in us. The number of Class C shares that PAA owns is equal to the number of outstanding PAA common units and Series A Preferred units (“Common Unit Equivalents”) that are entitled to vote, pro rata with the holders of our 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 PAA votes at the direction of and as proxy for the PAA common unitholders and Series A preferred unitholders in such director elections. PAA common units held by AAP and PAA Series B preferred units are not entitled to vote in the election of directors.
(2)PAA holds (i) direct and indirect ownership interests in consolidated operating subsidiaries including, but not limited to, Plains Marketing, L.P., Plains Pipeline, L.P., Plains Midstream Canada ULC (“PMCULC”) and PAA Natural Gas Storage, L.P. and (ii) indirect equity interests in unconsolidated entities including, but not limited to, BridgeTex Pipeline Company, LLC, Cactus II Pipeline LLC, Capline Pipeline Company LLC, Diamond Pipeline LLC, Eagle Ford Pipeline LLC, Eagle Ford Terminals Corpus Christi LLC, Saddlehorn Pipeline Company, LLC, STACK Pipeline LLC, White Cliffs Pipeline, L.L.C. and Wink to Webster Pipeline LLC.
Our Business Strategy
Unless we directly acquire and hold assets or businesses in the future, our cash flows will be generated solely from the cash distributions we receive on the Class A units of AAP (“AAP units”) we directly and indirectly own. AAP currently receives all of its cash flows from distributions on the PAA common units it owns.
Accordingly, our primary business objective is to increase our cash available for distribution to our Class A shareholders through the execution by PAA of its business strategy. In addition, we may facilitate PAA’s growth activities through various means, including, but not limited to, making loans, purchasing equity interests or providing other forms of financial support to PAA.
We maintain a one-to-one relationship between our Class A shares and the underlying PAA common units in which we have an indirect economic interest through our ownership interests in AAP and GP LLC (referred to as “Economic Parity”), such that the number of our outstanding Class A shares equals the number of AAP units we directly and indirectly own, which in turn equals the number of PAA common units held by AAP attributable to our direct and indirect ownership interest in AAP.
PAA’s Business Strategy
PAA’s principal business strategy is to provide competitive and efficient midstream infrastructure and logistics services to producers, refiners and other customers. PAA strives 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 its transportation, terminalling, storage, processing and fractionation assets with its supply, logistics and distribution expertise. PAA intends to execute its strategy by:
•Focusing on operational excellence, continuous improvement and running a safe, reliable, environmentally and socially responsible operation;
•Using its well positioned network of midstream infrastructure in conjunction with its commercial capabilities to provide market access, flexibility and value chain solutions to its customers, capture market opportunities, address physical market imbalances, mitigate risks and generate sustainable cash flow and margin;
•Optimizing its asset portfolio and operations to maximize returns on invested capital; and
•Pursuing a balanced, long-term financial strategy that is focused on maintaining an investment grade credit profile and enhancing financial flexibility by making disciplined capital allocation decisions.
We believe PAA’s successful execution of this strategy will enable it to generate sustainable earnings and cash flow, and will position PAA to reduce leverage and maintain an investment grade credit profile while increasing returns to equity holders over time.
PAA’s Competitive Strengths
We believe that the following competitive strengths position PAA to successfully execute its principal business strategy:
•Strategically located, geographically diverse and interconnected asset base that provides operational flexibility and commercial optionality. The majority of PAA’s primary Transportation segment assets are in crude oil service, are located in well-established crude oil producing regions (with PAA’s largest asset presence in the Permian Basin) and other transportation corridors and are connected, directly or indirectly, with PAA’s Facilities segment assets. The majority of PAA’s Facilities segment assets are located at major trading locations and premium markets that serve as gateways to major North American refinery and distribution markets where PAA has strong business relationships. In addition, PAA’s pipeline, rail, barge, truck and storage assets provide PAA’s customers and PAA with significant flexibility and optionality to satisfy demand and balance markets.
•Full-service integrated model and long-term focus attracts broad, diverse and high-quality customer base that supports sustainable fee-based cash flow generation. PAA’s strategically located and interconnected asset base enables it to provide its customers with a wide variety of services, including supply aggregation, quality segregation, flow assurance and market access. PAA focuses on building long-term relationships and alignment of interests with its customers. PAA believes this approach has helped it 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 its assets and, in turn, support long-term fee-based cash flow generation from its assets.
•PAA possesses specialized crude oil and NGL market knowledge. We believe PAA’s business relationships with participants in various phases of the crude oil and NGL distribution chain, from producers to refiners, as well as PAA’s own industry expertise (including PAA’s knowledge of North American crude oil and NGL flows), provide PAA with extensive market insight and an understanding of the North American physical crude oil and NGL markets that enables PAA to provide value chain solutions for its customers.
•PAA’s supply and logistics activities provide it with the opportunity to realize incremental margins. We believe the variety of activities executed within PAA’s Supply and Logistics segment provides PAA 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).
•PAA has the strategic and technical skills needed to execute strategic transactions that support its business and financial objectives, including joint ventures, joint ownership arrangements and divestitures. Since 2016, PAA has consummated over 10 joint venture and/or joint ownership arrangements and completed over $3 billion of divestitures of non-core assets and/or strategic sales of partial interests in selected assets. In addition, although acquisitions and investment capital projects are not currently a focus area, the strategic and technical skills needed to complete such transactions are very similar to those needed for other strategic transactions and since its initial public offering, PAA has completed and integrated over 90 acquisitions with an aggregate purchase price of approximately $13.7 billion, and PAA has also implemented investment capital projects totaling approximately $16.7 billion.
•PAA has an experienced management team whose interests are aligned with those of its unitholders. PAA’s executive management team has an average of 30 years of experience spanning across all sectors of the energy industry, as well as investment banking, and an average of 14 years with PAA or its predecessors and affiliates. In addition, through their ownership of PAA common units and grants of phantom units, PAA’s management team has a vested interest in PAA’s continued success.
Our Financial Strategy
Our financial strategy is designed to be complementary to PAA’s financial and business strategies. Our only cash-generating assets consist of our direct and indirect limited partner interests in AAP, which currently receives all of its cash flows from distributions on the PAA common units it owns.
We have entered into an Omnibus Agreement with the Plains Entities which provides for (i) our ability to issue additional Class A shares and use the net proceeds therefrom to purchase a like number of AAP units from AAP, and the corresponding ability of AAP to use the net proceeds therefrom to purchase a like number of PAA common units from PAA and (ii) our ability to lend proceeds of any future indebtedness we incur to AAP, and AAP’s corresponding ability to lend such proceeds to PAA, in each case on substantially the same terms as we incur.
Accordingly, we may access the equity capital markets from time to time to enhance the financial position of PAA and its ability to compete for incremental capital opportunities (including organic investments and third-party acquisitions) to drive future growth. We currently do not intend to incur any indebtedness in the near term. We would expect to fund direct acquisitions made by us, if any, with a combination of debt and equity.
PAA’s Financial Strategy
Targeted Credit Profile
We believe that a major factor in PAA’s continued success is its ability to maintain significant financial flexibility. An important part of PAA’s financial strategy is its commitment to generating positive free cash flow after distributions with a continued priority on deleveraging while also prudently increasing cash returned to its unitholders.
In that regard, PAA intends to maintain a credit profile that it believes is consistent with investment grade credit ratings. PAA targets a credit profile with the following attributes:
•a long-term debt-to-Adjusted EBITDA multiple averaging between 3.0x and 3.5x (See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Results of Operations-Non-GAAP Financial Measures” for our definition of Adjusted EBITDA and a discussion of our selected items that impact comparability and our non-GAAP measures.);
•an average long-term debt-to-total capitalization ratio of approximately 50% or less;
•an average total debt-to-total capitalization ratio of approximately 60% or less; and
•an average Adjusted EBITDA-to-interest coverage multiple of approximately 3.3x or better.
The first two of these four metrics include long-term debt as a critical measure, but do not include certain components of PAA’s capital structure such as short-term debt, preferred units and operating leases that may be considered by rating agencies in assigning their ratings. At December 31, 2020, PAA’s publicly-traded senior notes comprised approximately 97% of its long-term debt. Additionally, PAA also routinely incurs short-term debt primarily in connection with its supply and logistics activities that involve the simultaneous purchase and forward sale of crude oil and NGL. The crude oil and NGL purchased in these transactions are hedged. These borrowings are self-liquidating as they are repaid with sales proceeds. PAA also incurs 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 PAA’s working capital borrowings, these borrowings are self-liquidating. PAA does not consider the working capital borrowings or margin requirements associated with these activities to be part of its 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 and PAA conduct ourselves and engage in business relationships. Additional information regarding our Core Values and our commitment to environmental and social responsibility is available in the Sustainability section of our website. See “-Available Information” below.
Ongoing Activities Related to Strategic Transactions
PAA is continuously engaged in the evaluation of potential transactions that support its current business strategy. While in the past such transactions have included acquisitions and large capital projects, consistent with PAA’s current strategic focus on capital discipline, leverage reduction, portfolio optimization and free cash flow generation, PAA is currently primarily focused on evaluating whether it should (i) sell assets that it regards as non-core or that it believes might be a better fit with the business and/or assets of a third-party buyer or (ii) sell partial interests in assets to strategic joint venture partners, in each case to optimize PAA’s asset portfolio and strengthen its balance sheet and leverage metrics. With respect to a potential divestiture, PAA may also conduct an auction process or may negotiate a transaction with one or a limited number of potential buyers. Such transactions could involve assets that, if sold or put into a joint venture or joint ownership arrangement, could have a material effect on our financial condition and results of operations.
PAA typically does not announce a transaction until after it has executed a definitive agreement. However, in certain cases in order to protect its business interests or for other reasons, PAA 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 PAA has entered into a definitive agreement may be subject to customary and other closing conditions, which may not ultimately be satisfied or waived. Accordingly, PAA can give no assurance that its current or future efforts with respect to any such transactions will be successful, and PAA can provide no assurance that its financial expectations with respect to such transactions will ultimately be realized. See Item 1A. “Risk Factors-Risks Related to PAA’s Business-Divestitures, joint ventures, joint ownership arrangements and acquisitions involve risks that may adversely affect PAA’s business.”
PAA’s Joint Venture and Joint Ownership Arrangements
PAA is party to over 25 joint venture (“JV”) and undivided joint interest (“UJI”) arrangements with long-term partners throughout the industry value chain spanning across multiple North American basins. We believe that these capital-efficient arrangements provide strategic alignment with long-term industry partners, adding volume commitments to the systems and improving returns.
The following table summarizes PAA’s significant JVs as of December 31, 2020:
Entity (1)
Type of Operation JV
Ownership
Percentage
BridgeTex Pipeline Company, LLC Crude Oil Pipeline 20%
Cactus II Pipeline LLC Crude Oil Pipeline (2)
65%
Capline Pipeline Company LLC Crude Oil Pipeline (3)
54%
Diamond Pipeline LLC Crude Oil Pipeline (2)
50%
Eagle Ford Pipeline LLC Crude Oil Pipeline (2)
50%
Eagle Ford Terminals Corpus Christi LLC Crude Oil Terminal and Dock (2)
50%
Red River Pipeline Company LLC (4) (5)
Crude Oil Pipeline (2)
67%
Saddlehorn Pipeline Company, LLC (4)
Crude Oil Pipeline 30%
STACK Pipeline LLC Crude Oil Pipeline (2)
50%
White Cliffs Pipeline, LLC Crude Oil Pipeline 36%
Wink to Webster Pipeline LLC (4)
Crude Oil Pipeline 16%
(1)Except for Eagle Ford Terminals, which is reported in our Facilities segment, the financial results from the entities are reported in our Transportation segment.
(2)Asset is operated by Plains.
(3)The Capline pipeline was taken out of service pending the reversal of the pipeline system.
(4)Entity owns a UJI in the crude oil pipeline.
(5)We consolidate Red River Pipeline Company LLC based on control, with our partner’s 33% interest accounted for as a noncontrolling interest.
The following table summarizes PAA’s significant UJIs as of December 31, 2020, excluding UJIs that are indirectly owned by PAA through JVs (e.g., Wink to Webster, Saddlehorn and Red River JVs):
Asset Operating Segment Type of
Operation UJI
Ownership
Percentage
Basin Pipeline (1)
Transportation Crude Oil Pipeline 87%
Empress Processing (2)
Facilities NGL Facility 50% to 88%
Ft. Saskatchewan NGL Storage and Fractionation (2)
Facilities NGL Facility 21% to 48%
Western Corridor System (2)
Transportation Crude Oil Pipeline 21% to 58%
Sarnia NGL Storage and Fractionation (2)
Facilities NGL Facility 62% to 84%
Sunrise II Pipeline (1)
Transportation Crude Oil Pipeline 80%
(1)Asset is operated by Plains.
(2)Certain of these assets are operated by Plains.
PAA’s Acquisitions
Since PAA’s initial public offering in 1998, the acquisition of midstream assets and businesses has been an important component of its business strategy. Over the last five years, PAA completed several acquisitions for an aggregate of approximately $2.0 billion, the majority of which related to an acquisition in 2017. While the pace of PAA’s acquisition activity has slowed down in recent years, it continues to selectively analyze and pursue assets and businesses that are strategic and complementary to PAA’s existing operations.
PAA’s Divestitures
In 2016, PAA 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 its asset portfolio and strengthen its balance sheet and leverage metrics. Through December 31, 2020, PAA has completed asset sales totaling more than $3 billion.
PAA’s Investment Capital Projects
PAA’s extensive asset base and its relationships with long-term industry partners across the value chain provide it with opportunities for organic growth through the construction of additional assets that are complementary to, and expand or extend, its existing asset base. PAA’s 2021 capital plan consists of capital-efficient, highly contracted projects that help address industry needs. Substantially all of the capital will be invested in PAA’s fee-based Transportation and Facilities segments. The following investment capital projects are included in PAA’s 2021 capital plan as of February 2021:
Project Description Projected
In-Service Date 2021 Plan
Amount (1)
($ in millions)
Permian Basin Takeaway Pipeline Projects Primarily includes contributions for our interest in the Wink to Webster JV pipeline 2021 - 2022+ $ 140
Long-Haul Pipeline Projects (Non-Permian) Primarily includes contributions for our interests in the Diamond JV pipeline expansion / Capline JV pipeline reversal 1H 2021 - 2022 115
Complementary Permian Basin Projects Multiple projects to support the Permian Basin takeaway pipeline projects, and to expand/extend our gathering and intra-basin pipelines 1H 2020 - 2021+ 85
Selected Facilities Projects Primarily includes amounts for new connections at our St. James and Cushing facilities and a cavern conversion at our Fort Saskatchewan facility 2021 50
Other Projects 2021 - 2022+ 35
Total Projected Investment Capital Expenditures (1)
$ 425
(1)Represents the portion of the total project cost expected to be incurred during the year. Potential variation to current capital costs estimates may result from (i) changes to project design, (ii) final cost of materials and labor and (iii) timing of incurrence of costs due to uncontrollable factors such as receipt of permits or regulatory approvals and weather.
Global Petroleum Market Overview and Fundamental Themes
Current Global Petroleum Market Conditions
Crude oil and other petroleum liquids are supplied by producers around the world, including the Organization of Petroleum Exporting Countries (“OPEC”) and North American producers, among others. The chart below depicts the relationship between global supply of crude oil and other petroleum liquids and demand since the beginning of 2016:
Global Petroleum and Other Liquids Supply / Demand Balance (1)
(in millions of barrels per day)
(1)Average barrels produced and consumed per quarter.
Source: U.S. Energy Information Administration (“EIA”), Short-Term Energy Outlook, February 2021
In 2019, global demand for crude oil and other petroleum liquids worldwide averaged approximately 101 million barrels per day and since the year 2000 had grown at an average annual rate of approximately 1.0 to 1.5 million barrels per day. The largest drivers of demand growth were increases in population and rising standards of living in developing nations, particularly in Asia.
In 2020, global demand for crude oil and other petroleum liquids worldwide averaged approximately 92 million barrels per day, representing a significant decrease compared to 2019 as a result of the COVID-19 pandemic. As countries around the globe implemented government mandated shutdowns, demand for refined products such as gasoline, diesel and jet fuel significantly decreased resulting in global crude oil and other petroleum liquids demand falling to approximately 81 million barrels per day in April of 2020.
As global demand decreased, inventories began to build and global crude oil prices reached historic lows. Global supply responded in an attempt to rebalance the market as OPEC enacted production cuts, and North American producers shut-in production and greatly reduced capital spending, leading to a 75% reduction in Lower 48 onshore rig count versus the March 2020 peak and an excess of infrastructure in every major North American producing basin.
Both the EIA and OPEC currently forecast that global crude oil demand will recover to or near pre-COVID-19 levels by year end 2021. The global retrenchment of capital in both long-cycle and short-cycle supply combined with natural declines may put a constraint on the ability of producers to meet a meaningful recovery in demand. When demand does recover, there may be a need for incremental supply, and United States short-cycle shale is well positioned to meet this need. In the meantime, we as an industry must focus on rationalization and optimization of the existing infrastructure base while ensuring the ability to serve future growth of both supply and demand. Similar to crude oil, we expect demand for NGL to increase as the world population increases and as the population in developing nations seek to improve their quality of life. In addition, the resource base and the existing logistical infrastructure in North America is well situated to supply a meaningful portion of the expected increase in demand for NGL.
Crude Oil Market Overview
Crude oil is a global commodity that serves as feedstock for many of the world’s essential refined products such as transportation fuels (gasoline, diesel, jet fuel) and heating oil, among others. While commodities are typically considered unspecialized, mass-produced and fungible, crude oil is neither unspecialized nor fungible. The crude slate available to North American and world-wide refineries consists of a substantial number of different grades and varieties. Each crude oil grade has distinguishing physical properties. For example, specific gravity (generally referred to as light or heavy), sulfur content (generally referred to as sweet or sour) and metals content, along with other characteristics, collectively result in varying economic attributes. In many cases, these factors result in the need for such grades to be batched or segregated in the transportation and storage processes, blended to precise specifications or adjusted in value.
The lack of fungibility of the various grades of crude oil creates logistical transportation, terminalling and storage challenges and inefficiencies associated with regional volumetric supply and demand imbalances. These logistical inefficiencies are created as certain qualities of crude oil are indigenous to particular regions or countries. Also, each refinery has a distinct configuration of process units designed to handle particular grades of crude oil. The relative yields and the cost to obtain, transport and process the crude oil drive the refinery’s choice of feedstock.
We designed a business model to integrate large-scale supply aggregation capabilities with the ownership and operation of critical infrastructure systems that connect major producing regions (supply) to key demand centers (refineries) and export terminals. Our assets and our business strategy are designed to serve our producer and refiner customers by addressing regional crude oil supply and demand imbalances that exist in the United States and Canada. The nature and extent of supply and demand imbalances change from time to time as a result of a variety of factors, including global demand for exports; regional production declines and/or increases; refinery expansions, modifications and shut-downs; available transportation and storage capacity; and government mandates and related regulatory factors.
NGL Market Overview
NGL primarily includes ethane, propane, normal butane, iso-butane and natural gasoline, and is derived from natural gas production and processing activities, as well as crude oil refining processes. Liquefied petroleum gas (“LPG”) primarily includes propane and butane, which liquefy at moderate pressures making it easier to transport and store than ethane. NGL refers to all NGL products including LPG when used in this Form 10-K.
NGL is the primary feedstock for petrochemical facilities that produce many of the everyday consumer products used in the world. Individual NGL products have varying uses. Described below are the five basic NGL components and their typical uses:
•Ethane (C2). Ethane accounts for the largest portion of the NGL barrel and substantially all of the extracted ethane is used as feedstock in the production of ethylene, one of the basic building blocks for a wide range of plastics and other chemical products. When ethane recovery from a wet natural gas stream is uneconomic, ethane is left in the natural gas stream, subject to pipeline specifications.
•Propane (C3). Propane is used as heating fuel, engine fuel and industrial fuel, for agricultural burning and drying and also as petrochemical feedstock for the production of ethylene and propylene.
•Normal butane (C4). Normal butane is principally used for motor gasoline blending and as fuel gas, either alone or in a mixture with propane, and feedstock for the manufacture of ethylene and butadiene, a key ingredient of synthetic rubber. Normal butane is also used as a feedstock for iso-butane production and as a diluent in the transportation of heavy crude oil and bitumen, particularly in Canada.
•Iso-butane. Iso-butane is principally used by refiners to produce alkylates to enhance the octane content of motor gasoline.
•Natural Gasoline. Natural gasoline is principally used as a motor gasoline blend stock, a petrochemical feedstock, or as diluent in the transportation of heavy crude oil and bitumen, particularly in Canada.
We source NGL supply from field processing plants that are connected to our Cochrane-to-Edmonton (“Co-Ed”) system and other third-party pipelines that deliver NGL to our storage and processing assets in the Fort Saskatchewan area in Canada, and large processing plants located near Empress, Canada. These plants straddle the TransCanada pipeline system which is a mainline carrier of pipeline quality gas and primarily extract ethane that feeds local petrochemical facilities, and to a lesser extent extract NGL, which can be processed at our Empress or Sarnia fractionators. We expect NGL supply to grow with increased natural gas production in Western Canada when TransCanada completes the expansion of its mainline system in 2021.
Natural Gas Storage Market Overview
North American natural gas storage facilities provide a staging and warehousing function for seasonal swings in demand relative to supply, as well as an essential reliability cushion against disruptions in natural gas supply, demand and transportation by allowing natural gas to be injected into, withdrawn from or warehoused in such storage facilities as dictated by market conditions. Natural gas storage serves as a “shock absorber” that balances the market, serving as a source of supply to meet the consumption demands in excess of daily production capacity and a warehouse for gas when production exceeds daily demand.
Overall market conditions for natural gas storage appear to be improving as several fundamental factors are contributing to growth in North American natural gas demand. These factors include (i) increasing exports of LNG from North America, (ii) increasing exports of natural gas to Mexico, (iii) construction of new natural gas-fired power plants, (iv) sustained fuel switching from coal to natural gas among existing power plants and (v) growth in base-level industrial demand. The increase in both supply and demand has created greater opportunities for natural gas storage operations.
Description of Segments and Associated Assets
Under GAAP, we consolidate GP LLC, AAP and PAA and its subsidiaries. We currently have no separate operating activities apart from those conducted by PAA. As such, our segment analysis, presentation and discussion is the same as that of PAA, which conducts its operations through three segments-Transportation, Facilities and Supply and Logistics. Accordingly, any references to “we,” “us,” “our,” and similar terms describing assets, business characteristics or other related matters are references to assets, business characteristics or other matters involving PAA’s assets and operations. We have an extensive network of pipeline transportation, terminalling, storage and gathering assets in key crude oil and NGL producing basins and transportation corridors and at major market hubs in the United States and Canada. The map and descriptions below highlight our more significant assets (including certain assets under construction or development) as of December 31, 2020. Unless the context requires otherwise, references herein to our “facilities” includes all of the pipelines, terminals, storage and other assets owned by us.
Following is a description of the activities and assets for each of our three business segments.
Transportation Segment
Our Transportation segment operations generally consist of fee-based activities associated with transporting crude oil and NGL on pipelines, gathering systems and trucks. We generate revenue through a combination of tariffs, pipeline capacity agreements and other transportation fees. Our Transportation segment also includes equity earnings from our investments in entities that own or are developing transportation assets. We account for these investments under the equity method of accounting. See Note 9 to our Consolidated Financial Statements for additional information regarding these investments.
As of December 31, 2020, we employed a variety of owned or, to a much lesser extent, leased long-term physical assets throughout the United States and Canada in this segment, including approximately:
•18,370 miles of active crude oil and NGL pipelines and gathering systems;
•35 million barrels of active, above-ground tank capacity used primarily to facilitate pipeline throughput and help maintain product quality segregation; and
•815 trailers (primarily in Canada).
The following is a tabular presentation of our active crude oil and NGL pipeline assets in the United States and Canada as of December 31, 2020, grouped by geographic location:
Region Ownership Percentage Approximate System Miles (1)
2020 Average Net
Barrels per Day (2)
(in thousands)
Crude Oil Pipelines:
Permian Basin:
Gathering pipelines 100% 3,265 1,472
Intra-basin pipelines (3)
50% - 100% 815 1,907
Long-haul pipelines (3)
16% - 100% 1,535 1,048
5,615 4,427
South Texas/Eagle Ford 50% - 100% 830 380
Central 50% - 100% 2,495 379
Gulf Coast 54% - 100% 1,170 134
Rocky Mountain 21% - 100% 3,380 245
Western 100% 545 223
Canada 100% 2,700 294
Crude Oil Pipelines Total 16,735 6,082
Canadian NGL Pipelines 21% - 100% 1,635 184
Crude Oil and NGL Pipelines Total 18,370 6,266
(1)Includes total mileage of pipelines in which we own less than 100%.
(2)Represents average daily volumes for the entire year attributable to our interest. Average daily volumes are calculated as the total volumes (attributable to our interest) for the year divided by the number of days in the year. Volumes reflect tariff movements and thus may be included multiple times as volumes move through our integrated system.
(3)Includes pipelines operated by a third party.
A significant portion of our pipeline assets are interconnected and are operated as a contiguous system. The following descriptions are organized by type and geographic location and represent a selection of our most significant assets. Pipeline capacities throughout these descriptions are based on our reasonable estimate of volumes that can be delivered from origin to final destination on our pipeline systems. We report pipeline volumes based on the tariffs charged for individual movements, some of which may only utilize a certain segment of a pipeline system (i.e. two short-haul movements on a pipeline from point A to point B and another from point B to point C would double the pipeline tariff volumes on a particular system versus a single point A to point C movement). As a result, at times, our reported tariff barrel movements may exceed our total capacity.
Crude Oil Pipelines
Our crude oil pipelines are comprised of:
•gathering pipelines that move crude oil from wellhead or central battery connections to regional market hubs;
•intra-basin pipelines that are used as a hub system creating a significant amount of flexibility by creating connections between regional hub locations; and
•long-haul pipelines that move crude oil from (i) regional market hubs to major market hubs such as Cushing, Oklahoma or to export facilities, including our Corpus Christi terminal or (ii) major market hubs to a refinery.
Gathering Pipelines
Permian Basin. We own and operate over 3,200 miles of gathering pipelines in both the Midland Basin and the Delaware Basin that in aggregate represent over 2.5 million barrels per day of pipeline capacity. This gathering capacity includes pipeline capacity that delivers volumes to regional market hubs. Approximately 75% of the capacity of our gathering systems is in the Delaware Basin.
Central. We own and operate gathering pipelines that source crude oil from Western and Central Oklahoma and Southwest Kansas for transportation and delivery into our terminal facilities at Cushing, Oklahoma.
Rocky Mountain. We own and operate pipelines that provide gathering services in the Bakken and the Powder River Basin.
Western. We own and operate a pipeline in the San Joaquin Valley that gathers locally produced crude oil, which is then delivered via our Line 63 pipeline system and/or Line 2000 pipeline for transportation to Los Angeles area refiners.
Canada. We own and operate gathering systems with capacity of approximately 220,000 barrels per day. These gathering systems source crude from truck terminals and pipeline connected facilities to deliver to the Enbridge Mainline system at our Kerrobert and Regina terminals in Saskatchewan.
Intra-basin Pipelines
Permian Basin. We own and operate an intra-basin pipeline system with a capacity of over 2 million barrels per day that connects gathering pipelines and truck injection volumes to our owned and operated as well as third-party mainline pipelines that transport crude oil to major market hubs. This interconnected pipeline system is designed to provide shippers flow assurance, flexibility and access to multiple markets.
Canada. We own and operate intra-basin pipelines with capacity of approximately 290,000 barrels per day that deliver crude from northern and southern Alberta to the Edmonton, Alberta market hub. These pipelines provide shippers with flexibility to access the Enbridge and TransMountain long-haul pipelines along with the Imperial Oil Refinery. In addition, we have three cross-border pipelines that have the flexibility to move up to approximately 60,000 barrels per day of Canadian crude oil to our Rocky Mountain area long-haul pipelines. These intra-basin pipelines also have the ability to deliver up to approximately 105,000 barrels per day of crude oil to third-party pipelines in the Rocky Mountain region.
Long-haul Pipelines
Permian Basin. We own interests in multiple long-haul pipeline systems that, on a combined basis, represent over 1.5 million barrels per day of currently operational takeaway capacity (net to our ownership interests) out of the Permian Basin to major market hubs in Corpus Christi and Houston, Texas and Cushing, Oklahoma. Below is a description of some of our most significant long-haul pipeline systems within the Permian Basin region.
Permian to Cushing/Mid-Continent
•Basin Pipeline (Permian to Cushing). We own an 87% UJI in and are the operator of Basin Pipeline. Basin Pipeline has three primary origination locations: Jal, New Mexico; Wink, Texas; and Midland, Texas and, in addition to making intra-basin movements, serves as the primary route for transporting crude oil from the Permian Basin to Cushing, Oklahoma. Basin Pipeline also receives crude oil from a facility in southern Oklahoma which aggregates South Central Oklahoma Oil Province (SCOOP) production.
•Sunrise II Pipeline. We operate the Sunrise II Pipeline and, through a UJI arrangement, own 400,000 barrels of the capacity. Our Sunrise II Pipeline transports crude oil from Midland and Colorado City to connecting carriers at Wichita Falls.
Permian to Gulf Coast
•BridgeTex Pipeline (Permian to Houston). We own a 20% interest in the legal entity that owns the BridgeTex Pipeline, with two other partners. The pipeline, operated by a subsidiary of Magellan Midstream Partners, L.P., originates at Colorado City, Texas and extends to Houston, Texas. The pipeline has a capacity of 440,000 barrels per day and is capable of receiving supply from both our Basin and Midland South (formerly Sunrise) pipelines.
•Cactus Pipeline (Permian to Corpus Christi). We own and operate the Cactus Pipeline, which has a capacity of 390,000 barrels per day, originates at McCamey, Texas and extends to Gardendale, Texas. Cactus Pipeline volumes are interconnected to the Corpus Christi, Texas market through a connection at Gardendale to our Eagle Ford joint venture pipeline system.
•Cactus II Pipeline (Permian to Corpus Christi). We own a 65% interest in the legal entity that owns the Cactus II Pipeline (“Cactus II”), which we operate. Cactus II is a Permian mainline system that extends directly to the Corpus Christi, Texas market, and has a capacity of 670,000 barrels per day.
•Wink to Webster Pipeline. We own a 16% interest in the legal entity that owns the Wink to Webster Pipeline (“W2W Pipeline”), which in turn owns 100% of certain segments of the W2W Pipeline and a 71% UJI in the segment from Midland, Texas to Webster, Texas. The W2W Pipeline originates in the Permian Basin in West Texas and transports crude oil to multiple destinations in the Houston and Galveston market areas. The pipeline system, which is currently in partial service, will provide approximately 1.5 million barrels per day of crude oil capacity (1.1 million barrels per day, net to the UJI interest) and is supported by long-term shipper commitments. Phase one of the pipeline system from Midland, Texas to Webster, Texas is currently in service. Phase two, which increases the pipeline system to 1.5 million barrels per day of capacity, is expected to be in service in the fourth quarter of 2021, at which time long-term shipper commitments will become effective. The third phase of the project, which includes the segments from Wink, Texas to Midland, Texas and from Webster, Texas to Baytown, Texas, has been deferred by the partners until the fourth quarter of 2023.
South Texas/Eagle Ford. We own a 50% interest in the legal entity that owns the Eagle Ford Pipeline through a joint venture with a subsidiary of Enterprise. We serve as the operator of the Eagle Ford Pipeline, which has a total capacity of approximately 660,000 barrels per day and connects Permian and Eagle Ford area production to Corpus Christi, Texas refiners and terminals. Additionally, the Eagle Ford Pipeline has connectivity to Houston, Texas via a connection with Enterprise’s pipeline at Lyssy, Texas.
Central. We own and operate various pipeline systems that extend from our Cushing terminal in Oklahoma to various refineries and/or crude oil hubs. Below is a description of some of our most significant pipeline systems in the Central region.
•Diamond Pipeline (Cushing to Memphis). We own a 50% interest in the legal entity that owns the Diamond Pipeline through a joint venture with Valero Energy Corporation (“Valero”). We operate the Diamond Pipeline, which extends from our Cushing Terminal to Valero’s refinery in Memphis, Tennessee. The Diamond Pipeline is underpinned by a long-term minimum volume commitment and currently has a total capacity of 200,000 barrels per day. Following the successful 2019 open season on the Capline Pipeline system (“Capline”), the joint venture partners sanctioned an expansion and modest extension of the Diamond Pipeline that will expand its capacity to approximately 420,000 barrels per day, connect it to Capline and facilitate the movement of volumes from Cushing, Oklahoma to St. James, Louisiana.
•Red River Pipeline (Cushing to Longview). The Red River Pipeline is an approximately 235,000 barrel per day capacity pipeline that extends from our Cushing Terminal in Oklahoma to Longview, Texas, where it connects with various pipelines. The Red River Pipeline is supported by long-term shipper commitments and we serve as operator. In May 2019, we announced a new joint venture of the Red River Pipeline. Delek Logistics Partners, LP (“Delek”) purchased a 33% ownership interest in the new Red River Pipeline Company LLC (“Red River JV”) joint venture and we retained a 67% interest. In 2020, we put into service an expansion that enables additional volume pull-through from Cushing, Oklahoma and the Permian to the U.S. Gulf Coast markets, providing additional supply optionality for shippers. In support of this expansion, Delek increased its long-term throughput and deficiency agreement on the Red River Pipeline system from an existing 35,000 barrels per day to 100,000 barrels per day. The Red River JV has an approximate 69% UJI in the pipeline segment from Cushing to Hewitt and owns 100% of the segment of the pipeline extending from Hewitt to Longview.
Rocky Mountain. Our pipeline systems in the Rocky Mountain region provide access to our terminal in Cushing, Oklahoma as well as other major market hubs. We own and operate the Bakken North pipeline system that accommodates bidirectional flow and can move crude oil from the Bakken to the Enbridge Mainline system at Regina, Saskatchewan or from the Enbridge Mainline system to our terminal in Trenton, North Dakota. We own a UJI in a pipeline system that extends from the Canadian border to our terminal in Guernsey, Wyoming. This pipeline system receives crude oil from our Rangeland and Milk River Pipelines in Canada. In addition to these assets, our largest Rocky Mountain area systems include the following joint venture pipelines, both of which connect to our terminal in Cushing, Oklahoma.
•Saddlehorn Pipeline. We own a 30% interest in the legal entity that owns the Saddlehorn Pipeline and, through a UJI arrangement, owns 290,000 barrels per day of capacity in the Saddlehorn Pipeline, which includes a recent expansion of 100,000 barrels per day. The pipeline extends from the Niobrara and Denver-Julesburg (“DJ”) Basin to Cushing and is operated by Magellan. The Saddlehorn Pipeline is supported by minimum volume commitments.
•White Cliffs Pipeline. We own an approximate 36% interest in the entity that owns the White Cliffs Pipeline system through a joint venture with three other partners. The White Cliffs Pipeline system consists of one crude oil pipeline with approximately 100,000 barrels per day of capacity that extends from the DJ Basin to Cushing, Oklahoma and one NGL pipeline with approximately 90,000 barrels per day of capacity that extends from the DJ Basin to a tie-in location with the Southern Hills Pipeline in Oklahoma. The NGL pipeline is supported by a long-term capacity lease and long-term throughput agreements. A subsidiary of Energy Transfer LP serves as the operator of the pipelines.
Western. We own and operate the Line 63 and Line 2000 pipelines in California. Line 2000 is a mainline system that has the capacity to transport approximately 110,000 barrels per day from the San Joaquin Valley to refineries and terminal facilities in the Los Angeles area. Line 63 is used as a gathering and distribution system. The pipeline gathers crude oil in the San Joaquin Valley for delivery to Line 2000 and local refiners. In the Los Angeles area, the Line 63 distribution lines are used to move crude oil from Line 2000 to local refiners.
Canadian NGL Pipelines
Supply lines. Our supply lines transport NGL from producing locations to downstream processing facilities. Our primary supply system, the Co-Ed NGL pipeline system, has transportation capacity of approximately 70,000 barrels per day and gathers NGL from Southwest and Central Alberta (Cardium, Deep Basin, and Alberta Montney) for delivery to our Fort Saskatchewan, Alberta NGL fractionation facilities. In addition, we own a 50% UJI in a supply line with capacity of approximately 50,000 barrels per day that carries NGL from our Empress, Alberta fractionation facility to cavern storage assets in Kerrobert, Saskatchewan.
Market lines. Market lines are typically used to transport NGL from production locations to further downstream market distribution and storage terminals. We own and operate one market pipeline, the Plains Petroleum Transmission Company (“PPTC”) pipeline system, which has approximately 15,500 barrels per day of capacity. The pipeline extends from our Empress, Alberta fractionation facility to our Fort Whyte terminal in Winnipeg, Manitoba. The pipeline also delivers NGL to various terminals and rail loading facilities along the pipeline system.
Hub lines. Hub lines connect regional hub locations, such as processing assets to storage and petrochemical facilities. We own and operate hub lines in eastern Canada with approximately 130,000 barrels per day of capacity that transport propane and butane from our Sarnia, Ontario fractionation facility to our St. Clair, Michigan and Windsor, Ontario storage, rail and truck terminals, as well as third-party locations, and ethane from the Kinder Morgan Utopia pipeline to Nova Chemicals’ Corunna petrochemical complex in Sarnia, Ontario.
Facilities Segment
Our Facilities segment operations generally consist of fee-based activities associated with providing storage, terminalling and throughput services primarily for crude oil, NGL and natural gas, as well as NGL fractionation and isomerization services and natural gas and condensate processing services. We generate revenue through a combination of month-to-month and multi-year agreements and processing arrangements.
Revenues generated in this segment include (i) storage and throughput fees at our crude oil, NGL and natural gas storage facilities, (ii) fees from natural gas and condensate processing services and from NGL fractionation and isomerization services and (iii) loading and unloading fees at our rail terminals.
As of December 31, 2020, we owned, operated or employed a variety of long-term physical assets throughout the United States and Canada in this segment, including:
•approximately 75 million barrels of crude oil storage capacity primarily at our terminalling and storage locations;
•approximately 28 million barrels of NGL storage capacity;
•approximately 68 billion cubic feet (“Bcf”) of natural gas storage working gas capacity;
•approximately 26 Bcf of owned base gas;
•five natural gas processing plants located throughout Canada and the Gulf Coast area of the United States;
•a condensate processing facility located in the Eagle Ford area of South Texas with an aggregate processing capacity of approximately 120,000 barrels per day;
•eight fractionation plants located throughout Canada and the United States with an aggregate net processing capacity of approximately 206,500 barrels per day, and an isomerization and fractionation facility in California with an aggregate processing capacity of approximately 15,000 barrels per day;
•22 crude oil and NGL rail terminals located throughout the United States and Canada;
•five marine facilities in the United States; and
•approximately 330 miles of active pipelines that support our facilities assets.
The following discussion contains a detailed description of our more significant Facilities segment assets.
Crude Oil Storage and Terminalling Facilities
Our largest crude oil terminals are located in key market hubs, including Cushing, Oklahoma, St. James, Louisiana, Midland, Texas and Patoka, Illinois, and have connectivity to all major inbound and outbound pipelines and other terminals at these hubs.
We are the largest provider of crude oil terminalling services in Cushing, Oklahoma, which is one of the largest physical trading hubs in the United States and is the delivery point for crude oil futures contracts traded on the NYMEX. Our Cushing Terminal has been designated by the NYMEX as an approved delivery location for crude oil delivered under the NYMEX light sweet crude oil futures contract.
Our Cushing terminal is connected to our long-haul pipelines from the Permian Basin and Rocky Mountain regions, as well as to our Central region gathering pipelines. Additionally the terminal supplies crude oil to all four of our joint venture, Central region long-haul pipelines.
Our Midland terminal has access to all of our Permian Basin gathering pipelines, either through direct connections, or through our intra-basin pipelines in the Permian Basin. Likewise, the terminal is also either directly connected, or connected through our intra-basin pipelines to all four of our Permian Basin long-haul pipelines.
Our terminals at Corpus Christi, Texas, St. James, Louisiana and Mobile, Alabama all have docks and the capacity to export crude oil. In addition, our St James terminal has a rail unload facility that can move crude from rail cars to pipelines that service local refiners, or to our dock for export.
Our Patoka and St. James terminals are both connected to Capline pipeline, and the terminals will be a receipt and destination facility, respectively, once Capline is placed into service in 2022.
Our crude oil terminals have significant flexibility and operational capabilities, including large-scale multi-grade handling and segregation capabilities and multiple marine transportation loading and unloading capabilities. The table below presents our crude oil storage capacity by location as of December 31, 2020:
Crude Oil Storage Facilities Total Capacity
(MMBbls)
Cushing 27
St. James 15
Patoka 7
Permian Basin Area 8
Mobile and Ten Mile 5
Corpus Christi (1)
Other (2)
(1)We own 50% of this storage capacity through our investment in Eagle Ford Terminals Corpus Christi LLC.
(2)Amount includes approximately 2 million barrels of storage capacity associated with our crude oil rail terminal operations.
NGL Storage, Fractionation and Isomerization and Natural Gas Processing Facilities
We have a large integrated network of NGL storage and fractionation and natural gas processing facilities throughout Canada, as well as NGL storage and fractionation facilities in the United States. The tables below present volumes and capacities for these facilities as of December 31, 2020 and our most significant assets are described further below.
NGL Storage Facilities Total Capacity
(MMBbls)
Fort Saskatchewan 11
Sarnia Area 7
Empress Area 4
Other 6
NGL Fractionation and Isomerization Facilities Ownership Interest Total
Spec Product (1)
(Bbls/d)
Net
Capacity
(Bbls/d)
Empress 100 % 19,300 23,300
Fort Saskatchewan 21-100% 49,100 68,100
Sarnia 62-84% 47,200 90,000
Other 82-100% 13,200 40,100
128,800 221,500
Natural Gas Processing Facilities (2)
Ownership Interest Total Gas
Spec Product (1)
(Bcf/d)
Gas
Processing
Capacity
(Bcf/d)
United States Gulf Coast Area 100 % 0.2 0.3
Empress Area 50-88% 2.3 6.0
2.5 6.3
(1)Represents average volumes net to our share for the entire year.
(2)While natural gas processing volumes are presented, they are not indicative of revenues generated by these assets as fees associated with our natural gas processing activities are generally fixed.
Fort Saskatchewan. The Fort Saskatchewan facility is located near Edmonton, Alberta in one of the key North American NGL hubs. The facility is a receipt, storage, fractionation and delivery facility for NGL and is connected to other major NGL plants and pipeline systems in the area. The facility’s primary assets include 28 storage caverns. The facility includes assets operated by us and assets operated by a third party. Our ownership in the various facility assets ranges from approximately 21% to 100%. Our Fort Saskatchewan fractionation facility has a design capacity of 85,000 barrels per day and is able to produce up to approximately 50,000 barrels per day of spec propane, butane and condensate. The remaining capacity is used to produce a propane and butane mix, which is sent to our Sarnia facility for further fractionation. Through our 21% ownership in the Keyera Fort Saskatchewan fractionation plant, we have additional fractionation capacity of approximately 17,300 barrels per day.
Sarnia Area. Our Sarnia Area facilities in Southwestern Ontario consist of (i) our Sarnia facility, (ii) our Windsor storage terminal and (iii) our St. Clair, Michigan terminal. The Sarnia facility is a large NGL fractionation and storage facility located in the Sarnia Chemical Valley that contains multiple rail and truck loading spots. The Sarnia Area facilities are served by a network of multiple pipelines connected to various refineries, chemical plants and other pipeline systems in the area. This pipeline network also delivers product between our Sarnia facility and our Windsor storage terminal in addition to the delivery capability from our Sarnia facility to our St. Clair terminal. The Sarnia Fractionator is the largest fractionation plant in Eastern Canada and receives NGL feedstock primarily from the Enbridge pipeline system. The fractionation unit is able to produce approximately 120,000 barrels per day of spec NGL products. Our ownership in the various processing units at the Sarnia Fractionator ranges from 62% to 84%.
Empress Area. We own and/or operate four straddle plants located in the Empress Area, capable of processing up to 6.0 Bcf of natural gas per day, however, supply available to these plants are typically in the 2.5 to 3.5 Bcf per day range. These plants produce approximately 30,000 to 40,000 barrels per day of NGL which can be fractionated at either our Empress or Sarnia fractionators. Our Empress fractionation facility is capable of processing and producing up to 23,300 barrels per day of spec NGL products and is connected to our PPTC pipeline system.
Other. We have a long-term liquids supply and profit sharing contract with a third-party owned straddle plant, near Cochrane, Alberta, with gross processing capacity of approximately 2.5 Bcf per day. NGL produced from this facility are transported on our Co-Ed pipeline system to our Fort Saskatchewan area assets, and then to our Sarnia fractionator via the Enbridge pipeline system. In addition, we own a facility located near Bakersfield, California that provides approximately 15,000 barrels per day of isomerization and fractionation services to producers and customers.
Natural Gas Storage Facilities
We own two natural gas storage facilities with an aggregate commercial working gas capacity of approximately 68 Bcf in service as of December 31, 2020. Our natural gas storage facilities are strategically located within the Gulf Coast market and have a diverse group of customers, including liquefied natural gas (“LNG”) exporters, utilities, pipelines, producers, power generators and marketers whose storage needs vary from traditional seasonal storage services to hourly balancing. We are located near several major market hubs and our facilities have multiple physical interconnects with third-party interstate pipelines, intrastate pipelines and direct connect customers, serving markets in the Gulf Coast, Mid-Atlantic, Northeast, and Southeast regions of the United States.
Condensate Processing Facility
Our Gardendale condensate processing facility is located in La Salle County, Texas. The facility stabilizes condensate that is primarily sourced from our Eagle Ford area gathering systems. The NGL extracted at this facility is delivered to a third-party pipeline that delivers the NGL to Mont Belvieu, Texas. The facility has a total processing capacity of 120,000 barrels per day and usable storage capacity of 160,000 barrels. Throughput at the Gardendale processing facility is supplied by long-term commitments from producers.
Crude Oil Rail Facilities
We own crude oil rail loading facilities located at or near Carr, Colorado; Tampa, Colorado; Manitou, North Dakota; and Kerrobert, Saskatchewan. We own crude oil rail unloading facilities in St. James, Louisiana, Yorktown, Virginia and Bakersfield, California. The table below presents aggregate loading and unloading capacity for these facilities as of December 31, 2020:
Ownership Interest Loading
Capacity
(Bbls/d) Unloading
Capacity
(Bbls/d)
Crude Oil Rail Facilities 100 % 264,000 350,000
NGL Rail Facilities
We own 18 operational NGL rail facilities (including our Fort Saskatchewan rail facility, as well as facilities that can provide both crude oil and NGL service) strategically located near our NGL facilities as well as third-party distribution centers throughout Canada and the United States. Our NGL rail terminals are predominately utilized for internal purposes specifically for our supply and logistics activities. See our “Supply and Logistics Segment” discussion following this section for further discussion regarding the use of our rail terminals. The table below presents additional information regarding our NGL rail facilities as of December 31, 2020:
Ownership Interest Number of
Rack Spots Number of
Storage Spots
NGL Rail Facilities 75-100% 284 1,589
Supply and Logistics Segment
Our Supply and Logistics segment activities include the purchase, logistics and resale of crude oil and NGL in North America. Through these transactions, we seek to maintain a position that is substantially balanced between purchases and sales and future delivery obligations. The segment owns a significant volume of crude oil and NGL required to conduct our commercial activities. The crude oil and NGL used to support our ongoing commercial activities is classified as long-term assets and linefill or minimum inventory requirements. A summary of the assets employed to support our commercial activities, December 31, 2020, include approximately:
•16 million barrels of crude oil and NGL linefill in pipelines owned by us;
•4 million barrels of crude oil and NGL utilized as linefill in pipelines owned by third parties or otherwise required as long-term inventory;
•680 trucks and 840 trailers; and
•6,000 crude oil and NGL railcars.
Our crude oil activities generally include the purchase of crude oil at the wellhead or at central tank batteries typically owned by the crude oil producer. We may also purchase crude oil at market hubs, such as our Cushing terminal, or in-transit in a pipeline. We typically transport our crude oil supply to market hub locations, or directly to refiners using our pipeline or trucking assets and, to a lesser extent, pipelines owned by third parties. We may also optimize the value of our supply by executing exchanges with third parties, where we may exchange qualities of crude oil or the location of our crude oil, and we would either pay or receive a fee for the differential in value for the quality or location of the crude oil. We may use derivative instruments such as the NYMEX futures market to hedge our exposure to crude oil prices. We also hedge the currency differential between the U.S. and Canadian dollar for crude oil purchased on a Canadian dollar basis and sold on a U.S. dollar basis.
Our crude oil supplies are typically sold to refiners, crude oil exporters, traders or other market participants. All crude oil sales arrangements are subject to credit approval. In certain circumstances, where the market value for prompt deliveries of crude oil is discounted to the value for deferred delivery (such conditions are referred to as a “Contango Market”) we may store crude oil in tanks included in our Facilities or Transportation segments and use a NYMEX futures contract to hedge the value of the stored crude oil.
Our NGL activities include the purchase of both NGL and the spec components propane and butane (“spec products”). Our NGL supply is typically sourced at our Empress facility, where we acquire the rights to extract NGL from producers and/or shippers of the gas streams that pass through our Empress facility. The extraction rights that we acquire allow us to process that gas at our Empress facility and extract the higher valued NGL from the gas stream. We then purchase natural gas to replace the thermal content attributable to the NGL that was extracted. Our NGL supply at Empress is then either fractionated into spec products at our Empress fractionator, or transported on a third-party pipeline and fractionated into spec products at our Sarnia fractionator. Often times we will use derivative instruments to hedge the differential between natural gas prices and the spec product prices to ensure that we are able to extract and fractionate NGL, and deliver spec products to markets at a profitable margin.
We also acquire spec products from third parties. The majority of the spec products we purchase are at the end (“tailgate”) of our Fort Saskatchewan fractionator; however, we may also purchase butane from refiners and propane and/or butane from third-party processors. Some of the spec product we purchase at Fort Saskatchewan is combined into a propane/butane mix and transported on a third-party pipeline to our Sarnia fractionator. The spec products that we own are transported by pipeline, rail or truck and either delivered to one of our storage facilities, or delivered and sold to a third party. Similar to our crude oil activities, spec products may be profitably stored when there is a Contango Market. The value of the stored product is hedged using various derivative instruments.
Credit. Our supply and logistics activities require significant extensions of credit by our suppliers. In order to assure our ability to perform our obligations under the purchase agreements, various credit arrangements are negotiated with our suppliers. These arrangements include open lines of credit and, to a lesser extent, standby letters of credit issued under our hedged inventory facility or our senior unsecured revolving credit facility. In addition, storing crude oil, NGL or spec products in a Contango Market, or otherwise, requires us to have credit facilities to finance both the purchase of these products in the prompt month as well as margin requirements that may be required for the derivative instruments used to hedge our price exposure.
When we sell crude oil and NGL, we must determine the amount, if any, of credit to be extended to any given customer. Because our typical sales transactions can involve large volumes of crude oil, the risk of nonpayment and nonperformance by customers is a major consideration in our business. We believe our sales are made to creditworthy entities or entities with adequate credit support. We also have credit risk exposure related to our sales of NGL (principally propane); however, because our sales are typically in relatively small amounts to individual customers, we do not believe that these transactions pose a material concentration of credit risk. Typically, we enter into annual contracts to sell NGL on a forward basis, as well as to sell NGL on a current basis to local distributors and retailers. In certain cases our NGL customers prepay for their purchases, in amounts ranging up to 100% of their contracted amounts. See Note 3 to our Consolidated Financial Statements for further discussion of our credit review process and risk management procedures.
The following table shows the average daily volume of our supply and logistics activities for the year ended December 31, 2020:
Volumes
(MBbls/d)
Crude oil lease gathering purchases (1)
1,174
NGL sales 144
Supply and Logistics segment total volumes 1,318
(1)Of this amount, approximately 862 MBbls/d were purchased in the Permian Basin.
Impact of Commodity Price Volatility and Dynamic Market Conditions on Our Business Model
Crude oil, NGL and natural gas commodity prices have historically been very volatile. For example, in the last year, the prompt month NYMEX light, sweet futures contract (commonly referred to as “WTI”) price ranged from a low of approximately minus $38 per barrel to a high of approximately $63 per barrel. Similarly, there has also been volatility within the propane and butane markets as seen through the North American benchmark price located at Mont Belvieu, Texas, as well as with the basis differentials between Mont Belvieu prices and prices realized at various market hubs in North America.
While our objective is to position the Partnership such that our overall annual cash flow is not materially adversely affected by the absolute level of energy prices, market volatility associated with shifts between demand-driven markets and supply-driven markets or other similar dynamics has in the past, and may in the future create market conditions that are more challenging to our business model. In extended periods of lower crude oil and/or NGL prices, or periods where the supply and demand fundamentals compress regional location differentials, our financial results may be adversely impacted. In such market conditions, product flows on our pipelines in our Transportation segment may be adversely impacted and/or our Supply and Logistics segment may not fully recover its costs on certain transactions. Alternatively, in periods where supply exceeds regional demand and/or pipeline egress, product flows on our pipelines may be favorably impacted and/or our Supply and Logistics segment may be able to capture additional margins. In executing our business model, we employ a variety of financial risk management tools and techniques, predominantly in our Supply and Logistics segment. These are discussed in greater detail in the “-Risk Management” section below.
Relative contribution levels will vary from quarter-to-quarter due to seasonality, particularly with respect to our NGL activities in our Supply and Logistics segment. However, we expect that (absent material outperformance in our Supply and Logistics segment) our fee-based Transportation and Facilities segments should comprise more than 90% of our aggregate segment results.
Risk Management
In order to hedge margins involving our physical assets and manage risks associated with our various commodity purchase and sale obligations and, in certain circumstances, to realize incremental margin during volatile market conditions, we use derivative instruments. We also use various derivative instruments to manage our exposure to interest rate risk and currency exchange rate risk. In analyzing our risk management activities, we draw a distinction between enterprise-level risks and trading-related risks. Enterprise-level risks are those that underlie our core businesses and may be managed based on management’s assessment of the cost or benefit of doing so. Conversely, trading-related risks (the risks involved in trading in the hopes of generating an increased return) are not inherent in our core business; rather, those risks arise as a result of engaging in trading activities. Our policy is to manage the enterprise-level risks inherent in our core businesses by using financial derivatives to protect our ability to generate cash flow and optimize asset profitability, rather than trying to profit from trading activity. Our commodity risk management policies and procedures are designed to monitor NYMEX, ICE and over-the-counter positions, as well as physical volumes, grades, locations, delivery schedules and storage capacity, to help ensure that our hedging activities address our risks. Our interest rate and currency exchange rate risk management policies and procedures are designed to monitor our derivative positions and ensure that those positions are consistent with our objectives and approved strategies. We have a risk management function that has direct responsibility and authority for our risk policies, related controls around commercial activities and procedures and certain other aspects of corporate risk management. Our risk management function also approves all new risk management strategies through a formal process. Our approved strategies are intended to mitigate and manage enterprise-level risks that are inherent in our core businesses.
Our policy is generally to structure our purchase and sales contracts so that price fluctuations do not materially affect our operating income, and not to acquire and hold physical inventory or derivatives for the purpose of speculating on outright commodity price changes. Although we seek to maintain a position that is substantially balanced within our supply and logistics activities, we purchase crude oil, NGL and natural gas from thousands of locations and may experience net unbalanced positions for short periods of time as a result of production, transportation and delivery variances as well as logistical issues associated with inclement weather conditions and other uncontrollable events that may occur. When unscheduled physical inventory builds or draws do occur, they are monitored constantly and managed to a balanced position over a reasonable period of time. This activity is monitored independently by our risk management function and must take place within predefined limits and authorizations.
Customers
Marathon Petroleum Corporation and its subsidiaries accounted for 13%, 12% and 14% of our revenues for the years ended December 31, 2020, 2019 and 2018, respectively. ExxonMobil Corporation and its subsidiaries accounted for 12%, 12% and 14% of our revenues for the years ended December 31, 2020, 2019 and 2018, respectively. Phillips 66 Company and its subsidiaries accounted for 11% of our revenues for the year ended December 31, 2019. No other customers accounted for 10% or more of our revenues during any of the three years ended December 31, 2020. The majority of revenues from these customers pertain to our supply and logistics operations. The sales to these customers occur at multiple locations and we believe that the loss of these customers would have only a short-term impact on our operating results. There is risk, however, that we would not be able to identify and access a replacement market at comparable margins. For a discussion of customers and industry concentration risk, see Note 16 to our Consolidated Financial Statements.
Competition
Competition among pipelines is based primarily on transportation charges, access to producing areas and supply regions and demand for crude oil and NGL by end users. Although new pipeline projects represent a source of competition for our business, there are also existing third-party owned pipelines with excess capacity in the vicinity of our operations that expose us to significant competition based on the relatively low operating cost associated with moving an incremental barrel of crude oil or NGL through such unutilized capacity. In areas where additional infrastructure is being built or has been built to accommodate new or increased production or changing product flows, we face competition in providing the required infrastructure solutions as well as the risk that capacity in the area will be overbuilt for the foreseeable future. As a result of multiple pipeline expansions that have occurred or are being completed in the Permian Basin and other areas, together with meaningful reductions in expected production growth due to COVID-19 impacts, we anticipate competition for uncommitted barrels and contract renewals and extensions will be amplified in the coming years, increasing our contract renewal and customer retention risk.
In addition, depending upon the specific movement, pipelines, which generally offer the lowest cost of transportation, may also face competition from other forms of transportation, such as truck, rail and barge. Although these alternative forms of transportation are typically higher cost, they can provide access to alternative markets at which a higher price may be realized for the commodity being transported, thereby overcoming the increased transportation cost.
We also face competition with respect to our supply and logistics and facilities services. Our competitors include other crude oil and NGL pipeline and terminalling companies, other NGL processing and fractionation companies, the major integrated oil companies and their marketing affiliates, independent gatherers, private equity backed entities, banks that have established a trading platform, brokers and marketers of widely varying sizes, financial resources and experience. Some of these competitors have capital resources greater than ours. The addition of new pipelines supported by minimum volume commitments and/or acreage dedications could also amplify the level of competition for purchasing wellhead barrels, especially in the Permian Basin and thus impact our margins.
Regulation
Our assets, operations and business activities are subject to extensive legal requirements and regulations under the jurisdiction of numerous federal, state, provincial and local agencies. Many of these agencies are authorized by statute to issue, and have issued, requirements binding on the pipeline industry, related businesses and individual participants. The failure to comply with such legal requirements and regulations can result in substantial fines and penalties, expose us to civil and criminal claims, and cause us to incur significant costs and expenses. See Item 1A. “Risk Factors-Risks Related to Laws and Regulations Impacting PAA’s Business-PAA’s 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 it to significant costs and liabilities. The current laws and regulations affecting PAA’s business are subject to change and in the future PAA may be subject to additional laws, executive orders and regulations, which could adversely impact PAA’s business.” At any given time there may be proposals, provisional rulings or proceedings in legislation or under governmental agency or court review that could affect our business. The regulatory burden on our assets, operations and activities increases our cost of doing business and, consequently, affects our profitability. We can provide no assurance that the increased costs associated with any new or proposed laws, rules or regulations will not be material. We may at any time also be required to apply significant resources in responding to governmental requests for information and/or enforcement actions.
The following is a summary of certain, but not all, of the laws and regulations affecting our operations.
Health, Safety and Environmental Regulation
General
Our operations involving the storage, treatment, processing and transportation of liquid and gaseous hydrocarbons, including crude oil, are subject to stringent federal, state, provincial and local laws and regulations governing the discharge of materials into the environment or otherwise relating to protection of the environment, including wildlife. As with the industry generally, compliance with these laws and regulations increases our overall cost of doing business, including our capital costs to construct, maintain and upgrade equipment and facilities as regulations are updated or new regulations are invoked. Failure to comply with these laws and regulations could result in the assessment of administrative, civil and criminal penalties, the imposition of investigatory and remedial liabilities and the issuance of injunctions or other orders that may subject us to additional operational constraints. Failure to comply with these laws and regulations could also result in negative public perception of our operations or the industry in general, which may adversely impact our ability to conduct our business. Environmental and safety laws and regulations are subject to changes that may result in more stringent requirements, and we cannot provide any assurance that compliance with current and future laws and regulations will not have a material effect on our results of operations or earnings. A discharge of hazardous liquids into the environment could, to the extent such event is not insured, subject us to substantial expense, including both the cost to comply with applicable laws and regulations and any claims made by third parties. The following is a summary of some of the environmental, health and safety laws and regulations to which our operations are subject.
Pipeline Safety/Integrity Management
A substantial portion of our petroleum pipelines and our storage tank facilities in the United States are subject to regulation by the Department of Transportation’s (“DOT”) Pipeline and Hazardous Materials Safety Administration (“PHMSA”) pursuant to the Hazardous Liquids Pipeline Safety Act of 1979, as amended (the “HLPSA”). The HLPSA imposes safety requirements on the design, installation, testing, construction, operation, replacement and management of pipeline and tank facilities. Federal regulations implementing the HLPSA require pipeline operators to adopt measures designed to reduce the environmental impact of oil discharges from onshore oil pipelines, including the maintenance of comprehensive spill response plans and the performance of extensive spill response training for pipeline personnel. These regulations also require pipeline operators to develop and maintain a written qualification program for individuals performing covered tasks on pipeline facilities. Comparable regulation exists in some states in which we conduct intrastate common carrier or private pipeline operations. Regulation in Canada is under the Canada Energy Regulator (“CER”), formerly the National Energy Board, and provincial agencies.
United States
The HLPSA was amended by the Pipeline Safety Improvement Act of 2002 and the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006. These amendments have resulted in the adoption of rules by the DOT that require transportation pipeline operators to implement integrity management programs, including frequent inspections, correction of identified anomalies and other measures, to ensure pipeline safety in “high consequence areas” such as high population areas, areas unusually sensitive to environmental damage, and commercially navigable waterways. In the United States, our costs associated with the inspection, testing and correction of identified anomalies were approximately $41 million in 2020. Based on currently available information, our preliminary estimate for 2021 is that we will incur approximately $32 million in expenditures associated with our required pipeline integrity management program. However, significant additional expenses could be incurred if new or more stringently interpreted pipeline safety requirements are implemented. In addition to required activities, our integrity management program includes several voluntary, multi-year initiatives designed to prevent incidents. Costs incurred in connection with these voluntary initiatives were approximately $24 million in 2020, and our preliminary estimate for 2021 is that we will incur approximately $18 million of such costs.
PHMSA was reauthorized and the HLPSA was amended in 2011, 2016 and 2020. The regulatory changes precipitated by these actions have increased our cost to operate. For example, in October 2019, PHMSA published three final rules that create or expand reporting, inspection, maintenance and other pipeline safety obligations. Additionally, in the Fiscal Year 2021 Omnibus Appropriations Bill, Congress reauthorized PHMSA through fiscal year 2023 and directed the agency to move forward with several regulatory actions, including the “Pipeline Safety: Class Location Change Requirements” and the “Pipeline Safety: Safety of Gas Transmission and Gathering Pipelines” proposed rulemakings. Congress has also instructed PHMSA to issue final regulations that will require operators of non-rural gas gathering lines and new and existing transmission and distribution pipeline facilities to conduct certain leak detection and repair programs and to require facility inspection and maintenance plans to align with those regulations.
In October 2015, the Governor of California signed the Oil Spill Response: Environmentally and Ecologically Sensitive Areas Bill (“AB-864”) which requires new and existing pipelines located near environmentally and ecologically sensitive areas (“EESA”) connected to or located in the coastal zone to use best available technologies (“BAT”) to reduce the amount of oil released in an oil spill to protect state waters and wildlife. BAT includes, but is not limited to, installation of leak detection technologies, automatic shutoff systems, or remote controlled sectionalized block valves, or any combination of these technologies based on a risk analysis conducted by the operator. The Regulation became effective on October 1, 2020. Milestone dates include: May 1, 2021 - Requests for exemption (for pipelines located outside the Coastal Zone, if the operator can show through spill modeling / risk analysis that a release would not impact the coastal zone portion of an EESA) or deferral (pipeline already employing BAT) from the provisions of this Article shall be submitted to the State Fire Marshal no later than this date; October 1, 2021 - Submittal of Risk analysis, BAT evaluation, and implementation plan for existing pipelines; and April 1, 2023 - Completion of retrofit of existing pipelines with BAT is due. Compliance with these requirements will impact our pipeline operations in California and add to the cost to operate the pipelines subject to these rules.
The DOT has issued guidelines with respect to securing regulated facilities against terrorist attack. We have instituted security measures and procedures in accordance with such guidelines to enhance the protection of certain of our facilities; however, we cannot provide any assurance that these security measures would fully protect our facilities from an attack.
The DOT has generally adopted American Petroleum Institute Standard (“API”) 653 as the standard for the inspection, repair, alteration and reconstruction of steel above ground petroleum storage tanks subject to DOT jurisdiction. API 653 requires regularly scheduled inspection and repair of tanks remaining in service. In the United States, our costs associated with this program were approximately $27 million in 2020. For 2021, we have budgeted approximately $30 million in connection with continued API 653 compliance activities and similar new EPA regulations for tanks not regulated by the DOT. Certain storage tanks may be taken out of service if we believe the cost of compliance will exceed the value of the storage tanks or replacement tankage may be constructed.
Canada
In Canada, the CER and provincial agencies regulate the safety and integrity management of pipelines and storage tanks used for hydrocarbon transmission. We have incurred and will continue to incur costs related to such regulatory requirements.
We continue to implement Pipeline, Facility and Cavern Integrity Management Programs to comply with applicable regulatory requirements and assist in our efforts to mitigate risk. Costs incurred for such integrity management activities were approximately $69 million in 2020. We are increasing our integrity dig and pipeline replacement projects to ensure safe and reliable operations as we seek to expand volumes on certain of our systems. Our preliminary estimate for 2021 is that we will incur approximately $81 million of costs on such projects.
We cannot predict the potential costs associated with additional, future regulation. Significant additional expenses could be incurred, and additional operational requirements and constraints could be imposed, if new or more stringently interpreted pipeline safety requirements are implemented.
Occupational Safety and Health
United States
In the United States, we are subject to the requirements of the Occupational Safety and Health Act, as amended (“OSHA”) and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that certain information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities and citizens. Certain of our facilities are subject to OSHA Process Safety Management (“PSM”) regulations, which are designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals. These regulations apply to any process which involves a chemical at or above specified thresholds or any process that involves 10,000 pounds or more of a flammable liquid or gas in one location.
Canada
Similar regulatory requirements exist in Canada under the federal and provincial Occupational Health and Safety Acts, Regulations and Codes. The agencies with jurisdiction under these regulations are empowered to enforce them through inspection, audit, incident investigation or investigation of a public or employee complaint. In some jurisdictions, the agencies have been empowered to administer penalties for contraventions without the company first being prosecuted. Additionally, under the Criminal Code of Canada, organizations, corporations and individuals may be prosecuted criminally for violating the duty to protect employee and public safety.
Solid Waste
We generate wastes, including hazardous wastes, which are subject to the requirements of the federal Resource Conservation and Recovery Act, as amended (“RCRA”), and analogous state and provincial laws. Many of the wastes that we generate are not subject to the most stringent requirements of RCRA because our operations generate primarily oil and gas wastes, which currently are excluded from consideration as RCRA hazardous wastes. It is possible, however, that in the future, the exclusion for oil and gas waste under RCRA may be revisited and our wastes subject to more rigorous and costly disposal requirements, resulting in additional capital expenditures or operating expenses.
Hazardous Substances
The federal Comprehensive Environmental Response, Compensation and Liability Act, as amended (“CERCLA”), also known as “Superfund,” and comparable state laws impose liability, without regard to fault or the legality of the original act, on certain classes of persons that contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of the site or sites where the release occurred and companies that disposed of, or arranged for the disposal of, the hazardous substances found at the site. Such persons may be subject to strict, joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain health studies. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. In the course of our ordinary operations, we may generate waste that falls within CERCLA’s definition of a “hazardous substance.” Canadian federal and provincial laws also impose liabilities for releases of certain substances into the environment.
We are subject to the Environmental Protection Agency’s (“EPA”) Risk Management Plan regulations at certain facilities. These regulations are intended to work with OSHA’s PSM regulations to minimize the offsite consequences of catastrophic releases. The regulations require us to develop and implement a risk management program that includes a five-year accident history, an offsite consequence analysis process, a prevention program and an emergency response program. In January 2016, the EPA finalized revisions to the Risk Management Plan (“RMP”) rules, including requirements for the use of third-party compliance audits, root cause analyses for facilities that experience releases, process hazard analyses and enhanced information-sharing provisions, effective March 2017. In November 2019, the EPA finalized revisions to the RMP rules, removing requirements related to public disclosure, third-party audits and post-incident root cause analyses, among others. However, several environmental groups and trade unions have challenged the EPA’s revised rule. OSHA has announced that it is considering similar revisions to the PSM rule, but, to date, has not issued a Notice of Proposed Rulemaking. The potential for further revisions to either the RMP or PSM rule is uncertain at this time.
Environmental Remediation
We currently own or lease, and in the past have owned or leased, properties where potentially hazardous liquids, including hydrocarbons, are or have been handled. These properties may be subject to CERCLA, RCRA and state and Canadian federal and provincial laws and regulations. Under such laws and regulations, we could be required to remove or remediate potentially hazardous liquids or associated wastes (including wastes disposed of or released by prior owners or operators) and to clean up contaminated property (including contaminated groundwater).
We maintain insurance of various types with varying levels of coverage that we consider adequate under the circumstances to cover our operations and properties. The insurance policies are subject to deductibles and retention levels that we consider reasonable and not excessive. Consistent with insurance coverage generally available in the industry, in certain circumstances our insurance policies provide limited coverage for losses or liabilities relating to gradual pollution, with broader coverage for sudden and accidental occurrences.
Assets we have acquired or will acquire in the future may have environmental remediation liabilities for which we are not indemnified. We have in the past experienced and in the future may experience releases of hydrocarbon products into the environment from our pipeline, rail, storage and other facility operations. We may also discover environmental impacts from past releases that were previously unidentified. The costs and liabilities associated with any such releases or environmental impacts could be significant and may not be covered by insurance; accordingly, such costs and liabilities could have a material adverse impact on our results of operations and/or financial position.
Air Emissions
Our United States operations are subject to the United States Clean Air Act (“Clean Air Act”), comparable state laws and associated federal, state and local regulations. Our Canadian operations are also subject to federal and provincial air emission regulations, which are discussed in subsequent sections.
As a result of the changing air emission requirements in both Canada and the United States, we may be required to incur certain capital and operating expenditures in the next several years to install air pollution control equipment and otherwise comply with more stringent federal, state, provincial and regional air emissions control requirements when we attempt to obtain or maintain permits and approvals for sources of air emissions. We can provide no assurance that future air compliance obligations will not have a material adverse effect on our financial condition or results of operations.
Climate Change Initiatives
United States
The EPA has adopted rules for reporting the emission of carbon dioxide, methane and other greenhouse gases (“GHG”) from certain sources. Fewer than ten of our facilities are presently subject to the federal GHG reporting requirements. These include facilities with combustion GHG emissions and potential fugitive emissions above the reporting thresholds. We import sufficient quantities of finished fuel products into the United States to be required to report that activity as well.
In 2016, the EPA finalized regulations affecting new, modified and reconstructed sources of air emission in the oil and natural gas sectors (NSPS Subpart OOOOa) that required significant reductions in fugitive methane emissions from certain upstream and midstream oil and gas facilities. We had one natural gas storage facility for which a portion was subject to this regulation. In late 2020, the EPA rescinded the methane requirements of this rule, such that no Plains facility is now affected. There is a possibility that the Biden administration may reverse these changes, and we will continue to monitor these developments. For the period during which our single facility was subject to these requirements, compliance costs were not material.
California has implemented a GHG cap-and-trade program, authorized under Assembly Bill 32 (“AB32”). Since its start in 2014, California’s cap-and-trade program has only applied to large industrial facilities with carbon dioxide equivalent emissions over 25,000 metric tons. The California Air Resources Board has published a list of facilities that are subject to this program. At this time, the list only includes one of our facilities, the Lone Star Gas Liquids facility in Shafter, California because it is a significant combustion and propane fractionation source. As a result, compliance instruments for GHG emissions have been purchased since 2013.
Effective January 1, 2015, the AB32 regulations also covered finished fuel providers and importers. California finished fuels providers (refiners and importers) are required to purchase GHG emission credits for finished fuel sold in or imported into California. Plains Marketing was included in this portion of the regulation due to propane imports and completed its first year of compliance in 2016. Effective January 1, 2018, importers of finished fuels responsible for compliance costs associated with GHG has changed from the consignee to the importer on title of the product. Plains Midstream Canada is now included in this change to the rule due to its imports of propane into California and submitted its first compliance report in 2019.
California has also implemented several climate change initiatives via executive order. Executive Order B-30-15 was signed by California’s Governor in mid-2015. This Executive Order requires a 40% reduction in GHG emissions from the 1990 baseline level by 2030. Compliance with this reduction requirement may necessitate the lowering of the threshold for industrial facilities required to participate in the GHG cap and trade program. In late 2020, the governor of California issued an executive order setting targets on the limitation or phase-out of the sale of petroleum-fueled passenger, commercial, and off-road vehicles over the next 15 to 25 years. A number of other states are working to implement zero-emission vehicle requirements or targets. Separately, in October 2020, the Governor of California signed another executive order that establishes a state goal to conserve at least 30% of California’s land and coastal waters by 2030 and directs state agencies to implement other measures to mitigate climate change and strengthen biodiversity.
Certain other states where we operate, such as Colorado, have also adopted, or are considering adopting, regulations related to GHG emissions. While it is not possible at this time to predict how federal or state governments may choose to regulate GHG emissions, any new regulatory restrictions on GHG emissions could result in material increased compliance costs, additional operating restrictions, an increase in the cost of feedstock and products produced by our refinery customers, and a reduced demand for petroleum-based fuels.
In December 2015, the Paris Agreement was signed at the 21st annual Conference of Parties to the United Nations Framework Convention on Climate Change (“UNFCCC”). The Paris Agreement, which came into effect in November 2016, requires signatory parties to develop and implement carbon emission reduction policies with a goal of limiting the rise in average global temperatures to 2°C or less. The United States is currently a signatory to the Paris Agreement. The Paris Agreement is likely to become a significant driver for future potential GHG reduction programs in participating countries, including the United States. President Biden has announced that climate change policy will be a focal point of his administration, and legislative or regulatory initiatives may be developed that may impose additional restrictions on our operations. In January 2021, President Biden signed an executive order directing the Secretary of the Interior to pause new oil and gas leases on public lands and in offshore waters of the United States. The Biden administration could also pursue the imposition of more restrictive requirements for the establishment of pipeline infrastructure or more restrictive GHG emissions limitations for oil and gas facilities. There is also a risk that financial institutions may be required to adopt policies that have the effect of reducing the funding available to the hydrocarbon energy sector. The Federal Reserve recently announced that it has joined the Network for Greening the Financial System, a consortium of financial regulators focused on addressing climate-related risks in the financial sector. Finally, to the extent increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods and other climatic events, such events could have a material adverse effect on our assets, particularly those located in coastal or flood prone areas.
Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations could result in increased compliance costs or additional operating restrictions, and could have a material adverse effect on our business, demand for our services, financial condition, results of operations and cash flows.
Canada
Federal Regulations. Large emitters of GHG have been required to report their emissions under the Canadian Greenhouse Gas Emissions Reporting Program since 2004. Effective January 1, 2018, the Federal Department of Environment and Climate Change lowered the reporting threshold for all facilities from 50 thousand tonnes per year (“kt/y”) to 10 kt/y GHG emissions. This has resulted in one additional PMC facility (for a total of four locations) being currently required to prepare annual reports of their emissions. The associated cost with this reporting requirement is not considered to be material.
In December 2015, the UNFCCC ratified the Paris Agreement to accelerate climate change initiatives and to intensify the actions of member nations in the reduction of GHG emissions. This ratification also included requirements that all parties report on their emissions status and agreement for a review every five years to assess success among member nations in attaining objectives and targets under this agreement. The Government of Canada has implemented a pan-Canadian approach to pricing carbon pollution requiring all Canadian provinces and territories to have carbon pricing in place by 2018, which is now in effect. The provinces and territories were granted flexibility in deciding how they implement carbon pricing either by placing a direct price on carbon pollution or adopting a cap and trade system. The Provincial programs that fail to meet the Federal government’s requirements for their programs are required to adopt the Federal program. The Federal program includes two components: a direct price on carbon pollution (the Federal price on carbon pollution will start at CAD$20 per tonne in 2019 and rise by CAD$10 per year to reach CAD$50 per tonne in 2022) and an output based pricing system (“OBPS”) designed to address competitiveness risk for large emitters. However, legislation has been proposed which, if enacted, may increase the carbon prices charged on businesses in jurisdictions subject to the federal program.
In November 2020, the Federal government introduced proposed legislation that would commit the government to reach net-zero GHG emissions by 2050 through setting legally-binding, five-year emissions reduction targets (2030, 2035, 2040 and 2045). The impact of this proposed legislation on PMC operations cannot be determined until the legislation is passed and details of emission reduction targets are disclosed.
In December 2020, the Federal government released a Climate Plan signaling its intent to increase the Federal price on carbon pollution from CAD$30 per tonne to CAD$50 per tonne in 2022 with a further annual increase of CAD$15 per year up to CAD$170 per tonne in 2030. Legislation has not yet been passed for the increase in price on carbon. Costs for compliance with any increase in cost of carbon will be budgeted annually as part of ordinary operating cost processes.
In April 2018, the Federal Department of Environment and Climate Change introduced regulations designed to reduce methane emissions by up to 45% by 2025 (from 2012 levels) from oil and natural gas facilities. The scope and requirements of the proposed rule are similar to the EPA methane rules described above. Effective June 2017, the Federal Department of Environment and Climate Change has introduced the Multi Sector Air Pollutants Regulations which set air pollution emission standards across Canada for several industrial sectors that utilize applicable equipment regulated under this program. The regulations establish specific limits to the amount of nitrogen oxides emitted from gas fueled boilers, heaters and stationary spark-ignition engines above a specified power rating. Based on these regulations, reporting obligations exist that are associated with seven facilities with equipment that meets specifications of the program. The implications of these regulations coming into effect are not believed to be material.
Provincial Regulations
Ontario. In February 2015, the Ontario Ministry of Environment and Climate Change issued a discussion paper that identified carbon pricing as a critical action necessary to reduce emissions of GHGs. In April 2015, the Ontario government announced it would be implementing a GHG cap and trade program, which would be implemented through the Western Climate Initiative (“WCI”), which included Quebec and California. Mandatory participants for the program were responsible for their emissions starting January 1, 2017. PMC’s facility at Sarnia was considered a mandatory participant in the program. Compliance with the federal OBPS is not expected to have a material adverse effect on our operations.
In July 2019, the Ontario government implemented the Emissions Performance Standards (“EPS”) regulation as a successor program to the repealed GHG cap and trade program. In September 2020, the Federal government accepted the EPS program as equivalent to the OBPS which allows Ontario to move forward with implementing the EPS. Ontario has yet to specify the start date of the EPS and must update regulations to bring the EPS program into effect. Until the EPS comes into force, the PMC Sarnia facility is subject to the OBPS program. Costs for compliance with the OBPS or EPS is budgeted annually and is not expected to have a material effect on operations.
In 2018, the Ontario government introduced an updated Sulphur Dioxide (“SO2”) standard which requires the reduction of SO2 from the current one hour average emission rate of 690 micrograms per cubic meter of air (“µg/m3”) to the new one hour standard of 100 µg/m3 by 2023 at industrial facilities. The introduction of this reduction measure requires evaluation of current emissions and may require equipment upgrades at our Sarnia facility. The evaluation process has not been concluded and the impact of the standard is still under review.
Alberta. The Alberta Climate Change and Emissions Management Act provided a framework for managing GHG emissions with the intent of reducing specified gas emissions to 50% of 1990 levels by December 31, 2020. The Specified Gas Emitters Regulation (“SGER”) was the initial program introduced which imposed GHG emissions limits on large emitters and required reductions in GHG emissions intensity. In January 2018, the SGER was replaced with the Carbon Competitive Incentive Regulation (“CCIR”) for compliance years 2018 and 2019. In January 2020, the Emissions Management and Climate Resilience Act replaces the Climate Change and Emissions Management Act and the CCIR was replaced with the Technology Innovation and Emissions Reduction (“TIER”) regulation. Compliance options under the TIER are similar to those under the previous SGER and CCIR programs such that a GHG fund credit purchase will be required if reduction targets identified under the program are not attained. PMC’s Empress VI facility is a mandatory participant under the TIER. For economic reasons, Ft. Saskatchewan and six other PMC facilities have opted in to be a part of the TIER program for 2020. By opting in, the fuel consumption at these asset locations avoid being subject to the federal fuel charge.
Alberta repealed the provincial “Climate Leadership Act” in May 2019 and removed its provincial carbon pricing program. The province is now subject to the federal carbon pricing program. Assets within the TIER program are exempt from the federal carbon pricing program but other fuel consumption as part of operations is subject to the federal levies. The federal fuel charge cost increase has been captured as part of the annual budgeting cycle.
In association with the federal methane reduction targets, the Alberta Energy Regulator amended Directive 60 to outline reduction requirements. New reporting measures and requirements for fugitive emission surveys and methane emission reduction came into force in January 2020. Cost for reporting and completing surveys have been captured within the 2020 and beyond annual operational budgets.
Other Canadian Jurisdictions. Nova Scotia and Quebec Cap and Trade programs cover propane supplied by PMC into the Nova Scotia and Quebec markets. PMC is required to purchase GHG emission credits and submit annual compliance reports under each province’s respective Cap and Trade program. Program compliance costs will be passed along to the purchaser. Effective April 1, 2019, the federal carbon pricing program came into effect for provinces that do not have a carbon pricing program in place. This includes Saskatchewan, Manitoba, Ontario and New Brunswick. Program compliance costs will be passed along to the purchaser.
Water
The U.S. Federal Water Pollution Control Act, as amended, also known as the Clean Water Act (“CWA”), and analogous state and Canadian federal and provincial laws impose restrictions and strict controls regarding the discharge of pollutants into navigable waters of the United States and Canada, as well as state and provincial waters. Federal, state and provincial regulatory agencies can impose administrative, civil and/or criminal penalties for non-compliance with discharge permits or other requirements of the CWA, and can also pursue injunctive relief to enforce compliance with the CWA and analogous laws.
The U.S. Oil Pollution Act of 1990 (“OPA”) amended certain provisions of the CWA as they relate to the release of petroleum products into navigable waters. OPA subjects owners of facilities to strict, joint and potentially unlimited liability for containment and removal costs, natural resource damages and certain other consequences of an oil spill. State and Canadian federal and provincial laws also impose requirements relating to the prevention of oil releases and the remediation of areas.
In addition, for over 35 years, the U.S. Army Corps of Engineers (the “Corps”) has authorized construction, maintenance and repair of pipelines under a streamlined nationwide permit program under the CWA known as Nationwide Permit 12 (“NWP”). The NWP program is supported by strong statutory and regulatory history and was originally approved by Congress in 1977. From time to time, environmental groups have challenged the NWP program; however, to date, federal courts have upheld the validity of the NWP program under the CWA. In April 2020, the U.S. District Court for the District of Montana invalidated the 2017 decision by the Corps to reissue the NWP; however, industry groups appealed the decision, and the NWP was reinstated by the U.S. Supreme Court, pending a U.S. Circuit Court appeal process. We anticipate that the appeal will be decided in 2021. Additionally, in response to the vacatur, the Corps has announced a reissuance of the NWP 12 for oil and natural gas pipeline activities, including certain revisions to the conditions for the use of NWP 12; however, the rule has not been officially published and, with President Biden taking office in January 2021, may be subject to further revisions or suspension. While the full extent and impact of the vacatur is unclear at this time, we could face significant delays and financial costs when seeking project approvals from the Corps if we cannot obtain coverage under NWP 12.
In May 2015, the EPA published a final rule that attempted to clarify federal jurisdiction under the CWA over waters of the United States (“WOTUS”). This clarification greatly expanded the definition of WOTUS, thus increasing the jurisdiction of the Corps. Following the issuance of a presidential executive order to review the rule in January 2017, the EPA and the Corps proposed a rulemaking in June 2017 to repeal the May 2015 rule. The EPA and Corps also announced their intent to issue a new rule defining the CWA’s jurisdiction and finalized a stay delaying implementation of the 2015 rule for two years. Several states and environmental organizations announced their intent to challenge the stay and any attempt by the EPA and the Corps to rescind or revise the rule. However, on April 21, 2020, the EPA and the Corps announced the 2020 Final Rule concerning the redefinition of WOTUS. The 2020 Final Rule provides the outer bounds of the federal waters covered under the CWA’s key permitting programs such as Section 404 dredge and fill permits, Section 402 discharge permits and Section 311 oil spill prevention plans. The Final Rule took effect on June 22, 2020. In general, the 2020 Final Rule resulted in fewer federally regulated waters under the CWA offering a streamlined list of only four clear categories of jurisdictional waters and 12 exclusions. A decrease in mitigation requirements is expected, with traditional wetland states (e.g., Louisiana) and states in the arid west (e.g., Texas) expected to be among the most affected by the new rule. However, legal challenges to this rulemaking are ongoing, and it is possible that the new presidential administration could propose a broader interpretation of WOTUS.
Endangered Species
New projects may require approvals and environmental analysis under federal, state and provincial laws, including the National Environmental Policy Act and the Endangered Species Act in the United States and the Species at Risk Act in Canada. The resulting costs and liabilities associated with lengthy regulatory review and approval requirements could materially and negatively affect the viability of such projects.
Other Regulations
Transportation Regulation
Our transportation activities are subject to regulation by multiple governmental agencies. Our historical operating costs reflect the recurring costs resulting from compliance with these regulations. The following is a summary of the types of transportation regulation that may impact our operations.
General Interstate Regulation in the United States. Our interstate common carrier liquids pipeline operations are subject to rate regulation by the U.S. Federal Energy Regulatory Commission (“FERC”) under the Interstate Commerce Act (“ICA”). The ICA requires that tariff rates for liquids pipelines, which include both crude oil pipelines and refined products pipelines, be just and reasonable and non-discriminatory. Failure to comply with the requirements of the ICA could result in the imposition of civil or criminal penalties.
State Regulation in the United States. Our intrastate liquids pipeline transportation activities are subject to various state laws and regulations, as well as orders of state regulatory bodies, including the Railroad Commission of Texas (“TRRC”) and the California Public Utility Commission (“CPUC”). The CPUC prohibits certain of our subsidiaries from acting as guarantors of our senior notes and credit facilities.
U.S. Energy Policy Act of 1992 and Subsequent Developments. In October 1992, Congress passed the Energy Policy Act of 1992 (“EPAct”), which, among other things, required the FERC to issue rules to establish a simplified and generally applicable ratemaking methodology for petroleum pipelines and to streamline procedures in petroleum pipeline proceedings. The FERC responded to this mandate by establishing a formulaic methodology for petroleum pipelines to change their rates within prescribed ceiling levels that are tied to an inflation index. The FERC reviews the formula every five years. Pursuant to a December 2020 Order, commencing July 1, 2021, the annual index adjustment for the five year period ending June 30, 2026 will equal the producer price index for finished goods for the applicable year plus an adjustment factor of 0.78%. Rehearing of the December 2020 Order has been requested, and the requests remain pending before FERC. Pipelines may raise their rates to the rate ceiling level generated by application of the annual index adjustment factor each year; however, a shipper may challenge such increase if the increase in the pipeline’s rates is substantially in excess of the actual cost increases incurred by the pipeline during the relevant year. If the FERC’s annual index adjustment reduces the ceiling level such that it is lower than a pipeline’s filed rate, the pipeline must reduce its rate to conform with the lower ceiling. Indexing is the default methodology to change rates. The FERC, however, retained cost-of-service ratemaking, market-based rates and settlement rates as alternatives to the indexing approach that may be used in certain specified circumstances. Because the indexing methodology for the next five-year period is tied in part to an inflation index and is not based on our specific costs, the indexing methodology could hamper our ability to recover cost increases.
Under the EPAct, petroleum pipeline rates in effect for the 365-day period ending on the date of enactment of EPAct are deemed to be just and reasonable under the ICA if such rates had not been subject to complaint, protest or investigation during such 365-day period. Generally, complaints against such “grandfathered” rates may only be pursued if the complainant can show that a substantial change has occurred since the enactment of EPAct in either the economic circumstances of the oil pipeline or in the nature of the services provided that were a basis for the rate. EPAct places no such limit on challenges to a provision of an oil pipeline tariff rate or rules as unduly discriminatory or preferential.
Pipeline Rate Regulation in the United States. The FERC historically has not investigated rates of liquids pipelines on its own initiative when those rates have not been the subject of a protest or complaint by a shipper. The majority of our Transportation segment profit in the United States is produced by rates that are either grandfathered or set by agreement with one or more shippers. These rates remain regulated by FERC and are subject to challenge or review and modification by FERC consistent with the requirements of the ICA, which requires that tariff rates for liquids pipelines, which include both crude oil pipelines and refined products pipelines, be just and reasonable and non-discriminatory. See Item 1A. “Risk Factors-Risks Related to Laws and Regulations Impacting PAA’s Business-PAA’s assets are subject to federal, state and provincial regulation. Rate regulation or a successful challenge to the rates PAA charges on its U.S. and Canadian pipeline systems may reduce the amount of cash it generates.” 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.
Trucking Regulation
United States
We operate a fleet of trucks to transport crude oil and oilfield materials as a private, contract and common carrier. We are licensed to perform both intrastate and interstate motor carrier services. As a motor carrier, we are subject to certain safety regulations issued by the Federal Motor Carrier Safety Association of the DOT. The trucking regulations cover, among other things: (i) driver operations, (ii) log book maintenance, (iii) truck manifest preparations, (iv) safety placard placement on the trucks and trailer vehicles, (v) drug and alcohol testing and (vi) operation and equipment safety. We are also subject to OSHA with respect to our U.S. trucking operations.
Canada
Our trucking assets in Canada are subject to regulation by both federal and provincial transportation agencies in the provinces in which they are operated. These regulatory agencies do not set freight rates, but do establish and administer rules and regulations relating to other matters including equipment, facility inspection, reporting and safety. We are licensed to operate both intra- and inter-provincially under the direction of the National Safety Code (“NSC”) that is administered by Transport Canada. Our for-hire service is primarily the transportation of crude oil, condensates and NGL. We are required under the NSC to, among other things, monitor: (i) driver operations, (ii) log book maintenance, (iii) truck manifest preparations, (iv) safety placard placement on the trucks and trailers, (v) operation and equipment safety and (vi) many other aspects of trucking operations. We are also subject to Occupational Health and Safety regulations with respect to our Canadian trucking operations.
Railcar Regulation
We own and operate a number of railcar loading and unloading facilities in the United States and Canada. In connection with these rail terminals, we own and lease a significant number of railcars. Our railcar operations are subject to the regulatory jurisdiction of the Federal Railroad Administration of the DOT, the OSHA, as well as other federal and state regulatory agencies and Canadian regulatory agencies for operations in Canada.
Railcar accidents involving trains carrying crude oil from North Dakota’s Bakken shale formation have led to increased regulatory scrutiny. PHMSA issued a safety advisory warning that Bakken crude may be more flammable than other grades of crude oil and reinforcing the requirement to properly test, characterize, classify, and, where appropriate, sufficiently degasify hazardous materials prior to and during transportation. PHMSA also initiated “Operation Classification,” a compliance initiative involving unannounced inspections and testing of crude oil samples to verify that offerors of the materials have properly classified, described and labeled the hazardous materials before transportation. In December 2015, Congress passed the Fixing America’s Surface Transportation (“FAST”) Act which was subsequently signed by the President. This legislation clarified the parameters around the timeline and requirements for railcars hauling crude oil in the United States. We believe our railcar fleet is in compliance in all material respects with current standards for crude oil moved by rail.
In December 2014, the North Dakota Industrial Commission adopted new standards to improve the safety of Bakken crude oil for transport. The new standard, Commission Order 25417, was effective April 1, 2015, and requires operators/producers to condition Bakken crude oil to certain vapor pressure limits. Under the order, all Bakken crude oil produced in North Dakota will be conditioned with no exceptions. The order requires operators/producers to separate light hydrocarbons from all Bakken crude oil to be transported and prohibits the blending of light hydrocarbons back into oil supplies prior to shipment. We are not directly responsible for the conditioning or stabilization of Bakken crude oil; however, under the order, it is our responsibility to notify the State of North Dakota upon discovering that Bakken crude oil received at our rail facility exceeds the permitted vapor pressure limits.
Indigenous Protections
Part of our operations cross land that has historically been apportioned to various Native American/First Nations tribes (“Indigenous Peoples”), who may exercise significant jurisdiction and sovereignty over their lands. Indigenous Peoples may also have certain treaty rights and rights to consultation on projects that may affect such lands. Our operations may be impacted to the extent these tribal governments are found to have and choose to act upon such jurisdiction over lands where we operate. For example, in 2020, the Supreme Court ruled in McGirt v. Oklahoma that the Muscogee (Creek) Nation reservation in Eastern Oklahoma has not been disestablished (i.e., officially unrecognized). Prior to the court’s ruling, the prevailing view was that all reservations within Oklahoma had been disestablished prior to statehood in 1907. Although the court’s ruling indicates that it is limited to criminal law as applied within the Muscogee (Creek) Nation reservation, the ruling has significant potential implications for civil law within the Muscogee (Creek) Nation reservation, as well as other reservations that may similarly be found to not have been disestablished. Later in 2020, state courts in Oklahoma, applying the analysis in McGirt, ruled that the Cherokee, Chickasaw, Seminole, and Choctaw reservations likewise had not been disestablished.
On October 1, 2020, the EPA granted approval to the State of Oklahoma under Section 10211(a) of the Safe, Accountable, Flexible, Efficient Transportation Equity Act of 2005 (the “SAFETE Act”) to administer all of the State’s existing EPA-approved regulatory programs to Indian Country within the State except: Indian allotments to which Indian titles have not been extinguished; lands that are held in trust by the United States on behalf of any Indian or Tribe; lands that are owned in fee by any Tribe where title was acquired through a treaty with the United States to which such Tribe is a party and that have never been allotted to any citizen or member of such Tribe. The approval extends the State’s authority for existing EPA-approved regulatory programs to all lands within the State to which the State applied such programs prior to the U.S. Supreme Court’s ruling regarding the Muscogee (Creek) Nation reservation. However, several Tribes have expressed dissatisfaction with the consultation process performed in relation to this approval, and it is possible that EPA’s approval under the SAFETE Act could be challenged. Additionally, the SAFETE Act provides that any Tribe in Oklahoma may seek “Treatment as a State” by the EPA, and it is possible that one or more of the Tribes in Oklahoma may seek such an approval from EPA. At this time, we cannot predict how these jurisdictional issues may ultimately be resolved.
Cross Border Regulation
As a result of our cross border activities, including transportation and importation of crude oil, NGL and natural gas between the United States and Canada, we are subject to a variety of legal requirements pertaining to such activities including presidential permit requirements, export/import license requirements, tariffs, Canadian and U.S. customs and taxes and requirements relating to toxic substances. U.S. legal requirements relating to these activities include regulations adopted pursuant to the Short Supply Controls of the Export Administration Act (“EAA”), the North American Free Trade Agreement (“NAFTA”) replacement, the United States-Mexico-Canada Agreement (“USMCA”) (July 1, 2020) and the Toxic Substances Control Act (“TSCA”), as well as presidential permit requirements of the U.S. Department of State. In addition, the importation and exportation of natural gas from and to the United States and Canada is subject to regulation by U.S. Customs and Border Protection, U.S. Department of Energy and the CER. Violations of these licensing, tariff and tax reporting requirements or failure to provide certifications relating to toxic substances could result in the imposition of significant administrative, civil and criminal penalties. Furthermore, the failure to comply with U.S. federal, state and local tax requirements, as well as Canadian federal and provincial tax requirements, could lead to the imposition of additional taxes, interest and penalties.
Market Anti-Manipulation Regulation
In November 2009, the Federal Trade Commission (“FTC”) issued regulations pursuant to the Energy Independence and Security Act of 2007, intended to prohibit market manipulation in the petroleum industry. Violators of the regulations face civil penalties of up to approximately $1.25 million per violation per day, subject to the FTC’s annual inflation adjustment. In July 2010, Congress passed the Dodd-Frank Act, which incorporated an expansion of the authority of the Commodity Futures Trading Commission (“CFTC”) to prohibit market manipulation in the markets regulated by the CFTC. This authority, with respect to crude oil swaps and futures contracts, is similar to the anti-manipulation authority granted to the FTC with respect to crude oil purchases and sales. In July 2011, the CFTC issued final rules to implement their new anti-manipulation authority. The rules subject violators to a civil penalty of up to the greater of approximately $1.23 million, subject to the CFTC’s annual inflation adjustment, or triple the monetary gain to the person for each violation.
Natural Gas Storage Regulation
Our natural gas storage operations are subject to regulatory oversight by numerous federal, state and local regulatory agencies, many of which are authorized by statute to issue, and have issued, rules and regulations binding on the natural gas storage and pipeline industry, related businesses and market participants. The failure to comply with such laws and regulations can result in substantial penalties and fines.
The following is a summary of the kinds of regulation that may impact our natural gas storage operations. However, our unitholders should not rely on such discussion as an exhaustive review of all regulatory considerations affecting our natural gas storage operations.
Our natural gas storage facilities provide natural gas storage services in interstate commerce and are subject to comprehensive regulation by the FERC under the Natural Gas Act of 1938 (“NGA”). Pursuant to the NGA and FERC regulations, storage providers are prohibited from making or granting any undue preference or advantage to any person or subjecting any person to any undue prejudice or disadvantage or from maintaining any unreasonable difference in rates, charges, service, facilities, or in any other respect. The terms and conditions for services provided by our facilities are set forth in natural gas tariffs on file with the FERC. We have been granted market-based rate authorization for the services that our facilities provide. Market-based rate authority allows us to negotiate rates with individual customers based on market demand.
The FERC also has authority over the siting, construction, and operation of United States pipeline transportation and storage facilities and related facilities used in the transportation, storage and sale for resale of natural gas in interstate commerce, including the extension, enlargement or abandonment of such facilities. The FERC’s authority extends to maintenance of accounts and records, terms and conditions of service, acquisition and disposition of facilities, initiation and discontinuation of services, imposition of creditworthiness and credit support requirements applicable to customers and relationships among pipelines and storage companies and certain affiliates. Our natural gas storage entities are required by the FERC to post certain information daily regarding customer activity, capacity and volumes on their respective websites. Additionally, the FERC has jurisdiction to impose rules and regulations applicable to all natural gas market participants to ensure market transparency. FERC regulations require that buyers and sellers of more than a de minimis volume of natural gas report annual numbers and volumes of relevant transactions to the FERC. Our natural gas storage facilities are subject to these annual reporting requirements.
Under the Energy Policy Act of 2005 (“EPAct 2005”) and related regulations, it is unlawful in connection with the purchase or sale of natural gas or transportation services subject to FERC jurisdiction to use or employ any device, scheme or artifice to defraud; to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or to engage in any act or practice that operates as a fraud or deceit upon any person. EPAct 2005 gives the FERC civil penalty authority to impose penalties for certain violations of up to approximately $1.31 million per day for each violation, subject to FERC’s annual inflation adjustment. FERC also has the authority to order disgorgement of profits from transactions deemed to violate the NGA and the EPAct 2005.
In January 2020, PHMSA finalized a rule regarding the safety of underground natural gas storage facilities, which was published in the Federal Register on February 12, 2020. This rule maintains several elements from the earlier interim rule, incorporating API Recommended Practices 1170 and 1171 in PHMSA regulations; revises the definition of underground natural gas storage facility; and clarifies certain reporting and notification criteria. We do not anticipate that compliance with the final rule will have a significant adverse effect on our operations.
The natural gas industry historically has been heavily regulated. New rules, orders, regulations or laws may be passed or implemented that impose additional costs, burdens or restrictions on us. We cannot give any assurance regarding the likelihood of such future rules, orders, regulations or laws or the effect they could have on our business, financial condition, and results of operations or ability to make distributions to our unitholders.
Operational Hazards and Insurance
Pipelines, terminals, trucks or other facilities or equipment may experience damage as a result of an accident, natural disaster, terrorist attack, cyber event or other event. These hazards can cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage and suspension of operations. We maintain various types and varying levels of insurance coverage to cover our operations and properties, and we self-insure certain risks, including gradual pollution, cybersecurity and named windstorms. However, such insurance does not cover every potential risk that might occur, associated with operating pipelines, terminals and other facilities and equipment, including the potential loss of significant revenues and cash flows.
The occurrence of a significant event not fully insured, indemnified or reserved against, or the failure of a party to meet its indemnification obligations, could materially and adversely affect our operations and financial condition. We believe that we maintain adequate insurance coverage, although insurance will not cover many types of interruptions that might occur, will not cover amounts up to applicable deductibles and will not cover all risks associated with certain of our assets and operations. With respect to our insurance coverage, our policies are subject to deductibles and retention levels that we consider reasonable and not excessive. Additionally, no assurance can be given that we will be able to maintain adequate insurance in the future at rates we consider reasonable. As a result, we may elect to self-insure or utilize higher deductibles in certain other insurance programs. In addition, although we believe that we have established adequate reserves and liquidity to the extent such risks are not insured, costs incurred in excess of these reserves may be higher or we may not receive insurance proceeds in a timely manner, which may potentially have a material adverse effect on our financial conditions, results of operations or cash flows.
Title to Properties and Rights-of-Way
Our real property holdings generally consist of: (i) parcels of land that we own in fee, (ii) surface leases and underground storage leases and (iii) easements, rights-of-way, permits, crossing agreements or licenses from landowners or governmental authorities permitting the use of certain lands for our operations. In all material respects, we believe we have satisfactory title or the right to use the sites upon which our significant facilities are located, subject to (a) customary liens, restrictions or encumbrances and (b) challenges that we do not regard as material relative to our overall operations. Some of our real property rights may be subject to termination under agreements that provide for one or more of: periodic payments, term periods, renewal rights, abandonment of use, continuous operation requirements, revocation by the licensor or grantor and possible relocation obligations.
Human Capital
General
Our primary human capital management objective is to attract, retain and develop a high quality workforce that will enable us to maintain and enhance a culture that is consistent with our core values of safety and environmental stewardship; ethics and integrity; accountability; and respect and fairness. To support this objective, we seek to attract, reward and support employees through competitive pay, benefits and other programs; develop employees and encourage internal talent mobility to prepare employees for critical roles and leadership positions for the future; facilitate the development of a workplace culture that is diverse, engaging and inclusive; and promote efficiency and a high performance culture by investing in technology and systems and providing tools and resources that enable employees at work.
Neither we nor our general partner have officers or employees. All of our officers and other personnel necessary for our business to function are employed by GP LLC or PMCULC. As of December 31, 2020, GP LLC and PMCULC employed approximately 4,400 people in North America, of which approximately 3,200 were employed in the U.S. and approximately 1,200 were employed in Canada. Approximately 68% of our workforce (approximately 3,000 employees) are field employees, which includes approximately 880 employees in our trucking division. Our employees are located in 29 states in the U.S. and in 4 provinces in Canada. Approximately 136 employees are covered by five separate collective bargaining agreements, which run through 2023 and 2024.
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 has provided free mental and behavioral support for employees during the COVID-19 pandemic. 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. Since 2017, for each of these metrics, we have improved our performance each year and achieved cumulative three year reductions of more than 50%.
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, 2020, approximately 21% of our overall workforce was female (44% exclusive of field employees), and minorities represented approximately 31% of our U.S. workforce (36% 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
We are committed to the continued development of our people. We provide a multitude of training programs covering topics such as field operations, health and safety, regulatory compliance, technical training, management and leadership skills, and professional development. We also operate a number of internal programs at all levels of the workforce that are designed to identify and develop future leaders of the organization. The Board receives reports from senior management on a regular basis regarding the status of succession plans with respect to executive leadership of the company.
Benefits
Our compensation and benefits programs are designed to attract, retain and motivate our employees and to reward them for their services and success. In addition to providing competitive salaries and other compensation opportunities, we offer comprehensive and competitive benefits to our eligible employees including, depending on location, life and health (medical, dental and vision) insurance, prescription drug benefits, flexible spending accounts, parental leave, disability coverage, mental and behavioral health resources, paid time off, retirement savings plan, education reimbursement program and a disaster relief fund.
Summary of Tax Considerations
The following is a summary of material U.S. federal income tax consequences and tax considerations related to the purchase, ownership and disposition of our Class A shares by a taxpayer that holds our Class A shares as a “capital asset” (generally property held for investment). This summary is based on the provisions of the Internal Revenue Code of 1986, as amended (the “Code”), U.S. Treasury regulations, administrative rulings and judicial decisions, all as in effect on the date hereof, and all of which are subject to change or differing interpretations, possibly with retroactive effect. We have not sought any ruling from the Internal Revenue Service, or the IRS, with respect to the statements made and the conclusions reached in the following summary, and there can be no assurance that the IRS or a court will agree with such statements and conclusions.
This summary does not address all aspects of U.S. federal income taxation or the tax considerations arising under the laws of any non-U.S., state, or local jurisdiction, or under U.S. federal estate and gift tax laws. In addition, this summary does not address tax considerations applicable to investors that may be subject to special treatment under the U.S. federal income tax laws. The tax consequences of ownership of Class A shares depends in part on the owner’s individual tax circumstances. It is the responsibility of each shareholder, either individually or through a tax advisor, to investigate the legal and tax consequences, under the laws of pertinent U.S. federal, states and localities, as well as Canada and the Canadian provinces, of the shareholder’s investment in us. Further, it is the responsibility of each shareholder to file all U.S. federal, Canadian, state, provincial and local tax returns that may be required of the shareholder. Also see Item 1A. “Risk Factors-Tax Risks.”
Corporate Status
Although we are a Delaware limited partnership, we have elected to be treated as a corporation for U.S. federal income tax purposes. As a result, we are subject to tax as a corporation and distributions on our Class A shares will be treated as distributions on corporate stock for U.S. federal income tax purposes. No Schedule K-1 will be issued with respect to our Class A shares. Instead, holders of Class A shares will receive a Form 1099 from us with respect to distributions received on our Class A shares.
Consequences to U.S. Holders
The discussion in this section is addressed to holders of our Class A shares who are U.S. holders for U.S. federal income tax purposes. For the purposes of this discussion, a “U.S. holder” is a beneficial owner of our Class A shares that, for U.S. federal income tax purposes, is:
•an individual who is a citizen or resident of the United States;
•a corporation (or other entity treated as a corporation for U.S. federal income tax purposes) created or organized in or under the laws of the United States, any state thereof or the District of Columbia;
•an estate the income of which is subject to U.S. federal income tax regardless of its source; or
•a trust (i) the administration of which is subject to the primary supervision of a U.S. court and which has one or more United States persons who have the authority to control all substantial decisions of the trust or (ii) which has made a valid election under applicable U.S. Treasury regulations to be treated as a United States person.
Distributions
Distributions with respect to our Class A shares will constitute dividends for U.S. federal income tax purposes to the extent paid from our current or accumulated earnings and profits, as determined under U.S. federal income tax principles. To the extent that the amount of a distribution with respect to our Class A shares exceeds our current and accumulated earnings and profits, such distribution will be treated first as a tax-free return of capital to the extent of the U.S. holder’s adjusted tax basis in such Class A shares, which reduces such basis dollar-for-dollar, and thereafter as capital gain from the sale or exchange of such Class A shares. See “-Gain on Disposition of Class A Shares.” Non-corporate holders that receive distributions on our Class A shares that are treated as dividends for U.S. federal income tax purposes generally will be subject to U.S. federal income tax at a reduced rate (currently at a maximum rate of 20%) provided certain holding period requirements are met.
Both AAP and PAA have made elections permitted by Section 754 of the Code. As a result, our acquisition of AAP units in connection with our initial public offering (“IPO”) and in connection with exchanges since the IPO by the holders of our Class B shares and the AAP units not held by us (“Legacy Owners”) and their permitted transferees of their AAP units and Class B shares for Class A shares have resulted in basis adjustments with respect to our interest in the assets of AAP (and indirectly in PAA). Such adjustments have resulted in depreciation and amortization deductions that we anticipate will offset a substantial portion of our taxable income for an extended period of time. In addition, future exchanges of AAP units and Class B shares for our Class A shares will result in additional basis adjustments with respect to our interest in the assets of AAP (and indirectly in PAA). We expect to benefit from additional tax deductions resulting from those adjustments, the amount of which will vary depending on the value of the Class A shares at the time of the exchange.
As a result of the basis adjustments described above, we may not have sufficient earnings and profits for distributions on our Class A shares to qualify as dividends for U.S. federal income tax purposes. If a distribution on our Class A shares fails to qualify as a dividend for U.S. federal income tax purposes, such distribution will be treated first as a tax-free return of capital to the extent of the U.S. holder’s adjusted tax basis in our Class A shares and thereafter as capital gain from the sale or exchange of our Class A shares. As a result, U.S. corporate holders will be unable to utilize the corporate dividends-received deduction with respect to such distribution.
Investors in our Class A shares are encouraged to consult their tax advisors as to the tax consequences of receiving distributions on our Class A shares that do not qualify as dividends for U.S. federal income tax purposes, including, in the case of corporate investors, the inability to claim the corporate dividends received deduction with respect to such distributions.
Gain on Disposition of Class A Shares
A U.S. holder generally will recognize capital gain or loss on a sale, exchange, certain redemptions, or other taxable disposition of our Class A shares equal to the difference, if any, between the amount realized upon the disposition of such Class A shares and the U.S. holder’s adjusted tax basis in those shares. A U.S. holder’s tax basis in our shares generally will be equal to the amount paid for such shares reduced (but not below zero) by distributions received on such shares that are not treated as dividends for U.S. federal income tax purposes. Such capital gain or loss generally will be long-term capital gain or loss if the U.S. holder’s holding period for the shares sold or disposed of is more than one year. Long-term capital gains of individuals generally are subject to U.S. federal income tax at a reduced rate (currently at a maximum rate of 20%). The deductibility of net capital losses is subject to limitations.
Backup Withholding and Information Reporting
Information returns generally will be filed with the IRS with respect to distributions on our Class A shares and the proceeds from a disposition of our Class A shares. U.S. holders may be subject to backup withholding on distributions with respect to our Class A shares and on the proceeds of a disposition of our Class A shares unless such U.S. holders furnish the applicable withholding agent with a taxpayer identification number, certified under penalties of perjury, and certain other information, or otherwise establish, in the manner prescribed by law, an exemption from backup withholding. Penalties apply for failure to furnish correct information and for failure to include reportable payments in income.
Backup withholding is not an additional tax. Any amounts withheld under the backup withholding rules will be creditable against a U.S. holder’s U.S. federal income tax liability, and the U.S. holder may be entitled to a refund, provided the U.S. holder timely furnishes the required information to the IRS. U.S. holders are urged to consult their own tax advisors regarding the application of the backup withholding rules to their particular circumstances and the availability of, and procedure for, obtaining an exemption from backup withholding.
Consequences to Non-U.S. Holders
The discussion in this section is addressed to holders of our Class A shares who are non-U.S. holders for U.S. federal income tax purposes. For purposes of this discussion, a “non-U.S. holder” is a beneficial owner of our Class A shares that is an individual, corporation, estate or trust that is not a U.S. holder as defined above.
Distributions
Distributions with respect to our Class A shares will constitute dividends for U.S. federal income tax purposes to the extent paid from our current or accumulated earnings and profits, as determined under U.S. federal income tax principles. To the extent those distributions exceed our current and accumulated earnings and profits, the distributions will be treated as a non-taxable return of capital to the extent of the non-U.S. holder’s tax basis in our common stock and thereafter as capital gain from the sale or exchange of such common stock. See “-Gain on Disposition of Class A Shares.” Subject to the withholding requirements under FATCA (as defined below) and with respect to effectively connected dividends, each of which is discussed below, any distribution made to a non-U.S. holder on our Class A shares generally will be subject to U.S. withholding tax at a rate of 30% of the gross amount of the distribution unless an applicable income tax treaty provides for a lower rate. To the extent a distribution exceeds our current and accumulated earnings and profits, such distribution will reduce the non-U.S. holder’s adjusted tax basis in its Class A shares (but not below zero). The amount of any such distribution in excess of the non-U.S. holder's adjusted tax basis in its Class A shares will be treated as gain from the sale of such shares and will have the tax consequences described below under “Gain on Disposition of Class A Shares.” The rules applicable to distributions by a United States real property holding corporation (a “USRPHC”) to non-U.S. persons that exceed current and accumulated earnings and profits are not clear. As a result, it is possible that U.S. federal income tax at a rate not less than 15% (or such lower rate as specified by an applicable income tax treaty for distributions from a USRPHC) may be withheld from distributions received by non-U.S. holders that exceed our current and accumulated earnings and profits. To receive the benefit of a reduced treaty rate, a non-U.S. holder must provide the applicable withholding agent with an IRS Form W-8BEN or IRS Form W-8BEN-E (or other applicable or successor form) certifying qualification for the reduced rate.
Non-U.S. holders are encouraged to consult their tax advisors regarding the withholding rules applicable to distributions on our Class A shares, the requirement for claiming treaty benefits, and any procedures required to obtain a refund of any overwithheld amounts.
Distributions treated as dividends that are paid to a non-U.S. holder and that are effectively connected with a trade or business conducted by the non-U.S. holder in the United States (and, if required by an applicable income tax treaty, are treated as attributable to a permanent establishment maintained by the non-U.S. holder in the United States) generally will be taxed on a net income basis at the rates and in the manner generally applicable to United States persons (as defined under the Code). Such effectively connected dividends will not be subject to U.S. withholding tax if the non-U.S. holder satisfies certain certification requirements by providing the applicable withholding agent with a properly executed IRS Form W-8ECI certifying eligibility for exemption. If the non-U.S. holder is a corporation for U.S. federal income tax purposes, it may also be subject to a branch profits tax (at a 30% rate or such lower rate as specified by an applicable income tax treaty) on its effectively connected earnings and profits (as adjusted for certain items), which will include effectively connected dividends.
Gain on Disposition of Class A Shares
Subject to the discussion below under “-Backup Withholding and Information Reporting,” a non-U.S. holder generally will not be subject to U.S. federal income or withholding tax on any gain realized upon the sale or other disposition of our Class A shares unless:
•the non-U.S. holder is an individual who is present in the United States for a period or periods aggregating 183 days or more during the calendar year in which the sale or disposition occurs and certain other conditions are met;
•the gain is effectively connected with a trade or business conducted by the non-U.S. holder in the United States (and, if required by an applicable income tax treaty, is attributable to a permanent establishment maintained by the non-U.S. holder in the United States); or
•our Class A shares constitute a United States real property interest by reason of our status as a USRPHC for U.S. federal income tax purposes and as a result such gain is treated as effectively connected with a trade or business conducted by the non-U.S. holder in the United States.
A non-U.S. holder described in the first bullet point above will be subject to U.S. federal income tax at a rate of 30% (or such lower rate as specified by an applicable income tax treaty) on the amount of such gain, which generally may be offset by U.S. source capital losses.
A non-U.S. holder whose gain is described in the second bullet point above or, subject to the exceptions described in the next paragraph, the third bullet point above, generally will be taxed on a net income basis at the rates and in the manner generally applicable to United States persons (as defined under the Code) unless an applicable income tax treaty provides otherwise. If the non-U.S. holder is a corporation for U.S. federal income tax purposes whose gain is described in the second bullet point above, then such gain would also be included in its effectively connected earnings and profits (as adjusted for certain items), which may be subject to a branch profits tax (at a 30% rate or such lower rate as specified by an applicable income tax treaty).
Generally, a corporation is a USRPHC if the fair market value of its United States real property interests equals or exceeds 50% of the sum of the fair market value of its worldwide real property interests and its other assets used or held for use in a trade or business. We believe that we currently are, and expect to remain for the foreseeable future, a USRPHC for U.S. federal income tax purposes. However, as long as our Class A shares continue to be “regularly traded on an established securities market” (within the meaning of the U.S. Treasury Regulations), only a non-U.S. holder that actually or constructively owns, or owned at any time during the shorter of the five-year period ending on the date of the disposition or the non-U.S. holder’s holding period for the Class A shares, more than 5% of our Class A shares will be treated as disposing of a United States real property interest and will be taxable on gain realized on the disposition of our Class A shares as a result of our status as a USRPHC. If our Class A shares were not considered to be regularly traded on an established securities market, such non-U.S. holder (regardless of the percentage of our Class A shares owned) would be treated as disposing of a United States real property interest and would be subject to U.S. federal income tax on a taxable disposition of our Class A shares (as described in the preceding paragraph), and a 15% withholding tax would apply to the gross proceeds from such disposition.
Non-U.S. holders should consult their tax advisors with respect to the application of the foregoing rules to their ownership and disposition of our Class A shares, including regarding potentially applicable income tax treaties that may provide for different rules.
Backup Withholding and Information Reporting
Any distributions paid to a non-U.S. holder must be reported annually to the IRS and to each non-U.S. holder. Copies of these information returns may be made available to the tax authorities in the country in which the non-U.S. holder resides or is established. Payments of distributions to a non-U.S. holder generally will not be subject to backup withholding if the non-U.S. holder establishes an exemption by properly certifying its non-U.S. status on an IRS Form W-8BEN, or IRS Form W-8BEN-E (or other applicable or successor form).
Payments of the proceeds from a sale or other disposition by a non-U.S. holder of our Class A shares effected by or through a U.S. office of a broker generally will be subject to information reporting and backup withholding (at the applicable rate) unless the non-U.S. holder establishes an exemption by properly certifying its non-U.S. status on an IRS Form W-8BEN or IRS Form W-8BEN-E (or other applicable or successor form) and certain other conditions are met. Information reporting and backup withholding generally will not apply to any payment of the proceeds from a sale or other disposition of our Class A shares effected outside the United States by a non-U.S. office of a broker. However, unless such broker has documentary evidence in its records that the non-U.S. holder is not a United States person and certain other conditions are met, or the non-U.S. holder otherwise establishes an exemption, information reporting will apply to a payment of the proceeds of the disposition of our Class A shares effected outside the United States by such a broker if it has certain relationships within the United States.
Backup withholding is not an additional tax. Rather, the U.S. federal income tax liability (if any) of persons subject to backup withholding will be reduced by the amount of tax withheld. If backup withholding results in an overpayment of taxes, a refund may be obtained, provided that the required information is timely furnished to the IRS.
Additional Withholding Requirements under FATCA
Sections 1471 through 1474 of the Code, and the U.S. Treasury regulations and administrative guidance issued thereunder (“FATCA”), impose a 30% withholding tax on any dividends paid on our Class A shares if paid to a “foreign financial institution” or a “non-financial foreign entity” (each as defined in the Code) (including, in some cases, when such foreign financial institution or non-financial foreign entity is acting as an intermediary), unless (i) in the case of a foreign financial institution, such institution enters into an agreement with the U.S. government to withhold on certain payments, and to collect and provide to the U.S. tax authorities substantial information regarding U.S. account holders of such institution (which includes certain equity and debt holders of such institution, as well as certain account holders that are non-U.S. entities with U.S. owners), (ii) in the case of a non-financial foreign entity, such entity certifies that it does not have any “substantial United States owners” (as defined in the Code) or provides the applicable withholding agent with a certification identifying the direct and indirect substantial United States owners of the entity (in either case, generally on an IRS Form W-8BEN-E), or (iii) the foreign financial institution or non-financial foreign entity otherwise qualifies for an exemption from these rules and provides appropriate documentation (such as an IRS Form W-8BEN-E). Foreign financial institutions located in jurisdictions that have an intergovernmental agreement with the United States governing these rules may be subject to different rules. Under certain circumstances, a holder might be eligible for refunds or credits of such taxes. Non-U.S. holders are encouraged to consult their own tax advisors regarding the effects of FATCA on an investment in our Class A shares.
Available Information
We make available, free of charge on our Internet website at ir.pagp.com, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after we electronically file the material with, or furnish it to, the Securities and Exchange Commission (“SEC”). The SEC maintains an Internet site that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC at http://www.sec.gov. Our website includes a significant amount of information about us, including financial and other information that could be deemed material to investors. Investors and others are encouraged to review such information. The information posted on our website is not incorporated by reference into this Annual Report on Form 10-K or any of our other filings with the SEC.

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ITEM 1A. RISK FACTORS
Item 1A. Risk Factors
References to the “PAGP Entities” include PAGP GP, PAGP, GP LLC, AAP and PAA GP LLC (“PAA GP”). References to the “Plains Entities” include the PAGP Entities and PAA and its subsidiaries.
Summary of Risk Factors
Risks Inherent in an Investment in Us
Our partnership structure carries inherent risks, including but not limited to:
•our cash flow will be entirely dependent upon the ability of PAA to make cash distributions to AAP, and the ability of AAP to make cash distributions to us;
•the distributions AAP is entitled to receive may fluctuate, which may reduce cash distributions to our Class A shareholders;
•if distributions on our Class A shares are not paid with respect to any fiscal quarter, our Class A shareholders will not be entitled to receive that quarter’s payments in the future;
•the amount of cash that we and PAA distribute each quarter may limit our ability to grow;
•the Class B shareholders own a significant number of shares, which may make the removal of our general partner difficult; and
•Our general partner may cause us to issue additional Class A shares or other equity securities, including equity securities that are senior to our Class A shares, or cause AAP to issue additional securities, in each case without shareholder approval, which may adversely affect our shareholders.
Risks Related to Conflicts of Interest
Our existing organizational structure and the relationships among us, PAA, our respective general partners, the Legacy Owners and affiliated entities present the potential for conflicts of interest. Moreover, additional conflicts of interest may arise in the future among us and the entities affiliated with any general partner or similar interests we acquire or among PAA and such entities.
Risks Related to PAA’s Business
PAA’s business, results of operations, financial condition, cash flows and unit price can be adversely affected by many factors including but not limited to:
•the volume of crude oil, natural gas and NGL shipped, processed, purchased, stored, fractionated and/or gathered at or through the use of PAA’s facilities, which can be negatively impacted by a variety of factors outside of its control;
•pandemics, epidemics or other public health emergencies, such as the recent COVID-19 pandemic;
•competition in PAA’s industry, including recontracting and other risks associated with the general capacity overbuild of midstream energy infrastructure in some of the areas where PAA operates;
•fluctuations in supply and demand, which can be caused by a variety of factors outside of PAA’s control;
•natural disasters, catastrophes, terrorist attacks (including eco-terrorist attacks), process safety failures or other events, including pipeline or facility accidents and cyber or other attacks on PAA’s electronic and computer systems, could interrupt its operations and/or result in severe personal injury, property damage and environmental damage;
•cybersecurity breaches and other disruptions could compromise PAA’s information and operations, and expose it to liability;
•societal and political pressures, including opposition to the development or operation of PAA’s pipelines and facilities from various groups;
•the overall forward market for crude oil and NGL, and certain market structures, the absence of pricing volatility and other market factors;
•an inability to fully implement or realize expected returns or other anticipated benefits associated with joint venture and joint ownership arrangements, divestitures, acquisitions and other projects;
•loss of PAA’s investment grade credit rating or the ability to receive open credit;
•the credit risk of PAA’s customers and other counterparties it transacts with in the ordinary course of business activities;
•tightened capital markets or other factors that increase PAA’s cost of capital or otherwise limit its access to capital;
•the insufficiency of, or non-compliance with, PAA’s risk policies;
•PAA’s insurance coverage may not fully cover its losses and it may in the future encounter increased costs related to, and lack of availability of, insurance;
•PAA’s current or future debt levels, or inability to borrow additional funds or capitalize on business opportunities;
•changes in currency exchange rates;
•difficulties recruiting and retaining PAA’s workforce;
•an impairment of long-term assets;
•significant under-utilization of certain assets due to fixed costs incurred to obtain the right to use such assets;
•many of PAA’s assets have been in service for many years and require significant expenditures to maintain them. As a result, PAA’s maintenance or repair costs may increase in the future;
•PAA does not own all of the land on which its pipelines and facilities are located, which could result in disruptions to its operations;
•PAA’s inability to perform all of its obligations under our contracts, which could lead to increased costs; and
•failure to obtain materials or commodities in the quantity and the quality PAA needs, and at commercially acceptable prices, whether due to supply disruptions, tariffs, quotas or other factors.
Risks Related to Laws and Regulations Impacting PAA’s Business
PAA’s business may be adversely impacted by existing or new laws, executive orders and regulations relating to protection of the environment and wildlife, operational safety, cross-border import/export and tax matters, financial and hedging activities, climate change and related matters.
Risks Inherent in an Investment in PAA
PAA’s partnership structure carries inherent risks, including but not limited to:
•cost reimbursements due to PAA’s general partner may be substantial and will reduce PAA’s cash available for distribution to its unitholders;
•cash distributions are not guaranteed and may fluctuate with PAA’s performance and the establishment of financial reserves; and
•PAA’s preferred units have rights, preferences and privileges that are not held by, and are preferential to the rights of, holders of PAA’s common units.
Tax Risks
Our shares are subject to tax risks, which may adversely impact the value of or market for our shares and may reduce our cash available for distribution or debt service, including but not limited to:
•the tax treatment of PAA depends on its status as a partnership for U.S. federal income tax purposes, and it not being subject to a material amount of entity-level taxation. The cash available for distribution to us from PAA may be substantially reduced if PAA were to become subject to entity-level taxation as a result of the Internal Revenue Service (“IRS”) treating PAA as a corporation or legislative, judicial or administrative changes, and may also be reduced by any audit adjustments if imposed directly on PAA. Additionally, the treatment of PAA as a corporation would increase the portion of our distributions treated as taxable dividends; and
•our current tax treatment may change, which could affect the value of our Class A shares or reduce our cash available for distribution, and any decrease in our Class A share price could adversely affect our amount of cash available for distribution.
Risks Inherent in an Investment in Us
Our cash flow will be entirely dependent upon the ability of PAA to make cash distributions to AAP, and the ability of AAP to make cash distributions to us.
The source of our earnings and cash flow currently consists exclusively of cash distributions from AAP, which currently consist exclusively of cash distributions from PAA. The amount of cash that PAA will be able to distribute to its partners, including AAP, each quarter principally depends upon the amount of cash it generates from its business. For a description of certain factors that can cause fluctuations in the amount of cash that PAA generates from its business, please read “-Risks Related to PAA’s Business”, “-Risks Related to Laws and Regulations Impacting PAA’s Business”, “-Risks Inherent in an Investment in PAA” and Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” PAA may not have sufficient available cash each quarter to continue paying distributions at its current level or at all. If PAA reduces its per unit distribution, either because of reduced operating cash flow, higher expenses, capital requirements or otherwise, we will have less cash available for distribution and would likely be required to reduce our per share distribution. The amount of cash PAA has available for distribution depends primarily upon PAA’s cash flow, including cash flow from the release of financial reserves as well as borrowings, and is not solely a function of profitability, which will be affected by non-cash items. As a result, PAA may make cash distributions during periods when it records losses and may not make cash distributions during periods when it records profits.
Furthermore, AAP’s ability to distribute cash to us and our ability to distribute cash received from AAP to our Class A shareholders is limited by a number of factors, including:
•our payment of any income taxes;
•restrictions on distributions contained in PAA’s credit facilities and any future debt agreements entered into by AAP, PAA or us; and
•reserves our general partner establishes for the proper conduct of our business, to comply with applicable law or any agreement binding on us or our subsidiaries (exclusive of PAA and its subsidiaries), which reserves are not subject to a limit pursuant to our partnership agreement.
A material increase in amounts paid or reserved with respect to any of these factors could restrict our ability to pay quarterly distributions to our Class A shareholders.
The distributions AAP is entitled to receive may fluctuate, which may reduce cash distributions to our Class A shareholders.
At December 31, 2020, we directly and indirectly owned an approximate 79% limited partner interest in AAP, which owned approximately 245.8 million PAA common units. All of the cash flow we receive from AAP is derived from its ownership of these PAA common units. Because distributions on PAA common units are dependent on the amount of cash PAA generates, distributions may fluctuate based on PAA’s performance. The actual amount of cash that is available to be distributed each quarter will depend on numerous factors, some of which are beyond our control and the control of PAA. Cash distributions are dependent primarily on cash flow, including cash flow from financial reserves and working capital borrowings, and not solely on profitability, which is affected by non-cash items. Therefore, PAA’s cash distributions might be made during periods when PAA records losses and might not be made during periods when PAA record profits.
If distributions on our Class A shares are not paid with respect to any fiscal quarter, our Class A shareholders will not be entitled to receive that quarter’s payments in the future.
Our distributions to our Class A shareholders are not cumulative. Consequently, if distributions on our Class A shares are not paid with respect to any fiscal quarter, our Class A shareholders will not be entitled to receive that quarter’s payments in the future.
The amount of cash that we and PAA distribute each quarter may limit our ability to grow.
Because we distribute all of our available cash, our growth may not be as fast as the growth of businesses that reinvest their available cash to expand ongoing operations. In fact, because currently our cash flow is generated solely from distributions we receive from AAP, which are derived from AAP’s partnership interests in PAA, our growth will initially be completely dependent upon PAA. The amount of distributions received by AAP is based on PAA’s per unit distribution paid on each PAA common unit and the number of PAA common units that AAP owns. If we issue additional Class A shares or we were to incur debt or are required to pay taxes, the payment of distributions on those additional Class A shares, or interest on such debt or payment of such taxes could increase the risk that we will be unable to maintain or increase our cash distribution levels.
Restrictions in PAA’s credit facilities could limit AAP’s ability to make distributions to us, thereby limiting our ability to make distributions to our Class A shareholders.
PAA’s credit facilities contain various operating and financial restrictions and covenants. PAA’s ability to comply with these restrictions and covenants may be affected by events beyond its control, including prevailing economic, financial and industry conditions. If PAA is unable to comply with these restrictions and covenants, any indebtedness under these credit facilities may become immediately due and payable and PAA’s lenders’ commitment to make further loans under these credit facilities may terminate. PAA might not have, or be able to obtain, sufficient funds to make these accelerated payments.
For more information regarding PAA’s credit facilities, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Liquidity and Capital Resources.” For information regarding risks related to PAA’s credit facilities, please see “-Risks Related to PAA’s Business-The terms of PAA’s indebtedness may limit its ability to borrow additional funds or capitalize on business opportunities. In addition, PAA’s future debt level may limit its future financial and operating flexibility.”
The Class B shareholders own a significant number of shares, which may make the removal of our general partner difficult.
Our shareholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. If our Class A shareholders are dissatisfied with the performance of our general partner, they may be unable to remove our general partner. Our general partner may only be removed by vote of the holders of at least 66 2/3% of our outstanding shares (including both Class A and Class B shares). At December 31, 2020, the Legacy Owners owned approximately 21% of our outstanding Class A and Class B shares. This ownership level may make it difficult for our Class A shareholders to remove our general partner without the support of the Legacy Owners.
As a result of these provisions, the price at which our shares trade may be lower because of the absence or reduction of a takeover premium in the trading price.
Our general partner may cause us to issue additional Class A shares or other equity securities, including equity securities that are senior to our Class A shares, or cause AAP to issue additional securities, in each case without shareholder approval, which may adversely affect our shareholders.
Our general partner may cause us to issue an unlimited number of additional Class A shares or other equity securities of equal rank with the Class A shares, or cause AAP to issue additional securities, in each case without shareholder approval. In addition, we may issue an unlimited number of shares that are senior to our Class A shares in right of distribution, liquidation and voting. Except for Class A shares issued in connection with the exercise of an Exchange Right, which will result in the cancellation of an equivalent number of Class B shares and therefore have no effect on the total number of outstanding shares, the issuance of additional Class A shares or our other equity securities of equal or senior rank, or the issuance by AAP of additional securities, will have the following effects:
•each shareholder’s proportionate ownership interest in us may decrease;
•the amount of cash available for distribution on each Class A share may decrease;
•the relative voting strength of each previously outstanding Class A share may be diminished;
•the ratio of taxable income to distributions may increase; and
•the market price of the Class A shares may decline.
If PAA’s unitholders remove PAA GP, AAP may be required to sell or exchange its indirect general partner interest and we would lose the ability to manage and control PAA.
We currently manage our investment in PAA through our membership interest in GP LLC, the general partner of AAP. PAA’s partnership agreement, however, gives unitholders of PAA the right to remove PAA GP upon the affirmative vote of holders of 66 2/3% of PAA’s outstanding units. If PAA GP withdraws as general partner in compliance with PAA’s partnership agreement or is removed as general partner of PAA where cause (as defined in PAA’s partnership agreement) does not exist and a successor general partner is elected in accordance with PAA’s partnership agreement, AAP will receive cash in exchange for its general partner interest. If PAA GP withdraws in circumstances other than those described in the preceding sentence and a successor general partner is elected in accordance with PAA’s partnership agreement, the successor general partner will purchase the general partner interest for its fair market value. If PAA GP’s interests are not purchased in accordance with the foregoing theory, they would be converted into common units based on an independent valuation. In each case, PAA GP would also lose its ability to manage PAA.
In addition, if PAA GP is removed as general partner of PAA, we would face an increased risk of being deemed an investment company. Please read “-If in the future we cease to manage and control PAA, we may be deemed to be an investment company under the Investment Company Act of 1940.”
Shareholders may not have limited liability if a court finds that shareholder action constitutes control of our business.
Under Delaware law, our shareholders could be held liable for our obligations to the same extent as a general partner if a court determined that the right or the exercise of the right by our shareholders as a group to remove or replace our general partner, to approve some amendments to the partnership agreement or to take other action under our partnership agreement constituted participation in the “control” of our business. Additionally, the limitations on the liability of holders of limited partner interests for the liabilities of a limited partnership have not been clearly established in many jurisdictions.
Furthermore, Section 17-607 of the Delaware Revised Uniform Limited Partnership Act provides that, under some circumstances, a shareholder may be liable to us for the amount of a distribution for a period of three years from the date of the distribution.
If in the future we cease to manage and control PAA, we may be deemed to be an investment company under the Investment Company Act of 1940.
If we cease to indirectly manage and control PAA and are deemed to be an investment company under the Investment Company Act of 1940, we would either have to register as an investment company under the Investment Company Act of 1940, obtain exemptive relief from the SEC or modify our organizational structure or our contractual rights to fall outside the definition of an investment company. Registering as an investment company could, among other things, materially limit our ability to engage in transactions with affiliates, including the purchase and sale of certain securities or other property to or from our affiliates, restrict the ability of PAA and us to borrow funds or engage in other transactions involving leverage, require us to add additional directors who are independent of us and our affiliates, and adversely affect the price of our Class A shares.
Our partnership agreement restricts the rights of shareholders owning 20% or more of our shares.
Our shareholders’ voting rights are restricted by the provision in our partnership agreement generally providing that any shares held by a person or group that owns 20% or more of any class of shares then outstanding, other than our general partner, the Legacy Owners (or certain transferees in private, non-exchange transactions), their respective affiliates and persons who acquired such shares with the prior approval of our general partner’s board of directors, cannot be voted on any matter, except that such shares constituting up to 19.9% of the total shares outstanding may be voted in the election of directors. In addition, our partnership agreement contains provisions limiting the ability of our shareholders to call meetings or to acquire information about our operations, as well as other provisions limiting our shareholders’ ability to influence the manner or direction of our management. As a result, the price at which our Class A shares will trade may be lower because of the absence or reduction of a takeover premium in the trading price.
If PAA’s general partner, which is owned by AAP, is not fully reimbursed or indemnified for obligations and liabilities it incurs in managing the business and affairs of PAA, its value, and, therefore, the value of our Class A shares, could decline.
AAP, GP LLC and their affiliates may make expenditures on behalf of PAA for which PAA GP will seek reimbursement from PAA. Under Delaware partnership law, PAA GP has unlimited liability for the obligations of PAA, such as its debts and environmental liabilities, except for those contractual obligations of PAA that are expressly made without recourse to the general partner. To the extent PAA GP incurs obligations on behalf of PAA, it is entitled to be reimbursed or indemnified by PAA. If PAA is unable or unwilling to reimburse or indemnify PAA GP, PAA GP may be required to satisfy those liabilities or obligations, which would reduce AAP’s cash flows to us.
The price of our Class A shares may be volatile, and holders of our Class A shares could lose a significant portion of their investments.
The market price of our Class A shares could be volatile, and our shareholders may not be able to resell their Class A shares at or above the price at which they purchased such Class A shares due to fluctuations in the market price of the Class A shares, including changes in price caused by factors unrelated to our operating performance or prospects or the operating performance or prospects of PAA. The following factors, among others, could affect our Class A share price:
•PAA’s operating and financial performance and prospects and the trading price of its common units;
•the level of PAA’s quarterly distributions and our quarterly distributions;
•quarterly variations in the rate of growth of our financial indicators, such as distributable cash flow per Class A share, net income and revenues;
•changes in revenue or earnings and distribution estimates or publication of research reports by analysts;
•speculation by the press or investment community;
•sales of our Class A shares by our shareholders;
•the exercise by the Legacy Owners of their exchange rights with respect to any retained AAP units;
•announcements by PAA or its competitors of significant contracts, acquisitions, strategic partnerships, joint ventures, securities offerings or capital commitments;
•general market conditions, including conditions in financial markets;
•changes in accounting standards, policies, guidance, interpretations or principles;
•adverse changes in tax laws or regulations;
•domestic and international economic, legal and regulatory factors related to PAA’s performance; and
•other factors described in these “Risk Factors.”
An increase in interest rates may cause the market price of our shares to decline.
Like all equity investments, an investment in our Class A shares is subject to certain risks. In exchange for accepting these risks, investors may expect to receive a higher rate of return than would otherwise be obtainable from lower-risk investments. Accordingly, as interest rates rise, the ability of investors to obtain higher risk-adjusted rates of return by purchasing government-backed debt securities may cause a corresponding decline in demand for riskier investments generally, including yield-based equity investments such as publicly traded limited partnership interests. Reduced demand for our Class A shares resulting from investors seeking other more favorable investment opportunities may cause the trading price of our Class A shares to decline.
Future sales of our Class A shares in the public market could reduce our Class A share price, and any additional capital raised by us through the sale of equity or convertible securities may have a dilutive effect on our shareholders.
Subject to certain limitations and exceptions, holders of AAP units may exchange their AAP units (together with a corresponding number of Class B shares) for Class A shares (on a one-for-one basis, subject to customary conversion rate adjustments for equity splits and reclassification and other similar transactions) and then sell those Class A shares. We may also issue additional Class A shares or convertible securities in subsequent public or private offerings.
We cannot predict the size of future issuances of our Class A shares or securities convertible into Class A shares or the effect, if any, that future issuances and sales of our Class A shares will have on the market price of our Class A shares. Sales of substantial amounts of our Class A shares (including shares issued in connection with an acquisition), or the perception that such sales could occur, may adversely affect prevailing market prices of our Class A shares.
The Legacy Owners hold a significant portion of the combined voting power of our Class A and Class B shares.
At December 31, 2020, through their ownership of Class B shares, the Legacy Owners held approximately 21% of the combined voting power of our Class A and Class B shares. The Legacy Owners are entitled to act separately in their own respective interests with respect to their partnership interests in us, and collectively they currently have the ability to influence (i) the outcome of all matters requiring shareholder approval, including certain mergers and other material transactions and (ii) a change in the composition of our board of directors or a change in control of our company that could deprive our shareholders of an opportunity to receive a premium for their Class A shares as part of a sale of our company. So long as the Legacy Owners continue to own a significant amount of our outstanding shares, even if such amount is less than 50%, they will continue to be able to strongly influence all matters requiring shareholder approval, regardless of whether or not other shareholders believe that such matters are in their own best interests.
A valuation allowance on our deferred tax asset could reduce our earnings.
As of December 31, 2020, we had a gross deferred tax asset of approximately $1.5 billion. Generally accepted accounting principles in the United States (“GAAP”) requires that a valuation allowance must be established for deferred tax assets when it is more likely than not that they will not be realized. We believe that the deferred tax asset we recorded through 2020 will be realized and that a valuation allowance is not required. However, if we were to determine that a valuation allowance was appropriate for our deferred tax asset, we would be required to take an immediate charge to earnings with a corresponding reduction of partners’ capital and increase in balance sheet leverage as measured by debt-to-total capitalization. In light of the Tax Cuts and Jobs Act of 2017, a valuation allowance will not be required for any U.S. federal deferred tax asset created after 2017.
We may incur liability as a result of our ownership of our and PAA’s general partner.
Under Delaware law, a general partner of a limited partnership is generally liable for the debts and liabilities of the partnership for which it serves as general partner, subject to the terms of any indemnification agreements contained in the partnership agreement and except to the extent the partnership’s contracts are non-recourse to the general partner. As a result of our structure, we indirectly own and control the general partner of PAA and own a portion of our general partner’s membership interests. Our percentage ownership of our general partner is expected to increase over time as the Legacy Owners exercise their exchange rights. To the extent the indemnification provisions in the applicable partnership agreement or non-recourse provisions in our contracts are not sufficient to protect us from such liability, we may in the future incur liabilities as a result of our ownership of these general partner entities.
Risks Related to Conflicts of Interest
Our existing organizational structure and the relationships among us, PAA, our respective general partners, the Legacy Owners and affiliated entities present the potential for conflicts of interest. Moreover, additional conflicts of interest may arise in the future among us and the entities affiliated with any general partner or similar interests we acquire or among PAA and such entities.
Conflicts of interest may arise as a result of our organizational structure and the relationships among us, PAA, our respective general partners, the Legacy Owners and affiliated entities.
Our partnership agreement defines the duties of our general partner (and, by extension, its officers and directors). Our general partner’s board of directors or its conflicts committee will have authority on our behalf to resolve any conflict involving us and they have broad latitude to consider the interests of all parties to the conflict.
Conflicts of interest may arise between us and our shareholders, on the one hand, and our general partner and its owners and affiliated entities, on the other hand, or between us and our shareholders, on the one hand, and PAA and its unitholders, on the other hand. The resolution of these conflicts may not always be in our best interest or that of our shareholders.
Our partnership agreement defines our general partner’s duties to us and contains provisions that reduce the remedies available to our shareholders for actions that might otherwise be challenged as breaches of fiduciary or other duties under state law.
Our partnership agreement contains provisions that substantially reduce the standards to which our general partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement:
•permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, the Legacy Owners, our affiliates or any limited partner. Examples include its right to vote membership interests in our general partner held by us, the exercise of its limited call right, its rights to transfer or vote any shares it may own, and its determination whether or not to consent to any merger or consolidation of our partnership or amendment to our partnership agreement;
•generally provides that our general partner will not have any liability to us or our shareholders for decisions made in its capacity as a general partner so long as it acted in good faith which, pursuant to our partnership agreement, requires a subjective belief that the determination, or other action or anticipated result thereof is in, or not opposed to, our best interests;
•generally provides that any resolution or course of action adopted by our general partner and its affiliates in respect of a conflict of interest will be permitted and deemed approved by all of our partners, and will not constitute a breach of our partnership agreement or any duty stated or implied by law or equity if the resolution or course of action in respect of such conflict of interest is:
◦approved by a majority of the members of our general partner’s conflicts committee after due inquiry, based on a subjective belief that the course of action or determination that is the subject of such approval is fair and reasonable to us;
◦approved by majority vote of our Class A shares and Class B shares (excluding Class C shares and excluding shares owned by our general partner and its affiliates, but including shares owned by the Legacy Owners) voting together as a single class;
◦ determined by our general partner (after due inquiry) to be on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or
◦ determined by our general partner (after due inquiry) to be fair and reasonable to us, which determination may be made taking into account the circumstances and the relationships among the parties involved (including our short-term or long-term interests and other arrangements or relationships that could be considered favorable or advantageous to us).
•provides that, to the fullest extent permitted by law, in connection with any action or inaction of, or determination made by, our general partner or the conflicts committee of our general partner’s board of directors with respect to any matter relating to us, it shall be presumed that our general partner or the conflicts committee of our general partner’s board of directors acted in a manner that satisfied the contractual standards set forth in our partnership agreement, and in any proceeding brought by any limited partner or by or on behalf of such limited partner or any other limited partner or our partnership challenging any such action or inaction of, or determination made by, our general partner, the person bringing or prosecuting such proceeding shall have the burden of overcoming such presumption; and
•provides that our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or assignees for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or those other persons acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that such person’s conduct was criminal.
The Legacy Owners may have interests that conflict with holders of our Class A shares.
At December 31, 2020, the Legacy Owners owned approximately 21% of our outstanding Class A and Class B shares and approximately 21% of the AAP units. As a result, the Legacy Owners may have conflicting interests with holders of Class A shares. For example, the Legacy Owners may have different tax positions from us which could influence their decisions regarding whether and when to cause us to dispose of assets.
Furthermore, conflicts of interest could arise in the future between us, on the one hand, and the Legacy Owners, on the other hand, concerning among other things, potential competitive business activities or business opportunities. These conflicts of interest may not be resolved in our favor.
If we are presented with business opportunities, PAA has the first right to pursue such opportunities.
Pursuant to the administrative agreement, we have agreed to certain business opportunity arrangements to address potential conflicts with respect to business opportunities that may arise among us, our general partner, PAA, PAA GP, AAP and GP LLC. If a business opportunity is presented to us, our general partner, PAA, PAA GP, AAP or GP LLC, then PAA will have the first right to pursue such business opportunity. We have the right to pursue and/or participate in such business opportunity if invited to do so by PAA, or if PAA abandons the business opportunity and GP LLC so notifies our general partner. Accordingly, the terms of the administrative agreement limit our ability to pursue business opportunities.
Our general partner’s affiliates and the Legacy Owners may compete with us.
Our partnership agreement provides that our general partner will be restricted from engaging in any business activities other than acting as our general partner and those activities incidental to its ownership of interests in us. The restrictions contained in our general partner’s limited liability company agreement are subject to a number of exceptions. Affiliates of our general partner and the Legacy Owners will not be prohibited from engaging in other businesses or activities that might be in direct competition with us except to the extent they compete using our confidential information.
Our general partner has a call right that may require our shareholders to sell their Class A shares at an undesirable time or price.
If at any time more than 80% of our outstanding Class A shares and Class B shares on a combined basis (including Class A shares issuable upon the exchange of Class B shares) are owned by our general partner, the Legacy Owners (or certain transferees in private, non-exchange transactions) or their respective affiliates, our general partner will have the right (which it may assign to any of its affiliates, the Legacy Owners or us), but not the obligation, to acquire all, but not less than all, of the remaining Class A shares held by public shareholders at a price equal to the greater of (x) the current market price of such shares as of the date three days before notice of exercise of the call right is first mailed and (y) the highest price paid by our general partner, the Legacy Owners (or certain transferees in private, non-exchange transactions) or their respective affiliates for such shares during the 90 day period preceding the date such notice is first mailed. As a result, holders of our Class A shares may be required to sell such Class A shares at an undesirable time or price and may not receive any return of or on their investment. Class A shareholders may also incur a tax liability upon a sale of their Class A shares. At December 31, 2020, the Legacy Owners owned approximately 21% of the Class A shares and Class B shares on a combined basis.
Risks Related to PAA’s Business
PAA’s profitability depends on the volume of crude oil, natural gas and NGL shipped, processed, purchased, stored, fractionated and/or gathered at or through the use of its facilities, which can be negatively impacted by a variety of factors outside of its control.
Drilling activity, crude oil production and benchmark crude oil prices can fluctuate significantly over time. For example, the current COVID-19 pandemic has resulted in a swift and material decline in global crude oil demand and crude oil prices, which has led to a significant reduction of domestic crude oil, NGL and natural gas production, and it is unclear if or when global demand will recover to pre-pandemic levels. This has had an adverse effect on the demand for the midstream services PAA offers and the commercial opportunities that are available to it. If demand remains depressed or declines further it is likely to have an adverse impact on PAA’s financial performance. A turnaround of these adverse macroeconomic factors depends largely on an increase in global demand for crude oil, which will be driven primarily by the extent to which consumer demand and demand for crude oil rebound following the pandemic.
Crude oil prices may also decline due to actions of domestic or foreign oil producers-they may take actions that create an over-supply of crude oil, and decrease benchmark crude oil prices. If producers reduce drilling activity in response to future declines in such prices, reduced capital market access, increased capital raising costs for producers or adverse governmental or regulatory action, it could adversely impact production. In turn, such developments could lead to reduced throughput on PAA’s pipelines and at its other facilities, which, depending on the level of production declines, could have a material adverse effect on PAA’s business.
Also, except with respect to some of PAA’s recently constructed long haul pipeline assets, third-party shippers generally do not have long-term contractual commitments to ship crude oil on PAA’s pipelines. A decision by a shipper to substantially reduce or cease to ship volumes of crude oil on PAA’s pipelines could cause a significant decline in its revenues.
To maintain the volumes of crude oil PAA purchases in connection with its operations, PAA must continue to contract for new supplies of crude oil to offset volumes lost because of reduced drilling activity by producers, natural declines in crude oil production from depleting wells or volumes lost to competitors. If production declines, competitors with under-utilized assets could impair PAA’s ability to secure additional supplies of crude oil.
PAA’s business, results of operations, financial condition, cash flows and unit price can be adversely affected by pandemics, epidemics or other public health emergencies, such as the current COVID-19 pandemic.
PAA’s business, results of operations, financial condition, cash flows and unit price can be adversely affected by pandemics, epidemics or other public health emergencies. The current COVID-19 pandemic has caused widespread economic disruption, and resulted in material reductions in demand for crude oil, NGL and other petroleum products, which in turn has resulted 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 many of PAA’s assets. Future pandemics, epidemics or other public health emergencies may have greater economic impacts.
As a result of the COVID-19 pandemic, many of PAA’s support functions are operating remotely, which presents technical and communication challenges, including increased vulnerability to cybersecurity breaches, risk management oversights or delays in, or disruptions to, communications. In addition, pandemic-related restrictions may adversely impact PAA’s ability to operate and maintain its assets, and may adversely impact the supply chain to source goods and services required for its operating activities.
The long term impacts of the COVID-19 pandemic remain highly uncertain and depend on a wide variety of factors that are outside of PAA’s control, including the development, deployment and effectiveness of vaccines, treatments and testing protocols; mutations of the virus resulting in increased transmissibility or severity of the disease or decreasing the effectiveness of vaccines or treatments; the capacity of our healthcare systems and public health infrastructure to manage current and future outbreaks; and various political and economic considerations. It is unknown whether consumption of petroleum products will return to pre-COVID levels due to changes in consumer habits or preferences. As a result, PAA is unable to predict the timing of any such market recovery, including a return to market conditions that are more conducive to an increase in drilling and production activities in the United States and Canada.
PAA’s profitability can be negatively affected by a variety of factors stemming from competition in its industry, including risks associated with the general capacity overbuild of midstream energy infrastructure in some of the areas where it operates.
PAA faces competition in all aspects of its business and can give no assurances that it will be able to compete effectively against its competitors. In general, competition comes from a wide variety of participants in a wide variety of contexts, including new entrants and existing participants and in connection with day-to-day business, investment capital projects, acquisitions and joint venture activities. Some of PAA’s competitors have capital resources many times greater than PAA’s or control greater supplies of crude oil, natural gas or NGL. In addition, other competitors with significant excess capacity and high financial leverage may attempt to survive and compete by reducing transportation rates to levels approaching variable operating costs, without regard to whether they are generating an acceptable return on their investment. These competitive risks make it more difficult for PAA to attract new customers and expose PAA to increased contract renewal and customer retention risk with respect to its existing customers.
A significant driver of competition in some of the markets where PAA operates (including, for example, the Eagle Ford, Permian Basin, and Rockies/Bakken areas) stems from the rapid development of new midstream energy infrastructure capacity that was driven by the combination of (i) significant increases in oil and gas production and development in the applicable production areas, both actual and anticipated, (ii) relatively low barriers to entry and (iii) generally widespread access to relatively low cost capital. While this environment presented opportunities for PAA, many of these areas have become, or in the future may become, overbuilt, resulting in an excess of midstream energy infrastructure capacity. For example, several new pipeline projects have been placed in service or are currently under construction, and such projects have resulted in, and may contribute to future, excess takeaway capacity in certain areas where PAA operates. In addition, as an established participant in some markets, PAA also faces competition from aggressive new entrants to the market who are willing to provide services at a lower rate of return in order to establish relationships and gain a foothold in the market. In addition, PAA’s Supply and Logistics segment is a customer of its Transportation and Facilities segments (See Note 21 to our Consolidated Financial Statements for a discussion of operating segments). Competition that impacts PAA’s Supply and Logistics activities could result in a reduction in the use of its Transportation and Facilities assets by its Supply and Logistics segment. All of these competitive effects put downward pressure on PAA’s throughput and margins and, together with other adverse competitive effects, could have a significant adverse impact on PAA’s financial position, cash flows and ability to pay or increase distributions to its unitholders.
With respect to PAA’s crude oil activities, its competitors include other crude oil pipelines, the major integrated oil companies, their marketing affiliates, refiners, private equity-backed entities, and independent gatherers, brokers and marketers of widely varying sizes, financial resources and experience. PAA competes against these companies on the basis of many factors, including geographic proximity to production areas, market access, rates, terms of service, connection costs and other factors.
With respect to PAA’s natural gas storage operations, the principal elements of competition are rates, terms of service, supply and market access and flexibility of service. PAA’s natural gas storage facilities compete with several other storage providers, including regional storage facilities and utilities. Certain pipeline companies have existing storage facilities connected to their systems that compete with some of PAA’s facilities.
With regard to PAA’s NGL operations, it competes with large oil, natural gas and natural gas liquids companies that may, relative to PAA, have greater financial resources and access to supplies of natural gas and NGL. The principal elements of competition are rates, processing fees, geographic proximity to the natural gas or NGL mix, available processing and fractionation capacity, transportation alternatives and their associated costs, and access to end-user markets.
Fluctuations in supply and demand, which can be caused by a variety of factors outside of PAA’s control, can negatively affect its operating results.
Supply and demand for crude oil and other hydrocarbon products PAA handles is dependent upon a variety of factors, including price, current and future economic conditions, fuel conservation measures, alternative fuel adoption, governmental regulation, including climate change regulations, and technological advances in fuel economy and energy generation devices. For example, legislative, regulatory or executive actions intended to reduce emissions of greenhouse gases could increase the cost of consuming crude oil and other hydrocarbon products, thereby causing a reduction in the demand for such products. Given that crude oil and petroleum products are global commodities, demand can also be significantly influenced by developments in other countries and markets, particularly in key consumption markets like China. Ultimately, this can lead to a reduction in demand for the services PAA provides. Demand also depends on the ability and willingness of shippers having access to PAA’s transportation assets to satisfy their demand by deliveries through those assets. The supply of crude oil depends on a variety of global political and economic factors, including the reliance of foreign governments on petroleum revenues. Excess global supply of crude oil may negatively impact PAA’s operating results by decreasing the price of crude oil and making production and transportation less profitable in areas PAA services.
Fluctuations in demand for crude oil, such as those caused by refinery downtime or shutdowns, can have a negative effect on PAA’s operating results. Specifically, reduced demand in an area serviced by PAA’s transportation systems will negatively affect the throughput on such systems. Although the negative impact may be mitigated or overcome by PAA’s ability to capture differentials created by demand fluctuations, this ability is dependent on location and grade of crude oil, and thus is unpredictable.
Fluctuations in demand for NGL products, whether because of general or industry specific economic conditions, new government regulations, global competition, reduced demand by consumers for products made with NGL products, increased competition from petroleum-based feedstocks due to pricing differences, mild winter weather for some NGL products, particularly propane, or other reasons, could result in a decline in the volume of NGL products PAA handles or a reduction of the fees it charges for its services. Also, increased supply of NGL products could reduce the value of NGL PAA handles and reduce the margins realized by it.
NGL and products produced from NGL also compete with products from global markets. Any reduced demand or increased supply for ethane, propane, normal butane, iso-butane or natural gasoline in the markets PAA accesses for any of the reasons stated above could adversely affect demand for the services PAA provides as well as NGL prices, which could negatively impact its operating results.
Natural disasters, catastrophes, terrorist attacks (including eco-terrorist attacks), process safety failures or other events, including pipeline or facility accidents and cyber or other attacks on PAA’s electronic and computer systems, could interrupt its operations and/or result in severe personal injury, property damage and environmental damage, which could have a material adverse effect on its financial position, results of operations and cash flows.
Some of PAA’s operations involve risks of personal injury, property damage and environmental damage that could curtail its operations and otherwise materially adversely affect its cash flow. Virtually all of PAA’s operations are exposed to potential natural disasters or other natural events, including hurricanes, tornadoes, storms, floods, earthquakes, shifting soil and/or landslides. The location of some of PAA’s assets and its customers’ assets in the U.S. Gulf Coast region makes them particularly vulnerable to hurricane or tropical storm risk. PAA’s facilities and operations are also vulnerable to accidents caused by process safety failures, equipment failures, or human error. In addition, since the September 11, 2001 terrorist attacks, the U.S. government has issued warnings that energy assets, specifically the nation’s pipeline infrastructure, may be future targets of terrorist organizations. Terrorists may target PAA’s physical facilities and hackers may attack its electronic and computer systems.
If one or more of PAA’s pipelines or other facilities, including electronic and computer systems, or any facilities or businesses that deliver products, supplies or services to PAA or that it relies on in order to operate its business, are damaged by severe weather or any other disaster, accident, catastrophe, terrorist attack or event, its operations could be significantly interrupted. In addition, PAA’s supply and logistics operations include purchasing crude oil and NGL that is carried on railcars, tankers or barges. Such cargos are at risk of being damaged or lost because of events such as derailment, marine disaster, inclement weather, mechanical failures, grounding or collision, fire, explosion, environmental accidents, piracy, terrorism and political instability. These incidents or interruptions could involve significant damage or injury to people, property or the environment, and repairs could take from a week or less for minor incidents to six months or more for major interruptions. Any such event that interrupts the revenues generated by its operations, or which causes PAA to make significant expenditures not covered by insurance, could reduce its profitability, cash flows and its cash available for paying distributions to its partners and, accordingly, adversely affect its financial condition and the market price of its securities.
PAA may also suffer damage (including reputational damage) as a result of a disaster, accident, catastrophe, terrorist attack or other such event. The occurrence of such an event, or a series of such events, especially if one or more of them occurs in a highly populated or sensitive area, could negatively impact public perception of PAA’s operations and/or make it more difficult for PAA to obtain the approvals, permits, licenses or real property interests PAA needs in order to operate its assets or complete planned growth projects.
Cybersecurity breaches and other disruptions could compromise PAA’s information and operations, and expose it to liability, which would cause its business and reputation to suffer.
PAA is reliant on the continuous and uninterrupted operation of its information technology systems. User access of PAA’s sites and information technology systems are critical elements to its operations, as is cloud security and protection against cyber security incidents. In the ordinary course of its business, PAA collects and stores sensitive data in its data centers and on its networks, including intellectual property, proprietary business information, critical operating information and data, information regarding its customers, suppliers, royalty owners and business partners, and personally identifiable information of its employees. The secure processing, maintenance and transmission of this information is critical to PAA’s operations and business strategy. Despite PAA’s security measures, its information technology and infrastructure may be vulnerable to attacks by hackers or breached due to employee error, malfeasance or other disruptions. Any such breach could compromise PAA’s networks and the information stored there could be accessed, publicly disclosed, lost or stolen. Any such access, disclosure or other loss of information could result in legal claims or proceedings, liability under laws that protect the privacy of personal information, regulatory penalties for divulging shipper information, disruption of PAA’s operations, damage to its reputation, and loss of confidence in its services, which could adversely affect its business.
PAA’s information technology infrastructure is critical to the efficient operation of its business and essential to its ability to perform day-to-day operations. Potential risks to PAA’s IT systems include unauthorized attempts to extract business sensitive, confidential or personal information, denial of access extortion, corruption of information or disruption of business processes, or by inadvertent or intentional actions by PAA’s employees or vendors. Breaches in PAA’s information technology infrastructure or physical facilities, or other disruptions, could result in damage to its assets, safety incidents, damage to the environment, remediation costs, potential liability, regulatory enforcement, violation of privacy or securities laws and regulations or the loss of contracts, any of which could have a material adverse effect on its operations, financial position and results of operations.
PAA self-insures and thus does not carry insurance specifically for cybersecurity events; however, certain of PAA’s insurance policies may allow for coverage of associated damages resulting from such events. If PAA were to incur a significant liability for which it was not fully insured, or if PAA incurred costs in excess of reserves established for uninsured or self-insured risks, it could have a material adverse effect on PAA’s financial position, results of operations and cash flows.
PAA may face opposition to the development or operation of its pipelines and facilities from various groups and PAA’s business may be subject to societal and political pressures.
PAA may face opposition to the development or operation of its pipelines and facilities from environmental groups, landowners, tribal groups, local groups and other advocates. Such opposition could take many forms, including organized protests, attempts to block or sabotage PAA’s operations, intervention in regulatory or administrative proceedings involving its assets, or lawsuits or other actions designed to prevent, disrupt or delay the development or operation of PAA’s assets and business. For example, repairing PAA’s pipelines often involves securing consent from individual landowners to access their property; one or more landowners may resist PAA’s efforts to make needed repairs, which could lead to an interruption in the operation of the affected pipeline or other facility for a period of time that is significantly longer than would have otherwise been the case. In addition, acts of sabotage or eco-terrorism could cause significant damage or injury to people, property or the environment or lead to extended interruptions of PAA’s operations. Any such event that interrupts the revenues generated by PAA’s operations, or which causes PAA to make significant expenditures not covered by insurance, could reduce PAA’s cash available for paying distributions to its partners and, accordingly, adversely affect PAA’s financial condition and the market price of its securities.
PAA’s business plans are based upon the assumption that societal sentiment will continue to enable, and existing regulations will stay intact for, the future development, transportation and use of hydrocarbon-based fuels. Policy decisions relating to the production, refining, transportation and marketing of hydrocarbon-based fuels are subject to political pressures, the negative portrayal of the industry in which PAA operates by the media and others, and the influence and protests of environmental and other special interest groups. Such negative sentiment regarding the hydrocarbon energy industry could influence consumer preferences and government or regulatory actions, which could, in turn, have an adverse impact on PAA’s business.
Recently, activists concerned about the potential effects of climate change have directed their attention towards sources of funding for hydrocarbon energy companies, which has resulted in certain financial institutions, funds and other sources of capital restricting or eliminating their investment in energy-related activities. Ultimately, this could make it more difficult to secure funding for exploration and production activities or energy infrastructure related projects and ongoing operations, and consequently could both indirectly affect demand for PAA’s services and directly affect PAA’s ability to fund construction or other capital projects, as well as properly run its ongoing operations.
The results of PAA’s Supply and Logistics segment are influenced by the overall forward market for crude oil and NGL, and certain market structures, the absence of pricing volatility and other market factors may adversely impact its results.
Results from PAA’s Supply and Logistics segment are dependent on a variety of factors affecting the markets for crude oil and NGL, including regional and international supply and demand imbalances, takeaway availability and constraints, transportation costs and the overall forward market for crude oil. Periods when differentials are wide or when there is volatility in the forward market structure are generally more favorable for PAA’s Supply and Logistics segment. During periods where the infrastructure is over-built and/or there is a lack of volatility in the pricing structure PAA’s results may be negatively impacted. Depending on the overall duration of these transition periods, how PAA has allocated its assets to particular strategies and the time length of its crude oil purchase and sale contracts and storage agreements, these periods may have either an adverse or beneficial effect on PAA’s aggregate segment results. In the past, the results from PAA’s Supply and Logistics segment have varied significantly based on market conditions and this segment may continue to experience highly variable results as a result of future changes to the markets for crude oil and NGL.
PAA may not be able to fully implement or realize expected returns or other anticipated benefits associated with joint venture and joint ownership arrangements, divestitures, acquisitions and other projects.
PAA is undertaking, or is participating with various counterparties in, a number of projects that involve the construction of new midstream energy infrastructure assets or the expansion, modification, divestiture or combination of existing assets. Many of these projects involve numerous regulatory, environmental, commercial, economic, weather-related, political and legal uncertainties that are beyond its control, including the following:
•PAA may construct pipelines, facilities or other assets in anticipation of market demand that dissipates or market growth that never materializes;
•Despite the fact that PAA will expend significant amounts of capital during the construction phase of growth or expansion projects, revenues associated with these organic growth projects will not materialize until the projects have been completed and placed into commercial service, and the amount of revenue generated from these projects could be significantly lower than anticipated for a variety of reasons;
•As these projects are undertaken, required approvals, permits and licenses may not be obtained, may be delayed, may be obtained with conditions that materially alter the expected return associated with the underlying projects or may be granted and then subsequently withdrawn;
•PAA may face opposition to its planned projects from environmental groups, landowners, local groups and other advocates, including lawsuits or other actions designed to disrupt or delay PAA’s planned projects;
•PAA may not be able to obtain, or PAA may be significantly delayed in obtaining, all of the rights of way or other real property interests it needs to complete such projects, or the costs PAA incurs in order to obtain such rights of way or other interests may be greater than PAA anticipated;
•Due to unavailability or costs of materials, supplies, power, labor or equipment, including increased costs associated with any import duties or requirements to source certain supplies or materials from U.S. suppliers or manufacturers, the cost of completing these projects could turn out to be significantly higher than PAA budgeted and the time it takes to complete construction of these projects and place them into commercial service could be significantly longer than planned; and
•The completion or success of PAA’s projects may depend on the completion or success of third-party facilities over which PAA has no control.
As a result of these uncertainties, the anticipated benefits associated with PAA’s planned projects may not be achieved or could be delayed. In turn, this could negatively impact PAA’s cash flow and its ability to make or increase cash distributions to its partners.
Loss of PAA’s investment grade credit rating or the ability to receive open credit could negatively affect its borrowing costs, ability to purchase crude oil, NGL and natural gas supplies or to capitalize on market opportunities.
PAA’s business is dependent on its ability to maintain an attractive credit rating and continue to receive open credit from its suppliers and trade counterparties. PAA’s senior unsecured debt is currently rated as “investment grade” by Standard & Poor’s and Fitch Ratings Inc. In August 2017, Moody’s Investors Service downgraded its rating of PAA’s senior unsecured debt to a level below investment grade. A further downgrade by any of such agencies to a level below PAA’s current ratings levels assigned by such rating agencies could increase its borrowing costs, reduce its borrowing capacity and cause its counterparties to reduce the amount of open credit it receives from them. This could negatively impact PAA’s ability to capitalize on market opportunities. For example, PAA’s ability to utilize its crude oil storage capacity for merchant activities to capture contango market opportunities is dependent upon having adequate credit facilities, both in terms of the total amount of credit facilities and the cost of such credit facilities, which enables PAA to finance the storage of the crude oil from the time it completes the purchase of the crude oil until the time it completes the sale of the crude oil. Loss of PAA’s remaining investment grade credit ratings could also adversely impact its cash flows, its ability to make distributions at its current levels and the value of its outstanding equity and debt securities.
PAA is exposed to the credit risk of its customers and other counterparties it transacts with in the ordinary course of its business activities.
Risks of nonpayment and nonperformance by customers or other counterparties are a significant consideration in PAA’s business, and the economic fallout of the COVID-19 pandemic has had an adverse impact on the creditworthiness of many companies in the energy sector. Although PAA has credit risk management policies and procedures that are designed to mitigate and limit its exposure in this area, there can be no assurance that PAA has adequately assessed and managed the creditworthiness of its existing or future counterparties or that there will not be an unanticipated deterioration in their creditworthiness or unexpected instances of nonpayment or nonperformance, all of which could have an adverse impact on PAA’s cash flow and its ability to pay or increase its cash distributions to its partners.
PAA has a number of minimum volume commitment contracts that support pipelines in its Transportation segment. In addition, certain of the pipelines in which PAA owns a joint venture interest have minimum volume commitment contracts. Pursuant to such contracts, shippers are obligated to pay for a minimum volume of transportation service regardless of whether such volume is actually shipped (typically referred to as a deficiency payment), subject to the receipt of credits that typically expire if not used by a certain date. While such contracts provide greater revenue certainty, if the applicable shipper fails to transport the minimum required volume and is required to make a deficiency payment, under applicable accounting rules, the revenue associated with such deficiency payment may not be recognized until the applicable transportation credit has expired or has been used. Deferred revenue associated with non-performance by shippers under minimum volume contracts could be significant and could adversely affect PAA’s profitability and earnings.
In addition, in those cases in which PAA provides division order services for crude oil purchased at the wellhead, it may be responsible for distribution of proceeds to all parties. In other cases, PAA pays all of or a portion of the production proceeds to an operator who distributes these proceeds to the various interest owners. These arrangements expose PAA to operator credit risk, and there can be no assurance that PAA will not experience losses in dealings with such operators and other parties.
Further, to the extent one or more of PAA’s major customers experiences financial distress or commences bankruptcy proceedings, contracts with such customers (including contracts that are supported by acreage dedications) may be subject to renegotiation or rejection under applicable provisions of the United States Bankruptcy Code. Any such renegotiation or rejection could have an adverse effect on PAA’s revenue and cash flows and its ability to make cash distributions to its unitholders.
PAA has also undertaken numerous projects that require cooperation with and performance by joint venture co-owners. In addition, in connection with various acquisition, divestiture, joint venture and other transactions, PAA often receives indemnifications from various parties for certain risks or liabilities. Nonperformance by any of these parties could result in increased costs or other adverse consequences that could decrease PAA’s earnings and returns.
PAA also relies to a significant degree on the banks that lend to it under its revolving credit facility for financial liquidity, and any failure of those banks to perform on their obligations to PAA could significantly impair its liquidity. Furthermore, nonpayment by the counterparties to PAA’s interest rate, commodity and/or foreign currency derivatives could expose it to additional interest rate, commodity price and/or foreign currency risk.
Divestitures, joint ventures, joint ownership arrangements and acquisitions involve risks that may adversely affect PAA’s business.
PAA’s ability to execute its financial strategy is in part dependent on its ability to complete strategic divestitures or sales of interests to strategic partners. If PAA is unable to successfully complete planned divestitures (due to reduced investment in the energy sector, governmental action, litigation, counterparty non-performance or other factors), it may be more difficult for PAA to achieve its desired leverage levels, increase returns to equity holders or otherwise accomplish its financial goals. In addition, in connection with its divestitures, PAA may agree to retain responsibility for certain liabilities that relate to PAA’s period of ownership, which could adversely impact its future financial performance.
PAA is also involved in many strategic joint ventures and other joint ownership arrangements. PAA may not always be in complete alignment with its joint venture or joint owner counterparties; PAA may have differing strategic or commercial objectives and may be outvoted by its joint venture partners or PAA may disagree on governance matters with respect to the joint venture entity or the jointly owned assets. When PAA enters into joint ventures or joint ownership arrangements it may be subject to the risk that its counterparties do not fund their obligations. In some joint ventures and joint ownership arrangements PAA may not be responsible for construction or operation of such projects and will rely on its joint venture or joint owner counterparties for such services. Joint ventures and joint ownership arrangements may also require PAA to expend additional internal resources that could otherwise be directed to other projects. If PAA is unable to successfully execute and manage its existing and proposed joint venture and joint owner projects, it could adversely impact PAA’s financial and operating results.
Although PAA’s near-term strategy does not include a focus on acquisitions, it has completed a number of acquisitions in the past and may pursue future acquisitions on a selective basis. Any acquisition involves potential risks, including:
•performance from the acquired businesses or assets that is below the forecasts PAA used in evaluating the acquisition;
•a significant increase in PAA’s indebtedness and working capital requirements;
•the inability to timely and effectively integrate the operations of recently acquired businesses or assets;
•the incurrence of substantial unforeseen environmental and other liabilities arising out of the acquired businesses or assets for which PAA is either not fully insured or indemnified, including liabilities arising from the operation of the acquired businesses or assets prior to PAA’s acquisition;
•risks associated with operating in lines of business that are distinct and separate from PAA’s historical operations;
•customer or key employee loss from the acquired businesses; and
•the diversion of management’s attention from other business concerns.
Any of these factors could adversely affect PAA’s ability to achieve anticipated levels of cash flows from its acquisitions, realize other anticipated benefits and its ability to pay distributions to its partners or meet its debt service requirements.
Tightened capital markets or other factors that increase PAA’s cost of capital or otherwise limit its access to capital could impair its ability to achieve its strategic objectives.
Any limitations on PAA’s access to capital or increase in the cost of that capital could significantly impair the implementation of its strategy. PAA’s ability to maintain its targeted credit profile, including maintaining its credit ratings, could affect PAA’s cost of capital as well as its ability to execute its strategy. In addition, a variety of factors beyond its control could impact the availability or cost of capital, including domestic or international economic conditions, increases in key benchmark interest rates and/or credit spreads, the adoption of new or amended banking or capital market laws or regulations, the re-pricing of market risks and volatility in capital and financial markets.
Due to these factors, PAA cannot be certain that funding for its capital needs will be available from bank credit arrangements, capital markets or other sources on acceptable terms. If funding is not available when needed, or is available only on unfavorable terms, PAA may be unable to implement its development plans, enhance its existing business, complete strategic projects and transactions, take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on its revenues and results of operations.
PAA’s risk policies cannot eliminate all risks. In addition, the insufficiency of, or non-compliance with its risk policies could result in significant financial losses.
Generally, it is PAA’s policy to establish a margin for crude oil or other products it purchases by selling such products for physical delivery to third-party users, or by entering into a future delivery obligation under derivative contracts. Through these transactions, PAA seeks to maintain a position that is substantially balanced between purchases on the one hand, and sales or future delivery obligations on the other hand. PAA’s policy is not to acquire and hold physical inventory or derivative products for the purpose of speculating on commodity price changes. These policies and practices cannot, however, eliminate all risks. For example, any event that disrupts PAA’s anticipated physical supply of crude oil or other products could expose it to risk of loss resulting from price changes. PAA is also exposed to basis risk when crude oil or other products are purchased against one pricing index and sold against a different index. PAA may also face disruptions to futures markets for crude oil, NGL and other petroleum products, which may impair its ability to execute its commercial or hedging strategies related to the COVID-19 pandemic, future pandemics, epidemics, other public health emergencies or other factors. Margin requirements due to spikes or crashes in commodity prices may require us to exit hedge strategies at inopportune times. Moreover, PAA is exposed to some risks that are not hedged, including risks on certain of its inventory, such as linefill, which must be maintained in order to transport crude oil on its pipelines. In an effort to maintain a balanced position, specifically authorized personnel can purchase or sell crude oil, refined products and NGL, up to predefined limits and authorizations. Although this activity is monitored independently by PAA’s risk management function, it exposes PAA to commodity price risks within these limits.
In addition, PAA’s operations involve the risk of non-compliance with its risk policies. PAA has taken steps within its organization to implement processes and procedures designed to detect unauthorized trading; however, PAA can provide no assurance that these steps will detect and prevent all violations of its risk policies and procedures, particularly if deception, collusion or other intentional misconduct is involved.
PAA’s insurance coverage may not fully cover its losses and it may in the future encounter increased costs related to, and lack of availability of, insurance.
While PAA maintains insurance coverage at levels that it believes to be reasonable and prudent, PAA can provide no assurance that its current levels of insurance will be sufficient to cover any losses that it has incurred or may incur in the future, whether due to deductibles, coverage challenges or other limitations. In addition, over the last several years, as the scale and scope of PAA’s business activities has expanded, the breadth and depth of available insurance markets has contracted. As a result of these factors and other market conditions, as well as the fact that PAA has experienced several incidents over the last several years, premiums and deductibles for certain insurance policies have increased substantially. Accordingly, PAA can give no assurance that it will be able to maintain adequate insurance in the future at rates or on other terms PAA considers commercially reasonable. In addition, although PAA believes that it currently maintains adequate insurance coverage, insurance will not cover many types of interruptions or events that might occur and will not cover all risks associated with its operations. In addition, the proceeds of any such insurance may not be paid in a timely manner and may be insufficient if such an event were to occur. The occurrence of a significant event, the consequences of which are either not covered by insurance or not fully insured, or a significant delay in the payment of a major insurance claim, could materially and adversely affect PAA’s financial position, results of operations and cash flows.
The terms of PAA’s indebtedness may limit its ability to borrow additional funds or capitalize on business opportunities. In addition, PAA’s current or future debt levels, or inability to borrow additional funds or capitalize on business opportunities may limit its future financial and operating flexibility.
As of December 31, 2020, the face value of PAA’s consolidated debt outstanding was approximately $10.3 billion, consisting of approximately $9.5 billion face value of long-term debt (including senior notes, term loan borrowings and finance lease obligations) and approximately $0.8 billion of short-term borrowings. As of December 31, 2020, PAA had approximately $2.2 billion of liquidity available, including cash and cash equivalents and available borrowing capacity under its senior unsecured revolving credit facility and its senior secured hedged inventory facility, subject to continued covenant compliance. Lower Adjusted EBITDA could increase PAA’s leverage ratios and effectively reduce its ability to incur additional indebtedness.
The amount of PAA’s current or future indebtedness could have significant effects on its operations, including, among other things:
•a significant portion of PAA’s cash flow will be dedicated to the payment of principal and interest on its indebtedness and may not be available for other purposes, including the payment of distributions on its units and capital expenditures;
•credit rating agencies may view PAA’s debt level negatively;
•covenants contained in PAA’s existing debt arrangements will require it to continue to meet financial tests that may adversely affect its flexibility in planning for and reacting to changes in its business;
•PAA’s ability to obtain additional financing for working capital, capital expenditures, acquisitions and general partnership purposes may be limited;
•PAA may be at a competitive disadvantage relative to similar companies that have less debt; and
•PAA may be more vulnerable to adverse economic and industry conditions as a result of its significant debt level.
PAA’s credit agreements prohibit distributions on, or purchases or redemptions of, units if any default or event of default is continuing. In addition, the agreements contain various covenants limiting PAA’s ability to, among other things, incur indebtedness if certain financial ratios are not maintained, grant liens, engage in transactions with affiliates, enter into sale-leaseback transactions, and sell substantially all of its assets or enter into a merger or consolidation. PAA’s credit facilities treat a change of control as an event of default and also requires PAA to maintain a certain debt coverage ratio. PAA’s senior notes do not restrict distributions to unitholders, but a default under its credit agreements will be treated as a default under the senior notes. Please read Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Liquidity and Capital Resources-Credit Agreements, Commercial Paper Program and Indentures.”
PAA’s ability to access capital markets to raise capital on favorable terms will be affected by its debt level, its operating and financial performance, the amount of its current maturities and debt maturing in the next several years, and by prevailing market conditions. Moreover, if the rating agencies were to downgrade PAA’s credit ratings, then it could experience an increase in its borrowing costs, face difficulty accessing capital markets or incurring additional indebtedness, be unable to receive open credit from its suppliers and trade counterparties, be unable to benefit from swings in market prices and shifts in market structure during periods of volatility in the crude oil market or suffer a reduction in the market price of its common units. If PAA is unable to access the capital markets on favorable terms at the time a debt obligation becomes due in the future, it might be forced to refinance some of its debt obligations through bank credit, as opposed to long-term public debt securities or equity securities, or sell assets. The price and terms upon which PAA might receive such extensions or additional bank credit, if at all, could be more onerous than those contained in existing debt agreements. Any such arrangements could, in turn, increase the risk that PAA’s leverage may adversely affect its future financial and operating flexibility and thereby impact its ability to pay cash distributions at expected rates.
Increases in interest rates could adversely affect PAA’s business and the trading price of its units.
As of December 31, 2020, the face value of PAA’s consolidated debt was approximately $10.3 billion, of which approximately $9.4 billion was at fixed interest rates and approximately $0.9 billion was at variable interest rates. PAA is exposed to market risk due to the short-term nature of its commercial paper borrowings and the floating interest rates on its credit facilities. PAA’s results of operations, cash flows and financial position could be adversely affected by significant increases in interest rates above current levels. Additionally, increases in interest rates could adversely affect PAA’s Supply and Logistics segment results by increasing interest costs associated with the storage of hedged crude oil and NGL inventory. Further, the trading price of PAA’s common units may be sensitive to changes in interest rates and any rise in interest rates could adversely impact such trading price.
Changes in currency exchange rates could adversely affect PAA’s operating results.
Because PAA is a U.S. dollar reporting company and also conducts operations in Canada, it is exposed to currency fluctuations and exchange rate risks that may adversely affect the U.S. dollar value of its earnings, cash flow and partners’ capital under applicable accounting rules. For example, as the U.S. dollar appreciates against the Canadian dollar, the U.S. dollar value of PAA’s Canadian dollar denominated earnings is reduced for U.S. reporting purposes.
PAA’s business requires the retention and recruitment of a skilled workforce, and difficulties recruiting and retaining its workforce could result in a failure to implement PAA’s business plans.
PAA’s operations and management require the retention and recruitment of a skilled workforce, including engineers, technical personnel and other professionals. PAA and its affiliates compete with other companies in the energy industry for this skilled workforce. The COVID-19 pandemic and associated restrictions may also place additional demands on our employees, which may in turn make it more challenging to retain or recruit talented labor. If PAA is unable to (i) retain current employees; and/or (ii) recruit new employees of comparable knowledge and experience, PAA’s business could be negatively impacted. In addition, PAA could experience increased costs to retain and recruit these professionals.
An impairment of long-term assets could reduce PAA’s earnings.
At December 31, 2020, PAA had approximately $14.6 billion of net property and equipment, $982 million of linefill and base gas, $3.8 billion of investments accounted for under the equity method of accounting and $805 million of net intangible assets capitalized on its balance sheet. GAAP requires an assessment for impairment in certain circumstances, including when there is an indication that the carrying value of property and equipment may not be recoverable. If PAA was to determine that any of its property and equipment, linefill and base gas, intangibles or equity method investments was impaired, it could be required to take an immediate charge to earnings, which could adversely impact its operating results, with a corresponding reduction of partners’ capital and increase in balance sheet leverage as measured by debt-to-total capitalization. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Critical Accounting Policies and Estimates” for additional discussion of our accounting policies and use of estimates associated with impairments. During the year ended December 31, 2020, PAA recognized goodwill impairment losses of $2.5 billion and non-cash impairment charges of approximately $914 million related to the write-down of certain pipeline and other long-lived assets, certain of PAA’s investments in unconsolidated entities, and assets upon classification as held for sale. See Note 6, Note 7, Note 8 and Note 9 to our Consolidated Financial Statements for additional information regarding these impairments.
PAA is dependent on the use or availability of third-party assets for certain of its operations.
Certain of PAA’s business activities require the use or availability of third-party assets over which it may have little or no control. If at any time the availability of these assets is limited or denied, and if access to alternative assets cannot be arranged, it could have an adverse effect on PAA’s business, results of operations and cash flow.
Significant under-utilization of certain assets could significantly reduce PAA’s profitability due to fixed costs incurred to obtain the right to use such assets.
From time to time in connection with its business, PAA may lease or otherwise secure the right to use certain assets (such as railcars, trucks, barges, ships, pipeline capacity, storage capacity and other similar assets) with the expectation that the revenues it generates through the use of such assets will be greater than the fixed costs it incurs pursuant to the applicable leases or other arrangements. However, when such assets are not utilized or are under-utilized, PAA’s profitability could be negatively impacted because the revenues it earns are either non-existent or reduced, but it remains obligated to continue paying any applicable fixed charges, in addition to the potential of incurring other costs attributable to the non-utilization of such assets. Significant under-utilization of assets PAA leases or otherwise secures the right to use in connection with its business could have a significant negative impact on PAA’s profitability and cash flows.
Many of PAA’s assets have been in service for many years and require significant expenditures to maintain them. As a result, its maintenance or repair costs may increase in the future.
PAA’s pipelines, terminals, storage and processing and fractionation assets are generally long-lived assets, and many of them have been in service for many years. The age and condition of its assets could result in increased maintenance or repair expenditures in the future. Any significant increase in these expenditures could adversely affect PAA’s results of operations, financial position or cash flows, as well as its ability to make cash distributions to its unitholders.
PAA does not own all of the land on which its pipelines and facilities are located, which could result in disruptions to its operations.
PAA does not own all of the land on which its pipelines and facilities have been constructed, and therefore is potentially subject to more onerous terms and/or increased costs to retain necessary land use if PAA does not have valid rights-of-way or if such rights-of-way lapse or terminate. In some instances, PAA obtains the rights to construct and operate its pipelines on land owned by third parties and governmental agencies for a specific period of time. Following a decision issued in May 2017 by the Tenth Circuit Court of Appeals, tribal ownership of even a very small fractional interest in tribal land owned or at one time owned by an individual Indian landowner, bars condemnation of any interest in the allotment. Consequently, the inability to condemn such allotted lands under circumstances where existing pipeline rights-of-way may soon lapse or terminate serves as an additional potential impediment for pipeline operations. In September 2018, the Fourth Circuit Court of Appeals reversed a decision of the United States Forest Service (“USFS”) issuing a permit for the construction of a pipeline and granting a right of way across the Appalachian Trail, ruling that the USFS lacked statutory authority. This decision may make it more difficult to obtain permits and rights of way on certain federal lands and may be used as precedent to challenge existing and future permits and rights of way. Additionally, parts of PAA’s operations cross land that has historically been apportioned to various Native American/First Nations tribes, who may exercise significant jurisdiction and sovereignty over their lands. For more information, see our regulatory disclosure entitled “Indigenous Protections.” PAA cannot guarantee that it will always be able to renew existing rights-of-way or obtain new rights-of-way on favorable terms or without experiencing significant delays and costs. Any loss of rights with respect to real property, through PAA’s inability to renew right-of-way contracts or otherwise, could have a material adverse effect on its business, results of operations, and financial position.
For various operating and commercial reasons, PAA may not be able to perform all of its obligations under its contracts, which could lead to increased costs and negatively impact its financial results.
Various operational and commercial factors could result in an inability on PAA’s part to satisfy its contractual commitments and obligations. For example, in connection with PAA’s provision of firm storage services and hub services to its natural gas storage customers, PAA enters into contracts that obligate PAA to honor its customers’ requests to inject gas into its storage facilities, withdraw gas from its facilities and wheel gas through its facilities, in each case subject to volume, timing and other limitations set forth in such contracts. The following factors could adversely impact PAA’s ability to perform its obligations under these contracts:
•a failure on the part of PAA’s storage facilities to perform as it expects them to, whether due to malfunction of equipment or facilities or realization of other operational risks;
•the operating pressure of PAA’s storage facilities (affected in varying degree, depending on the type of storage cavern, by total volume of working and base gas, and temperature);
•a variety of commercial decisions PAA makes from time to time in connection with the management and operation of its storage facilities. Examples include, without limitation, decisions with respect to matters such as (i) the aggregate amount of commitments PAA is willing to make with respect to wheeling, injection, and withdrawal services, which could exceed PAA’s capabilities at any given time for various reasons, (ii) the timing of scheduled and unplanned maintenance or repairs, which can impact equipment availability and capacity, (iii) the schedule for and rate at which PAA conducts opportunistic leaching activities at its facilities in connection with the expansion of existing salt caverns, which can impact the amount of storage capacity PAA has available to satisfy its customers’ requests, (iv) the timing and aggregate volume of any base gas park and/or loan transactions PAA consummates, which can directly affect the operating pressure of PAA’s storage facilities and (v) the amount of compression capacity and other gas handling equipment that PAA installs at its facilities to support gas wheeling, injection and withdrawal activities; and
•adverse operating conditions due to hurricanes, extreme weather events or conditions, and operational problems or issues with third-party pipelines, storage or production facilities.
Although PAA manages and monitors all of these various factors in connection with the ongoing operation of its natural gas storage facilities with the goal of performing all of its contractual commitments and obligations and optimizing its revenue, one or more of the above factors may adversely impact PAA’s ability to satisfy its injection, withdrawal or wheeling obligations under its storage contracts. In such event, PAA may be liable to its customers for losses or damages they suffer and/or PAA may need to incur costs or expenses in order to permit it to satisfy its obligations.
If PAA fails to obtain materials or commodities in the quantity and the quality it needs, and at commercially acceptable prices, whether due to supply disruptions, tariffs, quotas or other factors, PAA’s results of operations, financial condition and cash flows could be materially and adversely affected.
PAA’s business requires access to steel and other materials to construct and maintain new and existing pipelines and facilities. If PAA experiences a shortage in the supply of these materials or is unable to source sufficient quantities of high quality materials at acceptable prices and in a timely manner, it could materially and adversely affect PAA’s ability to construct new infrastructure and maintain its existing assets.
PAA’s business also depends on having access to significant amounts of electricity and other commodities. If PAA is unable to obtain commodities sufficient to operate and maintain its assets, it could materially and adversely affect its business.
The COVID-19 pandemic has caused widespread supply chain disruptions, which may make it more challenging to obtain sufficient quantities of high quality materials at acceptable prices and in a timely manner. If PAA is unable to source such materials, it could materially and adversely affect its ability to construct new infrastructure and maintain its existing assets.
In addition, some of the materials used in PAA’s business are imported. Existing and future import duties and quotas could materially increase PAA’s costs of procuring imported or domestic steel and/or create shortages or difficulties in procuring sufficient quantities of steel meeting PAA’s required technical specifications. A material increase in PAA’s costs of construction and maintenance or any significant delays in its ability to complete its infrastructure projects could have a material adverse effect on PAA’s financial position, results of operations and cash flows.
Risks Related to Laws and Regulations Impacting PAA’s Business
PAA’s 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 it to significant costs and liabilities. The current laws and regulations affecting PAA’s business are subject to change and in the future PAA may be subject to additional laws, executive orders and regulations, which could adversely impact PAA’s business.
PAA’s operations involving the storage, treatment, processing, and transportation of liquid hydrocarbons, including crude oil, NGL and refined products, as well as PAA’s operations involving the storage of natural gas, are subject to stringent federal, state, and local laws and regulations governing the discharge of materials into the environment. PAA’s operations are also subject to laws and regulations relating to protection of the environment and wildlife, operational safety, climate change and related matters. Compliance with all of these laws and regulations increases its overall cost of doing business, including its capital costs to construct, maintain and upgrade equipment and facilities. Also, new or additional regulations, new interpretations of existing requirements or changes in PAA’s operations could trigger new permitting requirements applicable to its operations, which could result in increased costs or delays of, or denial of rights to conduct, PAA’s development programs. The failure to comply with any such laws and regulations could result in the assessment of administrative, civil, and criminal penalties, the imposition of investigatory and remedial liabilities, the issuance of injunctions that may subject PAA to additional operational requirements and constraints, or claims of damages to property or persons resulting from its operations. In addition, criminal violations of certain environmental laws, or in some cases even the allegation of criminal violations, may result in the temporary suspension or outright debarment from participating in government contracts. The laws and regulations applicable to PAA’s operations are subject to change and interpretation by the relevant governmental agency, including the possibility that exemptions it currently qualifies for may be modified or changed in ways that require PAA to incur significant additional compliance costs. PAA’s business and operations may also become subject to additional laws or regulations. For example, President Biden campaigned on several initiatives to address environmental concerns. Following the election of President Biden and a Democratic majority in both houses of Congress, it is possible that PAA’s operations, and those of its customers, may be subject to greater environmental regulations, particularly with regard to hydraulic fracturing, permitting, and GHG emissions. Any new laws, executive orders or regulations, or changes to or interpretations of existing laws or regulations, adverse to PAA could have a material adverse effect on its operations, revenues, expenses and profitability.
PAA has a history of incremental additions to the miles of pipelines it owns, both through acquisitions and investment capital projects. PAA has also increased its terminal and storage capacity and operates several facilities on or near navigable waters and domestic water supplies. Although PAA has implemented programs intended to maintain the integrity of its assets (discussed below), as it acquires additional assets it is at risk for an increase in the number of releases of liquid hydrocarbons into the environment. These releases expose PAA to potentially substantial expense, including clean-up and remediation costs, fines and penalties, and third-party claims for personal injury or property damage related to past or future releases. Some of these expenses could increase by amounts disproportionately higher than the relative increase in pipeline mileage and the increase in revenues associated therewith. PAA’s refined products terminal assets are also subject to significant compliance costs and liabilities. In addition, because of the increased volatility of refined products and their tendency to migrate farther and faster than crude oil when released, releases of refined products into the environment can have a more significant impact than crude oil and require significantly higher expenditures to respond and remediate. The incurrence of such expenses not covered by insurance, indemnity or reserves could materially adversely affect PAA’s results of operations.
PAA currently devotes substantial resources to comply with DOT-mandated pipeline integrity rules. The DOT regulations include requirements for the establishment of pipeline integrity management programs and for protection of “high consequence areas” where a pipeline leak or rupture could produce significant adverse consequences. Pipeline safety regulations are revised frequently. For example, Congress, through the 2021 Fiscal Year Omnibus Appropriations Bill, directed PHMSA to move forward with several regulatory actions. For more information, please see our regulatory disclosure entitled “Pipeline Safety/Integrity Management.” The adoption of new regulations requiring more comprehensive or stringent safety standards could require PAA to install new or modified safety controls, pursue new capital projects, or conduct maintenance programs on an accelerated basis, all of which could require PAA to incur increased operational costs that could be significant.
Although PAA continues to focus on pipeline and facility integrity management as a primary operational emphasis, doing so requires substantial time and resources and cannot eliminate all risk of releases. PAA has an internal review process pursuant to which it examines various aspects of its pipeline and gathering systems that are not currently subject to the DOT pipeline integrity management mandate. The purpose of this process is to review the surrounding environment, condition and operating history of these pipeline and gathering assets to determine if such assets warrant additional investment or replacement. Accordingly, in addition to potential cost increases related to unanticipated regulatory changes or injunctive remedies resulting from regulatory agency enforcement actions, PAA may elect (as a result of its own internal initiatives) to spend substantial sums to enhance the integrity of and upgrade its pipeline systems to maintain environmental compliance and, in some cases, PAA may take pipelines out of service if it believes the cost of upgrades will exceed the value of the pipelines. PAA cannot provide any assurance as to the ultimate amount or timing of future pipeline integrity expenditures but any such expenditures could be significant. See “Environmental - General” in Note 19 to our Consolidated Financial Statements. In addition, despite PAA’s pipeline and facility integrity management efforts, it can provide no assurance that its pipelines and facilities will not experience leaks or releases or that PAA will be able to fully comply with all of the federal, state and local laws and regulations applicable to the operation of PAA’s pipelines or facilities; any such leaks or releases could be material and could have a significant adverse impact on PAA’s reputation, financial position, cash flows and ability to pay or increase distributions to its unitholders.
PAA’s assets are subject to federal, state and provincial regulation. Rate regulation or a successful challenge to the rates PAA charges on its U.S. and Canadian pipeline systems may reduce the amount of cash it generates.
PAA’s U.S. interstate common carrier liquids pipelines are subject to regulation by the FERC under the ICA. The ICA requires that tariff rates and terms and conditions of service for liquids pipelines be just and reasonable and non-discriminatory. PAA is also subject to the Pipeline Safety Regulations of the DOT. PAA’s intrastate pipeline transportation activities are subject to various state laws and regulations as well as orders of regulatory bodies.
For PAA’s U.S. interstate common carrier liquids pipelines subject to FERC regulation under the ICA and its interstate natural gas storage facilities subject to FERC regulation under the NGA, shippers may protest its pipeline tariff filings or file complaints against its existing rates or complaints alleging that it is engaging in discriminating behavior. The FERC can also investigate on its own initiative. Under certain circumstances, the FERC could limit PAA’s ability to set rates based on its costs, or could order PAA to reduce its rates and could require the payment of reparations to complaining shippers for up to two years prior to the complaint. Natural gas storage facilities are subject to regulation by the FERC, the DOT, and certain state agencies. Under certain circumstances, the FERC could limit PAA’s ability to set its natural gas storage rates at market-based rates and could order PAA to reduce its rates for natural gas storage service or require the payment of refunds to its storage customers.
In addition, PAA routinely monitors the public filings and proceedings of other parties with the FERC and other regulatory agencies in an effort to identify issues that could potentially impact its business. Under certain circumstances PAA may choose to intervene in such third-party proceedings in order to express its support for, or its opposition to, various issues
raised by the parties to such proceedings. For example, if PAA believes that a petition filed with, or order issued by, the FERC is improper, overbroad other otherwise flawed, PAA may attempt to intervene in such proceedings for the purpose of protesting such petition or order and requesting appropriate action such as a clarification, rehearing or other remedy. Despite such efforts, PAA can provide no assurance that the FERC and other agencies that regulate its business will not issue future orders or declarations that increase its costs or otherwise adversely affect its operations.
PAA’s Canadian pipelines are subject to regulation by the CER and by provincial authorities. Under the Canadian Energy Regulator Act, the CER could investigate the tariff rates or the terms and conditions of service relating to a jurisdictional pipeline on its own initiative upon the filing of a toll or tariff application, or upon the filing of a written complaint. If the CER found the rates or terms of service relating to such pipeline to be unjust or unreasonable or unjustly discriminatory, the CER could require PAA to change its rates, provide access to other shippers, or change its terms of service. A provincial authority could, on the application of a shipper or other interested party, investigate the tariff rates or PAA’s terms and conditions of service relating to its provincially-regulated proprietary pipelines. If it found PAA’s rates or terms of service to be contrary to statutory requirements, it could impose conditions it considers appropriate. A provincial authority could declare a pipeline to be a common carrier pipeline, and require PAA to change its rates, provide access to other shippers, or otherwise alter its terms of service. Any reduction in PAA’s tariff rates would result in lower revenue and cash flows.
Some of PAA’s operations cross the U.S./Canada border and are subject to cross-border regulation.
PAA’s cross border activities subject it to regulatory matters, including import and export licenses, tariffs, Canadian and U.S. customs and tax issues and toxic substance certifications. Such regulations include the Short Supply Controls of the EAA, the NAFTA and the TSCA. Violations of these licensing, tariff and tax reporting requirements could result in the imposition of significant administrative, civil and criminal penalties. Furthermore, Presidential Permits that allow cross-border movements of crude oil may be revoked or terminated at any time.
PAA’s purchases and sales of crude oil, natural gas and NGL, and hedging activities, expose it to potential regulatory risks.
The FTC, the FERC and the CFTC hold statutory authority to monitor certain segments of the physical and futures energy commodities markets. These agencies have imposed broad regulations prohibiting fraud and manipulation of such markets. With regard to PAA’s physical purchases and sales of crude oil, natural gas or NGL and any related hedging activities that it undertakes, PAA is required to observe the market-related regulations enforced by these agencies, which hold substantial enforcement authority. PAA’s purchases and sales may also be subject to certain reporting and other requirements. Additionally, to the extent that PAA enters into transportation contracts with pipelines that are subject to FERC regulation, it is subject to FERC requirements related to the use of such capacity. Any failure on PAA’s part to comply with the regulations and policies of the FERC, the FTC or the CFTC could result in the imposition of civil and criminal penalties. Failure to comply with such regulations, as interpreted and enforced, could have a material adverse effect on PAA’s business, results of operations, financial condition and its ability to make cash distributions to its unitholders.
The enactment and implementation of derivatives legislation could have an adverse impact on PAA’s ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with its business and increase the working capital requirement to conduct these hedging activities.
The Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”), enacted on July 21, 2010, established federal oversight and regulation of derivative markets and entities, such as PAA, that participate in those markets. The Dodd-Frank Act requires the CFTC and the SEC to promulgate rules and regulations implementing the Dodd-Frank Act. Although the CFTC has finalized certain regulations, others remain to be finalized or implemented and it is not possible at this time to predict when this will be accomplished.
In January 2020, the CFTC proposed new rules that would place limits on positions in certain core futures and equivalent swaps contracts for, or linked to, certain physical commodities, subject to exceptions for certain bona fide hedging transactions. As these new position limit rules are not yet final, the impact of those provisions on PAA is uncertain at this time.
The CFTC has designated certain interest rate swaps and credit default swaps for mandatory clearing, and the associated rules require PAA, in connection with covered derivative activities, to comply with clearing and trade-execution requirements or take steps to qualify for an exemption from such requirements. PAA does not utilize credit default swaps and PAA qualifies for, and expects to continue to qualify for, the end-user exception from the mandatory clearing requirements for swaps entered into to hedge its interest rate risks. Should the CFTC designate commodity derivatives for mandatory clearing, PAA would expect to qualify for an end-user exception from the mandatory clearing requirements for swaps entered into to hedge its commodity price risk. However, the majority of PAA’s financial derivative transactions used for hedging commodity price risks are currently executed and cleared over exchanges that require the posting of margin or letters of credit based on initial and variation margin requirements. Pursuant to the Dodd Frank Act, however, the CFTC or federal banking regulators may require the posting of collateral with respect to uncleared interest rate and commodity derivative transactions.
Certain banking regulators and the CFTC have adopted final rules establishing minimum margin requirements for uncleared swaps. Although PAA qualifies for the end-user exception from margin requirements for swaps entered into to hedge commercial risks, if any of PAA’s swaps do not qualify for the commercial end-user exception, or if PAA is otherwise required to post additional cash margin or collateral it could reduce PAA’s ability to execute hedges necessary to reduce commodity price exposures and protect cash flows. Posting of additional cash margin or collateral could affect PAA’s liquidity (defined as unrestricted cash on hand plus available capacity under its credit facilities) and reduce PAA’s ability to use cash for capital expenditures or other partnership purposes.
Even if PAA itself is not required to post additional cash margin or collateral for its derivative contracts, the banks and other derivatives dealers who are PAA’s contractual counterparties will be required to comply with other new requirements under the Dodd-Frank Act and related rules. The costs of such compliance may be passed on to customers such as PAA, thus decreasing the benefits to PAA of hedging transactions or reducing its profitability. In addition, implementation of the Dodd-Frank Act and related rules and regulations could reduce the overall liquidity and depth of the markets for financial and other derivatives PAA utilizes in connection with its business, which could expose PAA to additional risks or limit the opportunities PAA is able to capture by limiting the extent to which PAA is able to execute its hedging strategies.
Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and gas. PAA’s financial results could be adversely affected if a consequence of the Dodd-Frank Act and implementing regulations is lower commodity prices.
The full impact of the Dodd-Frank Act and related regulatory requirements upon PAA’s business will not be known until the regulations are implemented and the market for derivatives contracts has adjusted. The Dodd-Frank Act and any new regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks PAA encounters, reduce PAA’s ability to monetize or restructure its existing derivative contracts. If PAA reduces its use of derivatives as a result of the Dodd-Frank Act and regulations implementing the Dodd-Frank Act, PAA’s results of operations may become more volatile and its cash flows may be less predictable. Any of these consequences could have a material adverse effect on PAA, its financial condition and its results of operations.
Legislation, executive orders and regulatory initiatives relating to hydraulic fracturing or other hydrocarbon development activities could reduce domestic production of crude oil and natural gas.
Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from unconventional geological formations. Recent advances in hydraulic fracturing techniques have resulted in significant increases in crude oil and natural gas production in many basins in the United States and Canada. The process involves the injection of water, sand and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production, and it is typically regulated by state and provincial oil and gas commissions. PAA does not perform hydraulic fracturing, but many of the producers using its pipelines do. Hydraulic fracturing has been subject to increased scrutiny and there have been a variety of legislative and regulatory proposals to prohibit, restrict, or more closely regulate various forms of hydraulic fracturing; for example, the Governor of California signed an executive order in which he announced plans to ask the state legislature to promulgate legislation banning the issuance of new hydraulic fracturing permits by 2024. In January 2021, President Biden signed an executive order directing the Secretary of the Interior to pause new oil and gas leases on public lands and in offshore waters of the United States. These actions, as well as any other legislation, executive orders or regulatory initiatives that curtail hydraulic fracturing or otherwise limit producers’ ability to drill or complete wells could reduce the production of crude oil and natural gas in the United States or Canada, and could thereby reduce demand for PAA’s transportation, terminalling and storage services as well as its supply and logistics services.
Climate change laws and regulations restricting emissions of greenhouse gases could result in increased operating costs and reduced demand for crude oil and natural gas, while potential physical effects of climate change could disrupt crude oil production and cause PAA to incur significant costs in preparing for or responding to those effects.
In response to findings that emissions of GHGs present an endangerment to public health and the environment, the EPA has adopted regulations under existing provisions of the federal Clean Air Act to reduce GHG emissions. For example, in June 2016, the EPA finalized new regulations, known as Subpart OOOOa, that set emissions standards for methane and volatile organic compounds from new and modified oil and natural gas production and natural gas processing and transmission facilities. However, there have been attempts to modify these regulations, and litigation concerning the regulations is ongoing.
While Congress has from time to time considered legislation to reduce emissions of GHGs, no significant legislation to reduce GHG emissions has been adopted at the federal level. However, President Biden has previously stated that one of his administration’s climate change goals is to achieve a 100% clean energy economy and net-zero emissions by 2050 at the national level; however, PAA cannot predict the degree to which this plan may be successfully implemented, what initiatives may be promulgated to facilitate it, or the degree to which it may impact its operations. In the absence of federal climate legislation, a number of state and regional GHG restrictions have emerged. Analogous regulations are or may be implemented in Canada. Any future laws and regulations that limit emissions of GHGs could adversely affect supply of or demand for oil and natural gas that operators, some of whom are PAA’s customers, produce and could thereby reduce demand for PAA’s midstream services. For more information, see our regulatory disclosure entitled “Climate Change Initiatives.”
Moreover, activists concerned about the potential effects of climate change have directed their attention at sources of funding for hydrocarbon energy companies, which has resulted in certain sources of capital restricting or eliminating their investment in oil and natural gas activities. Additionally, activist shareholders have introduced proposals that may seek to force companies to adopt aggressive emission reduction targets or restrict more hydrocarbon-intensive activities. Separately, activists may also pursue other means of curtailing oil and gas operations, such as through litigation; several suits have been filed in recent years claiming that oil and gas companies are responsible for climate harm due to their production and/or marketing of hydrocarbons or that oil and gas companies have known about the adverse effects of climate change but failed to adequately disclose those impacts to their investors or consumers. While PAA cannot predict the outcomes of such activities, they could make it more difficult for operators to engage in exploration and production activities, ultimately reducing demand for PAA’s services. Finally, many scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce significant physical effects, such as increased frequency and severity of storms, droughts, floods and other climatic events; if any such effects were to occur, they have the potential to cause physical damage to PAA’s assets and thus could have an adverse effect on its financial condition and operations.
Risks Inherent in an Investment in PAA
Cost reimbursements due to PAA’s general partner may be substantial and will reduce PAA’s cash available for distribution to its unitholders.
Prior to making any distribution on its common units, PAA will reimburse its general partner and its affiliates, including officers and directors of its general partner, for all expenses incurred on PAA’s behalf. In addition, PAA is required to pay all direct and indirect expenses of the Plains Entities, other than income taxes of any of the PAGP Entities. The reimbursement of expenses and the payment of fees and expenses could adversely affect PAA’s ability to make distributions. PAA’s general partner has sole discretion to determine the amount of these expenses. In addition, PAA’s general partner and its affiliates may provide PAA with services for which PAA will be charged reasonable fees as determined by its general partner.
Cash distributions are not guaranteed and may fluctuate with PAA’s performance and the establishment of financial reserves.
Because distributions on PAA’s common units are dependent on the amount of cash it generates, distributions may fluctuate based on PAA’s performance, which will result in fluctuations in the amount of distributions ultimately received by AAP. The actual amount of cash that is available to be distributed each quarter will depend on numerous factors, some of which are beyond PAA’s control and the control of PAA’s general partner. Cash distributions are dependent primarily on cash flow, levels of financial reserves and working capital borrowings, and not solely on profitability, which is affected by non-cash items. PAA’s levels of financial reserves are established by its general partner and include reserves for the proper conduct of PAA’s business (including future capital expenditures and anticipated credit needs), compliance with law or contractual obligations and funding of future distributions to its Series A and Series B preferred unitholders. Therefore, cash distributions might be made during periods when PAA records losses and might not be made during periods when it records profits.
PAA’s preferred units have rights, preferences and privileges that are not held by, and are preferential to the rights of, holders of PAA’s common units.
PAA’s Series A preferred units and PAA’s Series B preferred units (together, “PAA’s preferred units”) rank senior to all of PAA’s other classes or series of equity securities with respect to distribution rights and rights upon liquidation. These preferences could adversely affect the market price for PAA’s common units, or could make it more difficult for PAA to sell its common units in the future.
In addition, distributions on PAA’s preferred units accrue and are cumulative, at the rate of 8% per annum with respect to PAA’s Series A preferred units and 6.125% with respect to PAA’s Series B preferred units on the original issue price. PAA’s Series A preferred units are convertible into PAA common units by the holders of such units or by PAA in certain circumstances. PAA’s Series B preferred units are not convertible into PAA common units, but are redeemable by PAA in certain circumstances. PAA’s obligation to pay distributions on PAA’s preferred units, or on the PAA common units issued following the conversion of PAA’s Series A preferred units, could impact its liquidity and reduce the amount of cash flow available for working capital, capital expenditures, growth opportunities, acquisitions, and other general partnership purposes. PAA’s obligations to the holders of PAA’s preferred units could also limit its ability to obtain additional financing or increase its borrowing costs, which could have an adverse effect on PAA’s financial condition.
Tax Risks
As our only cash-generating assets consist of our partnership interest in AAP and its related direct and indirect interests in PAA, our tax risks are primarily derivative of the tax risks associated with an investment in PAA.
The tax treatment of PAA depends on its status as a partnership for U.S. federal income tax purposes, as well as it not being subject to a material amount of additional entity-level taxation by individual states. If the IRS were to treat PAA as a corporation for federal income tax purposes or if PAA becomes subject to additional amounts of entity-level taxation for state or foreign tax purposes, it would reduce the amount of cash available for distribution to us and increase the portion of our distributions treated as taxable dividends.
At December 31, 2020, we owned an approximate 79% limited partner interest in AAP, which directly owned a limited partner interest in PAA through its ownership of approximately 245.8 million PAA common units (approximately 31% of PAA’s Series A preferred units and common units combined). Accordingly, the value of our indirect investment in PAA, as well as the anticipated after-tax economic benefit of an investment in our Class A shares, depends largely on PAA being treated as a partnership for federal income tax purposes, which requires that 90% or more of PAA’s gross income for every taxable year consist of qualifying income, as defined in Section 7704 of the Internal Revenue Code of 1986, as amended (the “Code”). Based on PAA’s current operations, and current Treasury Regulations, PAA believes that it is treated as a partnership rather than a corporation for such purposes; however, a change in PAA’s business could cause it to be treated as a corporation for federal income tax purposes.
Current law may change, causing PAA to be treated as a corporation for federal income tax purposes or otherwise subjecting PAA to additional entity-level taxation. In addition, several states have been evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Imposition of any new or increased federal or state taxes on PAA may result in a decrease in the amount of distributions AAP receives from PAA and our resulting cash flows could be reduced substantially, which would adversely affect our ability to pay distributions to our shareholders.
If PAA were treated as a corporation for federal income tax purposes, it would pay federal income tax on its taxable income at the corporate tax rate and would likely pay state income taxes at varying rates. Distributions to PAA’s partners, including AAP, would generally be taxed again as corporate distributions, and no income, gains, losses or deductions would flow through to PAA’s partners. Because a tax would be imposed upon PAA as a corporation, its cash available for distribution would be substantially reduced. Therefore, treatment of PAA as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to us, likely causing a substantial reduction in the value of our Class A shares.
Moreover, if PAA were treated as a corporation we would not be entitled to the deductions associated with our initial acquisition of interests in AAP or subsequent exchanges of retained AAP interests and Class B shares for our Class A shares. As a result, if PAA were treated as a corporation, (i) our liability for taxes would likely be higher, further reducing our cash available for distribution, and (ii) a greater portion of the cash we are able to distribute will be treated as a taxable dividend.
The tax treatment of publicly traded partnerships or an investment in PAA common units could be subject to potential legislative, judicial or administrative changes or differing interpretations, possibly applied on a retroactive basis.
The present U.S. federal income tax treatment of publicly traded partnerships, including PAA, or an investment in PAA common units may be modified by administrative, legislative or judicial changes or differing interpretations at any time. Members of Congress have proposed and considered substantive changes to the existing U.S. federal income tax laws that would affect publicly traded partnerships, including proposals that would eliminate PAA’s ability to qualify for partnership tax treatment.
In addition, the Treasury Department has issued, and in the future may issue, regulations interpreting those laws that affect publicly traded partnerships. There can be no assurance that there will not be further changes to U.S. federal income tax laws or the Treasury Department’s interpretation of the qualifying income rules in a manner that could impact PAA’s ability to qualify as a partnership in the future.
Any modification to the U.S. federal income tax laws and interpretations thereof may or may not be retroactively applied and could make it more difficult or impossible for PAA to meet the exception for certain publicly traded partnerships to be treated as partnerships for U.S. federal income tax purposes. We are unable to predict whether any changes or other proposals will ultimately be enacted. Any future legislative changes could negatively impact the value of our indirect investment in PAA.
If the IRS makes audit adjustments to PAA’s income tax returns for tax years beginning after December 31, 2017, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustments directly from PAA, in which case PAA’s cash distribution to AAP and our cash available for distribution to our shareholders might be substantially reduced.
Pursuant to the Bipartisan Budget Act of 2015, for tax years beginning after December 31, 2017, if the IRS makes audit adjustments to PAA’s income tax returns, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustments directly from PAA. To the extent possible under these rules, PAA’s general partner may elect to either pay the taxes (including any applicable penalties and interest) directly to the IRS or, if PAA is eligible, issue a revised information statement to each unitholder and former unitholder with respect to an audited and adjusted return. Although PAA’s general partner may elect to have PAA’s unitholders and former unitholders take such audit adjustment into account and pay any resulting taxes (including applicable penalties or interest) in accordance with their interests in PAA during the tax year under audit, there can be no assurance that such election will be practical, permissible or effective in all circumstances. As a result, PAA’s current unitholders, including us through AAP, may bear some or all of the tax liability resulting from such audit adjustment, even if such unitholders did not own units in PAA during the tax year under audit. If, as a result of any such audit adjustment, PAA or AAP is required to make payments of taxes, penalties and interest, then the amount of distributions we receive from AAP could be substantially reduced, which would adversely affect our ability to pay distributions to our shareholders. These rules are not applicable for tax years beginning on or prior to December 31, 2017.
Taxable gain or loss on the sale of our Class A shares could be more or less than expected.
If a holder sells our Class A shares, the holder will recognize gain or loss equal to the difference between the amount realized and the holder’s tax basis in those Class A shares. To the extent that the amount of our distributions exceeds our current and accumulated earnings and profits, the distributions will be treated as a tax free return of capital and will reduce a holder’s tax basis in the Class A shares. We did not have any earnings and profits in 2020 and we do not expect to have any earnings and profits for an extended period of time. Because our distributions in excess of our earnings and profits decrease a holder’s tax basis in Class A shares, such excess distributions will result in a corresponding increase in the amount of gain, or a corresponding decrease in the amount of loss, recognized by the holder upon the sale of the Class A shares.
Our current tax treatment may change, which could affect the value of our Class A shares or reduce our cash available for distribution.
Our expectation that tax deductions associated with our initial and subsequent acquisitions of interests in AAP (as a result of the exercise by Legacy Owners of their exchange rights) will offset all of our current taxable income for an extended period of time, and thus result in our distributions not constituting taxable dividends for an extended period of time, is based on current law with respect to the amortization of basis adjustments associated with our acquisition of interests in AAP. Changes in federal income tax law relating to such tax treatment could result in (i) our being subject to additional taxation at the entity level with the result that we would have less cash available for distribution, and (ii) a greater portion of our distributions being treated as taxable dividends. Moreover, we are subject to tax in numerous jurisdictions. Changes in current law in these jurisdictions,
particularly relating to the treatment of deductions attributable to acquisitions of interests in AAP, could result in our being subject to additional taxation at the entity level with the result that we would have less cash available for distribution.
Any decrease in our Class A share price could adversely affect our amount of cash available for distribution.
Changes in certain market conditions may cause our Class A share price to decrease. If our Legacy Owners exchange their retained interests in AAP and Class B shares in us for our Class A shares at a point in time when our Class A share price is below the price at which Class A shares were sold in our initial public offering or in any subsequent exchange, the ratio of our income tax deductions to gross income would decline. This decline could result in our being subject to tax sooner than expected, our tax liability being greater than expected, or a greater portion of our distributions being treated as taxable dividends.
The IRS Forms 1099-DIV that our shareholders receive from their brokers may over-report dividend income with respect to our shares for U.S. federal income tax purposes, which may result in a shareholder’s overpayment of tax. In addition, failure to report dividend income in a manner consistent with the IRS Forms 1099-DIV may cause the IRS to assert audit adjustments to a shareholder’s U.S. federal income tax return. For non-U.S. holders of our shares, brokers or other withholding agents may overwithhold taxes from dividends paid, in which case a shareholder generally would have to timely file a U.S. tax return or an appropriate claim for refund in order to claim a refund of the overwithheld taxes.
Distributions we pay with respect to our shares will constitute “dividends” for U.S. federal income tax purposes only to the extent of our current and accumulated earnings and profits. Distributions we pay in excess of our earnings and profits will not be treated as “dividends” for U.S. federal income tax purposes; instead, they will be treated first as a tax-free return of capital to the extent of a shareholder’s tax basis in their shares and then as capital gain realized on the sale or exchange of such shares. We may be unable to timely determine the portion of our distributions that is a “dividend” for U.S. federal income tax purposes, which may result in a shareholder’s overpayment of tax with respect to distribution amounts that should have been classified as a tax-free return of capital. In such a case, a shareholder generally would have to timely file an amended U.S. tax return or an appropriate claim for refund in order to obtain a refund of the overpaid tax.
For a U.S. holder of our shares, the IRS Forms 1099-DIV may not be consistent with our determination of the amount that constitutes a “dividend” for U.S. federal income tax purposes or a shareholder may receive a corrected IRS Form 1099-DIV (and may therefore need to file an amended federal, state or local income tax return). We will attempt to timely notify our shareholders of available information to assist with income tax reporting (such as posting the correct information on our website). However, the information that we provide to our shareholders may be inconsistent with the amounts reported by a broker on IRS Form 1099-DIV, and the IRS may disagree with any such information and may make audit adjustments to a shareholder’s tax return.
For a non-U.S. holder of our shares, “dividends” for U.S. federal income tax purposes will be subject to withholding of U.S. federal income tax at a 30% rate (or such lower rate as specified by an applicable income tax treaty) unless the dividends are effectively connected with conduct of a U.S. trade or business. In the event that we are unable to timely determine the portion of our distributions that is a “dividend” for U.S. federal income tax purposes, or a shareholder’s broker or withholding agent chooses to withhold taxes from distributions in a manner inconsistent with our determination of the amount that constitutes a “dividend” for such purposes, a shareholder’s broker or other withholding agent may overwithhold taxes from distributions paid. In such a case, a shareholder generally would have to timely file a U.S. tax return or an appropriate claim for refund in order to obtain a refund of the overwithheld tax.

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ITEM 1B. UNRESOLVED STAFF COMMENTS
Item 1B. Unresolved Staff Comments
None.

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ITEM 2. PROPERTIES

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ITEM 3. LEGAL PROCEEDINGS
Item 3. Legal Proceedings
The information required by this item is included in Note 19 to our Consolidated Financial Statements, and is incorporated herein by reference thereto.

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ITEM 4. MINE SAFETY DISCLOSURE
Item 4. Mine Safety Disclosures
Not applicable.
PART II

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ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY
Item 5. Market for Registrant’s Shares, Related Shareholder Matters and Issuer Purchases of Equity Securities
Market Information, Holders and Distributions
Our Class A shares are listed and traded on The Nasdaq Global Select Market under the symbol “PAGP.” As of February 11, 2021, there were 194,097,504 Class A shares outstanding and approximately 35,000 record holders and beneficial owners (held in street name).
The following table presents cash distributions per Class A share pertaining to the quarter presented, which were declared and paid in the following calendar quarter (see the “Cash Distribution Policy” section below for a discussion of our policy regarding distribution payments):
First Quarter Second Quarter Third Quarter Fourth Quarter
2020 $ 0.18 $ 0.18 $ 0.18 $ 0.18
2019 $ 0.36 $ 0.36 $ 0.36 $ 0.36
Our Class A shares are also used as a form of compensation to our directors. See Note 18 to our Consolidated Financial Statements for additional information regarding our equity-indexed compensation plans.
Our Class B shares and Class C shares are not listed or traded on any stock exchange.
Performance Graph
The following graph compares the total unitholder return performance of our Class A shares with the performance of: (i) the Standard & Poor’s 500 Stock Index (“S&P 500”) and (ii) the Alerian MLP Index. The Alerian MLP Index is a composite of the most prominent energy master limited partnerships that provides investors with a comprehensive benchmark for this asset class. The graph assumes that $100 was invested in our Class A shares and each comparison index beginning on December 31, 2015 and that all distributions were reinvested on a quarterly basis.
12/31/2015 12/31/2016 12/31/2017 12/31/2018 12/31/2019 12/31/2020
PAGP $ 100.00 $ 150.74 $ 102.31 $ 98.75 $ 99.03 $ 48.35
S&P 500 $ 100.00 $ 111.96 $ 136.40 $ 130.42 $ 171.49 $ 203.04
Alerian MLP Index $ 100.00 $ 118.31 $ 110.59 $ 96.86 $ 103.21 $ 73.60
This information shall not be deemed to be “soliciting material” or to be “filed” with the Commission or subject to Regulation 14A or 14C under the Exchange Act, other than as provided in Item 201(e) of Regulation S-K, or to the liabilities of Section 18 of the Exchange Act, and shall not be deemed to be incorporated by reference into any filing under the Securities Act of 1933, as amended, or the Exchange Act, except to the extent that we specifically request that such information be treated as soliciting material or specifically incorporate it by reference into a filing under the Securities Act or the Exchange Act.
Recent Sales of Unregistered Securities
In connection with our IPO and related transactions, the Legacy Owners acquired the following interests (collectively, the “Stapled Interests”): (i) AAP units representing an economic limited partner interest in AAP; (ii) general partner units representing a non-economic membership interest in our general partner; and (iii) Class B shares representing a non-economic limited partner interest in us. The Legacy Owners and any permitted transferees of their Stapled Interests have the right to exchange (the “Exchange Right”) all or a portion of such Stapled Interests for an equivalent number of Class A shares. In connection with the exercise of the Exchange Right, the Stapled Interests are transferred to us and the applicable Class B shares are canceled. Although we issue one Class A share for each Stapled Interest that is exchanged, we also receive one AAP unit and one general partner unit. As a result, the exercise by Legacy Owners of the Exchange Right is not dilutive. During the three months ended December 31, 2020, certain Legacy Owners or their permitted transferees exercised the Exchange Right, which resulted in the issuance of 6,756,970 Class A shares. The issuance of Class A shares in connection with the exercise of the Exchange Rights was exempt from the registration requirements of the Securities Act of 1933, as amended, pursuant to Section 4(a)(2) thereof.
Cash Distribution Policy
Our partnership agreement requires that, within 55 days following the end of each quarter, we distribute all of our available cash to Class A shareholders of record on the applicable record date. Available cash generally means, for any quarter ending prior to liquidation, all cash on hand at the date of determination of available cash for the distribution in respect of such quarter (including expected distributions from AAP in respect of such quarter), less the amount of cash reserves established by our general partner, which will not be subject to a cap, to:
•comply with applicable law or any agreement binding upon us or our subsidiaries (exclusive of PAA and its subsidiaries);
•provide funds for distributions to shareholders;
•provide for future capital expenditures, debt service and other credit needs as well as any federal, state, provincial or other income tax that may affect us in the future; or
•provide for the proper conduct of our business, including with respect to the matters described under our partnership agreement.
Our available cash also includes cash on hand resulting from borrowings made after the end of the quarter.
Our principal sources of cash flow are derived from our indirect investment in PAA. As of December 31, 2020, we directly and indirectly owned approximately 194.1 million AAP units, which represented an approximate 79% limited partner interest in AAP. AAP currently receives all of its cash flows from its ownership of PAA common units. Therefore, our cash flow and resulting ability to make distributions is dependent upon the ability of PAA to make distributions to AAP in respect of the common units AAP owns. As of December 31, 2020, AAP owned approximately 245.8 million PAA common units. The actual amount of cash that PAA, and correspondingly AAP, will have available for distribution will primarily depend on the amount of cash PAA generates from its operations. Also, under the terms of the agreements governing PAA’s debt, PAA is prohibited from declaring or paying any distribution to unitholders if a default or event of default (as defined in such agreements) exists. No such default has occurred. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Liquidity and Capital Resources-Credit Agreements, Commercial Paper Program and Indentures.”
Our general partner owns a non-economic general partner interest in us, which does not entitle it to receive cash distributions.

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ITEM 6. SELECTED FINANCIAL DATA
Item 6. Selected Financial Data
The historical financial information below was derived from our audited Consolidated Financial Statements as of December 31, 2020, 2019, 2018, 2017 and 2016 and for the years then ended.
The selected financial data should be read in conjunction with Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and the Consolidated Financial Statements, including the notes thereto, in Item 8. “Financial Statements and Supplementary Data.”
Year Ended December 31,
2020 2019 2018 2017 2016
(in millions, except per share data)
Statement of operations data:
Total revenues
$ 23,290 $ 33,669 $ 34,055 $ 26,223 $ 20,182
Operating income/(loss) (1)
$ (2,383) $ 1,980 $ 2,272 $ 1,147 $ 990
Net income/(loss) (1) (2)
$ (2,440) $ 2,062 $ 2,107 $ (41) $ 660
Net income/(loss) attributable to PAGP (1) (2)
$ (568) $ 331 $ 334 $ (731) $ 94
Per share data:
Basic net income/(loss) per Class A share (1) (2)
$ (3.06) $ 1.97 $ 2.12 $ (5.03) $ 0.94
Diluted net income/(loss) per Class A share (1) (2)
$ (3.07) $ 1.96 $ 2.12 $ (5.03) $ 0.94
Declared distributions per Class A share (3)
$ 0.90 $ 1.38 $ 1.20 $ 1.95 $ 2.40
Balance sheet data (at end of period):
Property and equipment, net (1) (4)
$ 14,620 $ 15,367 $ 14,802 $ 14,105 $ 13,890
Total assets (1) (5)
$ 25,951 $ 29,969 $ 26,830 $ 26,753 $ 26,103
Long-term debt
$ 9,382 $ 9,187 $ 9,143 $ 9,183 $ 10,124
Long-term operating lease liabilities (5)
$ 317 $ 387 $ - $ - $ -
Total debt
$ 10,213 $ 9,691 $ 9,209 $ 9,920 $ 11,839
Partners’ capital:
Partners’ capital (excluding Noncontrolling interests)
$ 1,464 $ 2,155 $ 1,846 $ 1,695 $ 1,737
Noncontrolling interests
$ 9,726 $ 12,330 $ 11,473 $ 10,663 $ 8,970
Total Partners’ capital
$ 11,190 $ 14,485 $ 13,319 $ 12,358 $ 10,707
Other data:
Net cash provided by operating activities
$ 1,510 $ 2,500 $ 2,604 $ 2,496 $ 718
Net cash used in investing activities
$ (1,093) $ (1,765) $ (813) $ (1,570) $ (1,273)
Net cash provided by/(used in) financing activities
$ (430) $ (717) $ (1,753) $ (940) $ 571
Capital expenditures:
Investment capital
$ 921 $ 1,340 $ 1,888 $ 1,135 $ 1,405
Maintenance capital
$ 216 $ 287 $ 252 $ 247 $ 186
Acquisition capital
$ 310 $ 50 $ - $ 1,323 $ 289
Year Ended December 31,
2020 2019 2018 2017 2016
Volumes (6) (7)
Transportation segment (average daily volumes in thousands of barrels per day):
Tariff activities
6,266 6,805 5,791 5,083 4,523
Trucking
74 88 98 103 114
Transportation segment total volumes
6,340 6,893 5,889 5,186 4,637
Facilities segment:
Liquids storage (average monthly capacity in millions of barrels) (8)
109 110 109 112 107
Natural gas storage (average monthly working capacity in billions of cubic feet)
66 63 66 82 97
NGL fractionation (average volumes in thousands of barrels per day)
129 144 131 126 115
Facilities segment total volumes (average monthly volumes in millions of barrels)
124 125 124 130 127
Supply and Logistics segment (average daily volumes in thousands of barrels per day):
Crude oil lease gathering purchases
1,174 1,162 1,054 945 894
NGL sales
144 207 255 274 259
Supply and Logistics segment total volumes
1,318 1,369 1,309 1,219 1,153
(1)During the year ended December 31, 2020, we recognized impairments of approximately $3.4 billion. See Note 6, Note 7 and Note 8 to our Consolidated Financial Statements for additional information.
(2)During the year ended December 31, 2017, we recorded approximately $823 million related to the re-measurement of our existing deferred tax asset as a result of the reduction in our effective tax rate from the change in corporate federal income tax rate from 35% to 21%. See Note 15 to our Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2017 for additional information.
(3)Represents cash distributions declared and paid per share during the year presented. See Note 12 to our Consolidated Financial Statements for further discussion regarding our distributions.
(4)See Note 7 for discussion of our acquisitions and dispositions completed during the three years ended December 31, 2020.
(5)On January 1, 2019, we adopted Accounting Standards Update 2016-02, Leases (Topic 842) using the optional transitional method. Prior period amounts have not been adjusted and continue to be reported in accordance with our historic accounting under Accounting Standards Codification Topic 840.
(6)Average volumes are calculated as the total volumes (attributable to our interest) for the year divided by the number of days or months in the year.
(7)Facilities segment total volumes are calculated as the sum of: (i) liquids storage capacity; (ii) natural gas storage working capacity divided by 6 to account for the 6:1 thousand cubic feet (“mcf”) of natural gas to crude British thermal unit (“Btu”) equivalent ratio and further divided by 1,000 to convert to monthly volumes in millions; and (iii) NGL fractionation volumes multiplied by the number of days in the year and divided by the number of months in the year.
(8)Includes volumes (attributable to our interest) from facilities owned by unconsolidated entities.

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Introduction
The following discussion is intended to provide investors with an understanding of our financial condition and results of our operations and should be read in conjunction with our historical Consolidated Financial Statements and accompanying notes. Unless the context otherwise requires, references to “we,” “us,” “our,” and “PAGP” are intended to mean the business and operations of PAGP and its consolidated subsidiaries.
Our discussion and analysis includes the following:
•Executive Summary
•Critical Accounting Policies and Estimates
•Recent Accounting Pronouncements
•Results of Operations
•Liquidity and Capital Resources
A comparative discussion of our 2019 to 2018 operating results and performance measures can be found in Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Results of Operations” included in our Annual Report on Form 10-K for the year ended December 31, 2019 filed with the SEC on February 27, 2020.
Executive Summary
Company Overview
We are a Delaware limited partnership formed in 2013 that has elected to be taxed as a corporation for United States federal income tax purposes. As of December 31, 2020, our sole cash-generating assets consisted of (i) a 100% managing member interest in GP LLC, an entity that has also elected to be taxed as a corporation for United States federal income tax purposes and (ii) an approximate 79% limited partner interest in AAP through our direct ownership of approximately 193.1 million AAP units and indirect ownership of approximately 1.0 million AAP units through GP LLC. GP LLC is a Delaware limited liability company that also holds the non-economic general partner interest in AAP. AAP is a Delaware limited partnership that, as of December 31, 2020, directly owned a limited partner interest in PAA through its ownership of approximately 245.8 million PAA common units (approximately 31% PAA’s total outstanding common units and Series A preferred units combined). AAP is the sole member of PAA GP, a Delaware limited liability company that directly holds the non-economic general partner interest in PAA.
PAA’s 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, PAA owns an extensive network of pipeline transportation, terminalling, storage and gathering assets in key crude oil and NGL producing basins (including the Permian Basin) and transportation corridors and at major market hubs in the United States and Canada. PAA’s assets and the services it provides are primarily focused on crude oil, NGL and natural gas. PAA’s business activities are conducted through three operating segments: Transportation, Facilities and Supply and Logistics. See “-Results of Operations-Analysis of Operating Segments” for further discussion.
Recent Events and Outlook
During the first quarter of 2020, COVID-19 escalated into a global pandemic, which led to widespread shelter-in-place or similar requirements throughout North America and across the world, resulting in significantly reduced energy demand. As a result, North American producers responded aggressively by shutting in significant levels of production early in the second quarter, which mitigated the pace of crude oil inventory builds and the risk of testing storage maximums. Subsequently, United States refinery utilization increased, the previously steep contango market structure tempered, and crude oil prices improved to more constructive levels. Over the course of the second half of the year, the more constructive price environment allowed oil and gas producers to return to production wells that were previously shut-in, resume completion activities and begin to increase drilling activities during the third quarter at a level that is lower than pre-pandemic, but likely at a level that is sufficient to offset natural declines.
While prices have rebounded to levels that are near pre-pandemic levels, drilling activity is at a fraction of pre-pandemic levels as evidenced by the Lower 48 rig count, which is approximately 40% of peak levels reached in 2020 pre-COVID-19. Many oil and gas producers in the United States have publicly stated their intention to reduce capital investment in oil and gas drilling activities in 2021 as they strive to improve their financial metrics and increase returns to shareholders. Accordingly, we expect oil and gas drilling activities to continue to be lower than pre-pandemic levels which in turn will slow the growth in oil production, relative to pre-pandemic expectations of production growth. We expect that the combination of a muted growth in production, with excess pipeline capacity in most of our operating areas will have a negative impact on our business relative to pre-pandemic levels, with the impacts in 2021 being more pronounced than in 2020.
Similar to the actions taken by oil and gas producers, we have implemented a number of initiatives, as described below, to ensure that we are positioned to manage through the current challenging market environment. Longer term, we expect global demand for hydrocarbons will recover, which should drive higher production levels in key onshore shale basins, which should support growing demand for our assets. Also see Items 1. and 2. “Business and Properties-Global Petroleum Market Overview and Fundamental Themes” for additional information.
Our response to the challenging near-term market conditions has been to focus on measures to strengthen our balance sheet, liquidity and long-term financial flexibility. These actions include significantly reducing our capital program, reducing the amount of our common equity distributions, progressing asset sales, and reducing costs, while remaining focused on operating safely and responsibly.
Specifically, since April, we have reduced our 2020/2021 capital program by $950 million, or 41%, and have decreased PAA’s common unit distributions and our Class A share distributions by 50% versus the distributions paid in February 2020, which reflects a reduction of $525 million on an annualized basis. We have also completed approximately $450 million of asset sales. While each of these actions should contribute to a stronger balance sheet and enhanced liquidity and long-term financial flexibility, we can provide no assurance that we will be able to effect certain future actions (such as additional capital reductions, asset sales and expense reductions) and additional actions may be necessary to achieve our balance sheet, liquidity and financial security objectives. See “Risk Factors-Risks Related to PAA’s Business” in Item 1A.
While some modifications in our operations have been necessary to deal with risks associated with the COVID-19 pandemic, we have not experienced any material constraints in our ability to continue our essential business functions and have not incurred any significant additional operating costs as a result of the pandemic. We remain focused on the health and safety of our workforce, and have modified our operations in ways that we believe are prudent and appropriate in order to protect our employees while continuing to operate our assets in an effective, safe and responsible manner.
In addition, many governments have enacted or are contemplating measures to provide aid and economic stimulus in response to the COVID-19 pandemic. These measures include actions by both the United States federal government and the government of Canada. There has been no material direct impact to our financial position, results of operations or cash flows resulting from these measures. However, our Canadian subsidiary participated in a wage subsidy program during the second, third and fourth quarters of 2020 for subsidies totaling approximately $23 million. The impact of such subsidies is included in the line items “Field operating costs” and “Segment general and administrative expenses” of the applicable segments. See “-Results of Operations-Analysis of Operating Segments” for further discussion.
Overview of Operating Results, Capital Investments and Other Significant Activities
The macroeconomic and industry specific challenges discussed above have resulted in a number of impairment charges recognized during 2020 as discussed further below. See “-Liquidity and Capital Resources” for additional discussion of the expected and potential impact of COVID-19 and related market conditions on our business.
We recognized a net loss of $2.440 billion for the year ended December 31, 2020 compared to net income of $2.062 billion recognized for the year ended December 31, 2019. The net loss for the period was driven by goodwill impairment losses of $2.515 billion and was also impacted by non-cash impairment charges of approximately $914 million related to the write-down of certain pipeline and other long-lived assets, certain of our investments in unconsolidated entities, and assets upon classification as held for sale. In addition, we recognized approximately $233 million of inventory valuation adjustments due to declines in commodity prices primarily during the first quarter of 2020.
Our results for the comparative period were also impacted by:
•Less favorable results from our Supply and Logistics segment due to less favorable crude oil differentials, lower NGL margins and the unfavorable impact of the mark-to-market of certain derivative instruments, resulting in higher losses recognized in 2020 compared to 2019, partially offset by the favorable impact of contango market conditions during 2020;
•Less favorable results from our Transportation segment driven by lower volumes from shut-ins of crude oil production, reduced drilling and completion activity and compressed regional basis differentials, a portion of which are covered by minimum volume commitments that will be made up or paid for in future periods, and lower pipeline loss allowance revenue in 2020 due to lower prices and volumes, partially offset by lower field operating costs;
•Higher depreciation and amortization expense in the 2020 period primarily due to additional depreciation expense associated with acquired assets, the completion of various investment capital projects and a reduction in the useful lives of certain assets;
•A gain of $21 million recognized in the current period related to the sale of a portion of our interest in Saddlehorn Pipeline Company, LLC in February 2020, compared to a non-cash gain of $269 million recognized in the 2019 period related to a fair value adjustment resulting from the accounting for the contribution of our undivided joint interest in the Capline pipeline system for an equity interest in Capline Pipeline Company LLC; partially offset by
•Favorable results from our Facilities segment primarily due to lower field operating costs; and
•The favorable impact on income tax expense of (i) lower income attributable to PAGP as a result of lower earnings at PAA and (ii) lower taxable earnings and lower year-over-year income as impacted by fluctuations in the derivative mark-to-market valuations in our Canadian operations.
See further discussion of our operating results in the “-Results of Operations-Analysis of Operating Segments” and “-Other Income and Expenses” sections below.
We invested $921 million in midstream infrastructure projects during 2020, which primarily related to projects under development in the Permian Basin. See “-Liquidity and Capital Resources-Investing Activities-Investment Capital Projects” for additional information. Additionally, during the first quarter of 2020, we acquired $310 million of assets, which primarily included a crude oil gathering system located in the Delaware Basin.
We also paid approximately $863 million of cash distributions to our Class A Shareholders and noncontrolling interests during 2020.
In June 2020, PAA completed the issuance of $750 million, 3.80% senior notes due September 2030. We used the net proceeds from this offering of $742 million, after deducting the underwriting discount and offering expenses, to repay the principal amounts of PAA’s 5.00% senior notes due February 2021 in November 2020. See “-Liquidity and Capital Resources-Financing Activities-Senior Notes” for additional information.
During the fourth quarter of 2020, PAA repurchased 6.6 million common units for $53 million, which includes repurchases of 350,000 common units for $3 million that did not settle until January 2021. See “-Liquidity and Capital Resources-Financing Activities-Common Equity Repurchase Program” for additional information.
Critical Accounting Policies and Estimates
The preparation of financial statements in conformity with GAAP and rules and regulations of the SEC requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities, as well as the disclosure of contingent assets and liabilities, at the date of the financial statements. Such estimates and assumptions also affect the reported amounts of revenues and expenses during the reporting period. Although we believe these estimates are reasonable, actual results could differ from these estimates. On a regular basis, we evaluate our assumptions, judgments and estimates. We also discuss our critical accounting policies and estimates with the Audit Committee of the Board of Directors.
We believe that the assumptions, judgments and estimates involved in the accounting for our (i) estimated fair value of assets and liabilities acquired and identification of associated goodwill and intangible assets, (ii) impairment assessments of goodwill and intangible assets, (iii) fair value of derivatives, (iv) accruals and contingent liabilities, (v) property and equipment, depreciation and amortization expense and asset retirement obligations, (vi) impairment assessments of property and equipment and investments in unconsolidated entities and (vii) inventory valuations have the greatest potential impact on our Consolidated Financial Statements. These areas are key components of our results of operations and are based on complex rules which require us to make judgments and estimates. Therefore, we consider these to be our critical accounting policies and estimates, which are discussed further as follows. For further information on all of our significant accounting policies, see Note 2 to our Consolidated Financial Statements.
Fair Value of Assets and Liabilities Acquired and Identification of Associated Goodwill and Intangible Assets. In accordance with Financial Accounting Standards Board (“FASB”) guidance regarding business combinations, with each acquisition, we allocate the cost of the acquired entity to the assets and liabilities assumed based on their estimated fair values at the date of acquisition. If the initial accounting for the business combination is incomplete when the combination occurs, an estimate will be recorded. We also expense the transaction costs as incurred in connection with each acquisition, except for acquisitions of equity method investments. In addition, we are required to recognize intangible assets separately from goodwill.
Determining the fair value of assets and liabilities acquired, as well as intangible assets that relate to such items as customer relationships, acreage dedications and other contracts, involves professional judgment and is ultimately based on acquisition models and management’s assessment of the value of the assets acquired and, to the extent available, third-party assessments.
Impairment Assessments of Goodwill and Intangible Assets. Goodwill and intangible assets with indefinite lives are not amortized but are instead periodically assessed for impairment. Intangible assets with finite lives are amortized over their estimated useful life as determined by management. See Note 8 and Note 10 to our Consolidated Financial Statements for further discussion of goodwill and intangible assets.
Impairment testing entails estimating future net cash flows relating to the business, based on management’s estimate of future revenues, future cash flows and market conditions including pricing, demand, competition, operating costs and other factors. Uncertainties associated with these estimates include changes in production decline rates, production interruptions, fluctuations in refinery capacity or product slates, economic obsolescence factors in the area and potential future sources of cash flow. In addition, changes in our weighted average cost of capital from our estimates could have a significant impact on fair value. We cannot provide assurance that actual amounts will not vary significantly from estimated amounts. Resolutions of these uncertainties have resulted, and in the future may result, in impairments that impact our results of operations and financial condition.
Fair Value of Derivatives. The fair value of a derivative at a particular period end does not reflect the end results of a particular transaction, and will most likely not reflect the gain or loss at the conclusion of a transaction. We reflect estimates for these items based on our internal records and information from third parties. We have commodity derivatives, interest rate derivatives and foreign currency derivatives that are accounted for as assets and liabilities at fair value on our Consolidated Balance Sheets. The valuations of our derivatives that are exchange traded are based on market prices on the applicable exchange on the last day of the period. For our derivatives that are not exchange traded, the estimates we use are based on indicative broker quotations or an internal valuation model. Our valuation models utilize market observable inputs such as price, volatility, correlation and other factors and may not be reflective of the price at which they can be settled due to the lack of a liquid market. Less than 1% of total annual revenues are based on estimates derived from internal valuation models.
We also have embedded derivatives that are recorded at fair value on our Consolidated Balance Sheets. These embedded derivatives are valued using models that contain inputs, some of which involve management judgment.
Although the resolution of the uncertainties involved in these estimates has not historically had a material impact on our results of operations or financial condition, we cannot provide assurance that actual amounts will not vary significantly from estimated amounts. See Item 7A. Quantitative and Qualitative Disclosures About Market Risk and Note 13 to our Consolidated Financial Statements for a discussion regarding our derivatives and risk management activities.
Accruals and Contingent Liabilities. We record accruals or liabilities for, among other things, environmental remediation, potential legal claims or settlements and fees for legal services associated with loss contingencies, and bonuses. Accruals are made when our assessment indicates that it is probable that a liability has occurred and the amount of liability can be reasonably estimated. Our estimates are based on all known facts at the time and our assessment of the ultimate outcome. Among the many uncertainties that impact our estimates are the necessary regulatory approvals for, and potential modification of, our environmental remediation plans, the limited amount of data available upon initial assessment of the impact of soil or water contamination, changes in costs associated with environmental remediation services and equipment, the duration of the natural resource damage assessment and the ultimate amount of damages determined, the determination and calculation of fines and penalties, the possibility of existing legal claims giving rise to additional claims and the nature, extent and cost of legal services that will be required in connection with lawsuits, claims and other matters. Our estimates for contingent liability accruals are increased or decreased as additional information is obtained or resolution is achieved. A hypothetical variance of 5% in our aggregate estimate for the accruals and contingent liabilities discussed above would have an impact on earnings of up to approximately $19 million. Although the resolution of these uncertainties has not historically had a material impact on our results of operations or financial condition, we cannot provide assurance that actual amounts will not vary significantly from estimated amounts.
Property and Equipment, Depreciation and Amortization Expense and Asset Retirement Obligations. We compute depreciation and amortization using the straight-line method based on estimated useful lives. These estimates are based on various factors including condition, manufacturing specifications, technological advances and historical data concerning useful lives of similar assets. Uncertainties that impact these estimates include changes in laws and regulations relating to restoration and abandonment requirements, economic conditions and supply and demand in the area. When assets are put into service, we make estimates with respect to useful lives and salvage values that we believe are reasonable. However, subsequent events could cause us to change our estimates, thus impacting the future calculation of depreciation and amortization.
We record retirement obligations associated with tangible long-lived assets based on estimates related to the costs associated with cleaning, purging and, in some cases, completely removing the assets and returning the land to its original state. In addition, our estimates include a determination of the settlement date or dates for the potential obligation, which may or may not be determinable. Uncertainties that impact these estimates include the costs associated with these activities and the timing of incurring such costs.
Impairment Assessments of Property and Equipment and Investments in Unconsolidated Entities. We periodically evaluate property and equipment for impairment when events or circumstances indicate that the carrying value of these assets may not be recoverable. Any evaluation is highly dependent on the underlying assumptions of related cash flows. We consider the fair value estimate used to calculate impairment of property and equipment a critical accounting estimate. In determining the existence of an impairment of carrying value, we make a number of subjective assumptions as to:
•whether there is an event or circumstance that may be indicative of an impairment;
•the grouping of assets;
•the intention of “holding”, “abandoning” or “selling” an asset;
•the forecast of undiscounted expected future cash flow over the asset’s estimated useful life; and
•if an impairment exists, the fair value of the asset or asset group.
In addition, when we evaluate property and equipment and other long-lived assets for recoverability, it may also be necessary to review related depreciation estimates and methods.
Investments in unconsolidated entities accounted for under the equity method of accounting are assessed for impairment when events or circumstances suggest that a decline in value may be other than temporary. Examples of such events or circumstances include continuing operating losses of the entity and/or long-term negative changes in the entity’s core business. When it is determined that an indicated impairment is other than temporary, a charge is recognized for the difference between the investment’s carrying amount and its estimated fair value. We consider the fair value estimate used to calculate the impairment of investments in unconsolidated entities a critical accounting estimate. In determining the existence of an other-than-temporary impairment of carrying value, we make a number of subjective assumptions as to:
•whether there is an event or circumstance that may be indicative of a decline in value of the investment;
•whether the decline in value is other than temporary; and
•the fair value of the investment.
A change in our outlook or use could result in impairments that may be material to our results of operations or financial condition. See “-Executive Summary- Recent Events and Outlook” and Note 6 and Note 9 to our Consolidated Financial Statements for additional information.
Inventory Valuations. Inventory, including long-term inventory, primarily consists of crude oil and NGL and is valued at the lower of cost or net realizable value, with cost determined using an average cost method within specific inventory pools. At the end of each reporting period, we assess the carrying value of our inventory and use estimates and judgment when making any adjustments necessary to reduce the carrying value to net realizable value. Among the uncertainties that impact our estimates are the applicable quality and location differentials to include in our net realizable value analysis. Additionally, we estimate the upcoming liquidation timing of the inventory. Changes in assumptions made as to the timing of a sale can materially impact net realizable value. During the years ended December 31, 2020, 2019 and 2018, we recorded charges of $233 million, $11 million and $8 million, respectively, related to the valuation adjustment of our crude oil inventory due to declines in prices. See Note 5 to our Consolidated Financial Statements for further discussion regarding inventory.
Recent Accounting Pronouncements
See Note 2 to our Consolidated Financial Statements for information regarding the effect of recent accounting pronouncements on our Consolidated Financial Statements.
Results of Operations
The following table sets forth an overview of our consolidated financial results calculated in accordance with GAAP (in millions, except per share amounts):
Year Ended December 31, Variance
2020 2019 $ %
Transportation Segment Adjusted EBITDA (1)
$ 1,616 $ 1,722 $ (106) (6) %
Facilities Segment Adjusted EBITDA (1)
731 705 26 4 %
Supply and Logistics Segment Adjusted EBITDA (1)
210 803 (593) (74) %
Adjustments:
Depreciation and amortization of unconsolidated entities (73) (62) (11) (18) %
Selected items impacting comparability - Segment Adjusted EBITDA (617) (163) (454) **
Unallocated general and administrative expenses
(5) (5) - - %
Depreciation and amortization (656) (604) (52) (9) %
Gains/(losses) on asset sales and asset impairments, net (719) (28) (691) **
Goodwill impairment losses (2,515) - (2,515) N/A
Gain on/(impairment of) investments in unconsolidated entities, net
(182) 271 (453) (167) %
Interest expense, net (436) (425) (11) (3) %
Other income, net 39 24 15 63 %
Income tax (expense)/benefit 167 (176) 343 195 %
Net income/(loss) (2,440) 2,062 (4,502) (218) %
Net (income)/loss attributable to noncontrolling interests 1,872 (1,731) 3,603 208 %
Net income/(loss) attributable to PAGP $ (568) $ 331 $ (899) (272) %
Basic net income/(loss) per Class A share
$ (3.06) $ 1.97 $ (5.03) **
Diluted net income/(loss) per Class A share
$ (3.07) $ 1.96 $ (5.03) **
Basic weighted average Class A shares outstanding
186 168 18 **
Diluted weighted average Class A shares outstanding
246 170 76 **
** Indicates that variance as a percentage is not meaningful.
(1)Segment Adjusted EBITDA is the measure of segment performance that is utilized by our Chief Operating Decision Maker (“CODM”) to assess performance and allocate resources among our operating segments. This measure is adjusted for certain items, including those that our CODM believes impact comparability of results across periods. See Note 21 to our Consolidated Financial Statements for additional discussion of such adjustments.
Non-GAAP Financial Measures
To supplement our financial information presented in accordance with GAAP, management uses additional measures known as “non-GAAP financial measures” in its evaluation of past performance and prospects for the future.
The primary additional measure used by management is earnings before interest, taxes, depreciation and amortization (including our proportionate share of depreciation and amortization of unconsolidated entities), gains and losses on asset sales and asset impairments, goodwill impairment losses and gains on and impairments of investments in unconsolidated entities, adjusted for certain selected items impacting comparability (“Adjusted EBITDA”).
Our definition and calculation of certain non-GAAP financial measures may not be comparable to similarly-titled measures of other companies. Adjusted EBITDA is reconciled to Net Income/(Loss), the most directly comparable measure as reported in accordance with GAAP, and should be viewed in addition to, and not in lieu of, our Consolidated Financial Statements and accompanying notes.
Management believes that the presentation of such additional financial measure provides useful information to investors regarding our performance and results of operations because this measure, when used to supplement related GAAP financial measures, (i) provide additional information about our core operating performance, (ii) provide investors with the same financial analytical framework upon which management bases financial, operational, compensation and planning/budgeting decisions and (iii) present measurements that investors, rating agencies and debt holders have indicated are useful in assessing us and our results of operations. This non-GAAP measure may exclude, for example, (i) charges for obligations that are expected to be settled with the issuance of equity instruments, (ii) gains and losses on derivative instruments that are related to underlying activities in another period (or the reversal of such adjustments from a prior period), gains and losses on derivatives that are related to investing activities (such as the purchase of linefill) and inventory valuation adjustments, as applicable, (iii) long-term inventory costing adjustments, (iv) items that are not indicative of our core operating results and business outlook and/or (v) other items that we believe should be excluded in understanding our core operating performance. This measure may further be adjusted to include amounts related to deficiencies associated with minimum volume commitments whereby we have billed the counterparties for their deficiency obligation and such amounts are recognized as deferred revenue in “Other current liabilities” in our Consolidated Financial Statements. Such amounts are presented net of applicable amounts subsequently recognized into revenue. We have defined all such items as “selected items impacting comparability.” We do not necessarily consider all of our selected items impacting comparability to be non-recurring, infrequent or unusual, but we believe that an understanding of these selected items impacting comparability is material to the evaluation of our operating results and prospects.
Although we present selected items impacting comparability that management considers in evaluating our performance, you should also be aware that the items presented do not represent all items that affect comparability between the periods presented. Variations in our operating results are also caused by changes in volumes, prices, exchange rates, mechanical interruptions, acquisitions, divestitures, investment capital projects and numerous other factors as discussed, as applicable, in “-Analysis of Operating Segments.”
The following table sets forth the reconciliation of our non-GAAP financial performance measure Adjusted EBITDA from Net Income/(Loss) (in millions):
Year Ended December 31, Variance
2020 2019 $ %
Net income/(loss) $ (2,440) $ 2,062 $ (4,502) (218) %
Add/(Subtract):
Interest expense, net 436 425 11 3 %
Income tax expense/(benefit) (167) 176 (343) (195) %
Depreciation and amortization 656 604 52 9 %
(Gains)/losses on asset sales and asset impairments, net 719 28 691 **
Goodwill impairment losses 2,515 - 2,515 N/A
(Gain on)/impairment of investments in unconsolidated entities, net 182 (271) 453 167 %
Depreciation and amortization of unconsolidated entities (1)
73 62 11 18 %
Selected Items Impacting Comparability:
Losses from derivative activities net of inventory valuation adjustments (2)
480 160 320 **
Long-term inventory costing adjustments (3)
44 (20) 64 **
Deficiencies under minimum volume commitments, net (4)
74 (18) 92 **
Equity-indexed compensation expense (5)
19 17 2 **
Net (gain)/loss on foreign currency revaluation (6)
(3) 14 (17) **
Line 901 incident (7)
- 10 (10) **
Significant acquisition-related expenses (8)
3 - 3 **
Selected Items Impacting Comparability - Segment Adjusted EBITDA 617 163 454 **
Gains from derivative activities (2)
(20) (2) (18) **
Net gain on foreign currency revaluation (6)
(13) (15) 2 **
Net gain on early repayment of senior notes (9)
(3) - (3) **
Selected Items Impacting Comparability - Adjusted EBITDA (10)
581 146 435 **
Adjusted EBITDA (10)
$ 2,555 $ 3,232 $ (677) (21) %
** Indicates that variance as a percentage is not meaningful.
(1)Over the past several years, we have increased our participation in strategic pipeline joint ventures accounted for under the equity method of accounting. We exclude our proportionate share of the depreciation and amortization expense of such unconsolidated entities when reviewing Adjusted EBITDA, similar to our consolidated assets.
(2)We use derivative instruments for risk management purposes, and our related processes include specific identification of hedging instruments to an underlying hedged transaction. Although we identify an underlying transaction for each derivative instrument we enter into, there may not be an accounting hedge relationship between the instrument and the underlying transaction. In the course of evaluating our results of operations, we identify the earnings that were recognized during the period related to derivative instruments for which the identified underlying transaction does not occur in the current period and exclude the related gains and losses in determining Adjusted EBITDA. In addition, we exclude gains and losses on derivatives that are related to investing activities, such as the purchase of linefill. We also exclude the impact of corresponding inventory valuation adjustments, as applicable. See Note 13 to our Consolidated Financial Statements for a comprehensive discussion regarding our derivatives and risk management activities.
(3)We carry crude oil and NGL inventory that is comprised of minimum working inventory requirements in third-party assets and other working inventory that is needed for our commercial operations. We consider this inventory necessary to conduct our operations and we intend to carry this inventory for the foreseeable future. Therefore, we classify this inventory as long-term on our balance sheet and do not hedge the inventory with derivative instruments (similar to linefill in our own assets). We treat the impact of changes in the average cost of the long-term inventory (that result from fluctuations in market prices) and write-downs of such inventory that result from price declines as a selected item impacting comparability. See Note 5 to our Consolidated Financial Statements for additional inventory disclosures.
(4)We, and certain of our equity method investments, have certain agreements that require counterparties to deliver, transport or throughput a minimum volume over an agreed upon period. Substantially all of such agreements were entered into with counterparties to economically support the return on our capital expenditure necessary to construct the related asset. Some of these agreements include make-up rights if the minimum volume is not met. We record a receivable from the counterparty in the period that services are provided or when the transaction occurs, including amounts for deficiency obligations from counterparties associated with minimum volume commitments. If a counterparty has a make-up right associated with a deficiency, we defer the revenue attributable to the counterparty’s make-up right and subsequently recognize the revenue at the earlier of when the deficiency volume is delivered or shipped, when the make-up right expires or when it is determined that the counterparty’s ability to utilize the make-up right is remote. We include the impact of amounts billed to counterparties for their deficiency obligation, net of applicable amounts subsequently recognized into revenue, as a selected item impacting comparability. We believe the inclusion of the contractually committed revenues associated with that period is meaningful to investors as the related asset has been constructed, is standing ready to provide the committed service and the fixed operating costs are included in the current period results.
(5)Our total equity-indexed compensation expense includes expense associated with awards that will or may be settled in PAA common units and awards that will or may be settled in cash. The awards that will or may be settled in PAA common units are included in PAA’s diluted net income per unit calculation when the applicable performance criteria have been met. We consider the compensation expense associated with these awards as a selected item impacting comparability as the dilutive impact of the outstanding awards is included in PAA’s diluted net income per unit calculation, as applicable, and the majority of the awards are expected to be settled in PAA common units. The portion of compensation expense associated with awards that are certain to be settled in cash is not considered a selected item impacting comparability. See Note 18 to our Consolidated Financial Statements for a discussion regarding our equity-indexed compensation plans.
(6)During the periods presented, there were fluctuations in the value of the Canadian dollar (“CAD”) to the U.S. dollar (“USD”), resulting in the realization of foreign exchange gains and losses on the settlement of foreign currency transactions as well as the revaluation of monetary assets and liabilities denominated in a foreign currency. These gains and losses are not integral to our core operating performance and were thus classified as a selected item impacting comparability. See Note 13 to our Consolidated Financial Statements for discussion regarding our currency exchange rate risk hedging activities.
(7)Includes costs recognized during the period related to the Line 901 incident that occurred in May 2015, net of amounts we believe are probable of recovery from insurance. See Note 19 to our Consolidated Financial Statements for additional information regarding the Line 901 incident.
(8)Includes acquisition-related expenses associated with the acquisition of Felix Midstream LLC (“Felix Midstream”) in February 2020. See Note 7 to our Consolidated Financial Statements for additional information.
(9)Includes net gains recognized in connection with the repurchase of our outstanding senior notes on the open market. See Note 11 to our Consolidated Financial Statements for additional information.
(10)Other income/(expense), net per our Consolidated Statements of Operations, adjusted for selected items impacting comparability (“Adjusted other income/(expense), net”) is included in Adjusted EBITDA and excluded from Segment Adjusted EBITDA.
Analysis of Operating Segments
We manage our operations through three operating segments: Transportation, Facilities and Supply and Logistics. Our CODM (our Chief Executive Officer) evaluates segment performance based on a variety of measures including Segment Adjusted EBITDA, segment volumes, Segment Adjusted EBITDA per barrel and maintenance capital investment.
We define Segment Adjusted EBITDA as revenues and equity earnings in unconsolidated entities less (a) purchases and related costs, (b) field operating costs and (c) segment general and administrative expenses, plus our proportionate share of the depreciation and amortization expense of unconsolidated entities, and further adjusted for certain selected items including (i) the mark-to-market of derivative instruments that are related to underlying activities in another period (or the reversal of such adjustments from a prior period), gains and losses on derivatives that are related to investing activities (such as the purchase of linefill) and inventory valuation adjustments, as applicable, (ii) long-term inventory costing adjustments, (iii) charges for obligations that are expected to be settled with the issuance of equity instruments, (iv) amounts related to deficiencies associated with minimum volume commitments, net of applicable amounts subsequently recognized into revenue and (v) other items that our CODM believes are integral to understanding our core segment operating performance. See Note 21 to our Consolidated Financial Statements for a reconciliation of Segment Adjusted EBITDA to Net income/(loss) attributable to PAGP.
Our segment analysis involves an element of judgment relating to the allocations between segments. In connection with its operations, the Supply and Logistics segment secures transportation and facilities services from our other two segments as well as third-party service providers under month-to-month and multi-year arrangements. Intersegment transportation service rates are conducted at posted tariff rates, rates similar to those charged to third parties or rates that we believe approximate market. Facilities segment services are also obtained at rates generally consistent with rates charged to third parties for similar services. Intersegment activities are eliminated in consolidation and we believe that the estimates with respect to these rates are reasonable. Also, our segment operating and general and administrative expenses reflect direct costs attributable to each segment; however, we also allocate certain operating expenses and general and administrative overhead expenses between segments based on management’s assessment of the business activities for the period. The proportional allocations by segment require judgment by management and may be adjusted in the future based on the business activities that exist during each period. We believe that the estimates with respect to these allocations are reasonable.
Revenues and expenses from our Canadian based subsidiaries, which use CAD as their functional currency, are translated at the prevailing average exchange rates for the month.
Transportation Segment
Our Transportation segment operations generally consist of fee-based activities associated with transporting crude oil and NGL on pipelines, gathering systems and trucks. The Transportation segment generates revenue through a combination of tariffs, pipeline capacity agreements and other transportation fees. Tariffs and other fees on our pipeline systems vary by receipt point and delivery point. The segment results generated by our tariff and other fee-related activities depend on the volumes transported on the pipeline and the level of the tariff and other fees charged, as well as the fixed and variable field costs of operating the pipeline.
The following tables set forth our operating results from our Transportation segment:
Operating Results (1)
(in millions, except per barrel data)
Year Ended December 31, Variance
2020 2019 $ %
Revenues $ 2,020 $ 2,320 $ (300) (13) %
Purchases and related costs (229) (244) 15 6 %
Field operating costs (584) (700) 116 17 %
Segment general and administrative expenses (2)
(98) (104) 6 6 %
Equity earnings in unconsolidated entities 350 388 (38) (10) %
Adjustments (3):
Depreciation and amortization of unconsolidated entities 71 61 10 16 %
Losses from derivative activities, net of inventory valuation adjustments 1 - 1 **
Deficiencies under minimum volume commitments, net 71 (18) 89 **
Equity-indexed compensation expense 11 9 2 **
Line 901 incident - 10 (10) **
Significant acquisition-related expenses 3 - 3 **
Segment Adjusted EBITDA $ 1,616 $ 1,722 $ (106) (6) %
Maintenance capital $ 136 $ 161 $ (25) (16) %
Segment Adjusted EBITDA per barrel $ 0.70 $ 0.68 $ 0.02 3 %
Average Daily Volumes
(in thousands of barrels per day) (4)
Year Ended December 31, Variance
2020 2019 Volumes %
Tariff activities volumes
Crude oil pipelines (by region):
Permian Basin (5)
4,427 4,690 (263) (6) %
South Texas / Eagle Ford (5)
380 446 (66) (15) %
Central (5)
379 498 (119) (24) %
Gulf Coast 134 165 (31) (19) %
Rocky Mountain (5)
245 293 (48) (16) %
Western 223 198 25 13 %
Canada 294 323 (29) (9) %
Crude oil pipelines 6,082 6,613 (531) (8) %
NGL pipelines 184 192 (8) (4) %
Tariff activities total volumes 6,266 6,805 (539) (8) %
Trucking volumes 74 88 (14) (16) %
Transportation segment total volumes 6,340 6,893 (553) (8) %
** Indicates that variance as a percentage is not meaningful.
(1)Revenues and costs and expenses include intersegment amounts.
(2)Segment general and administrative expenses reflect direct costs attributable to each segment and an allocation of other expenses to the segments. The proportional allocations by segment require judgment by management and are based on the business activities that exist during each period.
(3)Represents adjustments included in the performance measure utilized by our CODM in the evaluation of segment results. See Note 21 to our Consolidated Financial Statements for additional discussion of such adjustments.
(4)Average daily volumes are calculated as the total volumes (attributable to our interest) for the year divided by the number of days in the year.
(5)Region includes volumes (attributable to our interest) from pipelines owned by unconsolidated entities.
The following is a discussion of items impacting Transportation segment operating results for the periods indicated.
Revenues, Purchases and Related Costs, Equity Earnings in Unconsolidated Entities and Volumes. The following table presents variances in revenues, purchases and related costs and equity earnings in unconsolidated entities by region:
Favorable/(Unfavorable) Variance
2020-2019
(in millions) Revenues Purchases and Related Costs Equity Earnings
Crude oil pipelines
Permian Basin region $ (104) $ (17) $ 31
South Texas / Eagle Ford region (12) - (26)
Central region (33) (2) (21)
Rocky Mountain region (5) - (24)
Canada region (26) - -
Other regions, NGL pipelines, trucking and pipeline loss allowance revenue (120) 34 2
Total variance $ (300) $ 15 $ (38)
•COVID-19 Impact. The destruction of demand for refined products, and therefore crude oil, caused by COVID-19 created a supply and demand imbalance in the crude oil markets for a portion of 2020 in all of our operating regions. This imbalance pushed crude oil prices to historically low levels, including negative values for at least one day in April 2020. In turn, these factors caused U.S. and Canadian producers to respond by quickly curtailing their crude oil production as well as their drilling and completion activities. These actions led to a decline of onshore, lower 48 U.S. oil production by approximately 1.4 million barrels of crude oil per day between February and May of 2020, according to the information provided by the EIA, and adversely impacted transportation volumes on our pipelines.
•Permian Basin region. Revenues, net of purchases and related costs, (“net revenues”) decreased by $121 million for the year ended December 31, 2020 compared to the year ended December 31, 2019. This decrease was primarily due to lower long-haul pipeline movements to Cushing, Oklahoma and Corpus Christi, Texas due to compressed regional basis differentials, as well as lower volumes on our intra-basin pipelines that feed our long-haul pipelines, partially offset by increased volumes on our gathering pipelines, almost half of which was attributable to the Felix Midstream system we acquired in February 2020. Some shippers on the long-haul pipelines to Cushing and Corpus Christi have under-delivered relative to their minimum volume commitments; however, the earnings related to these volume shortfalls will not be recognized until future periods when either the shortfall is made up or when the shipper’s make-up rights expire or it is determined that their ability to utilize the make-up right is remote. Such deficiencies are reflected as an “Adjustment” in the table above as discussed further below under “-Adjustments: Deficiencies under minimum volume commitments, net.”
The increase in equity earnings over the comparative period was primarily from our 65% interest in the Cactus II pipeline, which was placed in service in August 2019, partially offset by lower equity earnings from our 20% interest in the BridgeTex pipeline primarily due to lower volumes.
•South Texas / Eagle Ford region. The decrease in revenues for the year ended December 31, 2020 compared to the year ended December 31, 2019 was due to lower volumes, primarily related to lower production.
Equity earnings from our 50% interest in the Eagle Ford pipeline decreased for the year ended December 31, 2020 compared to the year ended December 31, 2019 due to a combination of lower joint tariff volumes from the Permian Basin via our Cactus I pipeline, and to a lesser extent, lower regional receipts. Similar to some shippers in the Permian Basin region, certain shippers on the Eagle Ford pipeline have under-delivered relative to their minimum volume commitments and the earnings related to these volume shortfalls will not be recognized until future periods. Such deficiencies are reflected as an “Adjustment” in the table above as discussed further below under “-Adjustments: Deficiencies under minimum volume commitments, net.”
•Central region. The decrease in net revenues for the year ended December 31, 2020 compared to the year ended December 31, 2019 was primarily due to a decrease in crude oil production in the region. This is also a region with a meaningful amount of excess pipeline capacity, which exacerbates the impact to our assets in this region.
The decrease in equity earnings for the year ended December 31, 2020 compared to the year ended December 31, 2019 was primarily due to the impact of refinery downtime on certain of the demand pull pipelines out of Cushing, Oklahoma, in which we own a 50% interest.
•Rocky Mountain region. Equity earnings decreased for the year ended December 31, 2020 compared to the year ended December 31, 2019 primarily due to a combination of (i) lower crude oil volumes, partially offset by higher NGL volumes, (ii) lower tariff rates due to the expiration of certain long-term contracts and (iii) the sale of 25% of our interest in Saddlehorn in February 2020.
•Canada region. The decrease in revenues for the year ended December 31, 2020 compared to the year ended December 31, 2019 was primarily due to decreased crude oil production in the areas serviced by our pipelines.
•Other regions, NGL pipelines, trucking and pipeline loss allowance revenue. The decrease in other net revenues for the year ended December 31, 2020 compared to the year ended December 31, 2019 was primarily due to lower pipeline loss allowance revenue due to a combination of both lower prices and volumes in 2020. To a lesser extent, lower net revenues from our trucking activities due to less favorable market conditions in 2020 contributed to the decrease. Additionally, volumes in our Gulf Coast region were impacted by a decrease in throughput on a lower tariff pipeline, which did not result in a significant impact on revenue.
Adjustments: Deficiencies under minimum volume commitments, net. Many industry infrastructure projects developed and completed over the last several years were underpinned by long-term minimum volume commitment contracts whereby the shipper agreed to either: (i) ship and pay for certain stated volumes or (ii) pay the agreed upon price for a minimum contract quantity. Some of these agreements include make-up rights if the minimum volume is not met. If a counterparty has a make-up right associated with a deficiency, we bill the counterparty and defer the revenue attributable to the counterparty’s make-up right but record an adjustment to reflect such amount associated with the current period activity in Segment Adjusted EBITDA. We subsequently recognize the revenue, and record a corresponding reversal of the adjustment, at the earlier of when the deficiency volume is delivered or shipped, when the make-up right expires or when it is determined that the counterparty’s ability to utilize the make-up right is remote.
For the year ended December 31, 2020, amounts billed to counterparties exceeded revenue recognized during the period that was previously deferred. For the year ended December 31, 2019, the recognition of previously deferred revenue exceeded amounts billed to counterparties associated with deficiencies under minimum volume commitments.
Field Operating Costs. The decrease in field operating costs for the year ended December 31, 2020 compared to the year ended December 31, 2019 was primarily due to (i) a decrease in variable costs due to lower volumes, (ii) a decrease of maintenance activities, primarily due to timing changes, (iii) lower equity-based compensation costs on liability-classified awards (which are not included as an “Adjustment” in the table above) due to a decrease in our common unit price, (iv) reductions in compensation costs, primarily due to the benefit of wage subsidies received by our Canadian subsidiary and (v) additional estimated costs recognized in 2019 associated with the Line 901 incident (which impact field operating costs but are excluded from Segment Adjusted EBITDA and thus are reflected as an “Adjustment” in the table above). Such favorable impacts were partially offset by higher property taxes attributable to assets placed in service in 2020 and increased property valuations.
Segment General and Administrative Expenses. The decrease in segment general and administrative expenses for the year ended December 31, 2020 compared to the year ended December 31, 2019 was primarily due to (i) lower equity-based compensation costs on liability-classified awards (which are not included as an “Adjustment” in the table above), due to a decrease in our common unit price, (ii) decreased travel and entertainment costs and (iii) the benefit of wage subsidies received by our Canadian subsidiary. Such items were partially offset by an overall increase in compensation costs related to severance costs associated with our efforts to streamline our organization.
Maintenance Capital. Maintenance capital consists of capital expenditures for the replacement and/or refurbishment of partially or fully depreciated assets in order to maintain the operating and/or earnings capacity of our existing assets. The decrease in maintenance capital for the year ended December 31, 2020 compared to the year ended December 31, 2019 was due to timing changes, the completion of multi-year reliability improvement programs and application of updated regulatory guidance, among other factors.
Facilities Segment
Our Facilities segment operations generally consist of fee-based activities associated with providing storage, terminalling and throughput services primarily for crude oil, NGL and natural gas, as well as NGL fractionation and isomerization services and natural gas and condensate processing services. The Facilities segment generates revenue through a combination of month-to-month and multi-year agreements.
The following tables set forth our operating results from our Facilities segment:
Operating Results (1)
(in millions, except per barrel data)
Year Ended December 31, Variance
2020 2019 $ %
Revenues $ 1,138 $ 1,171 $ (33) (3) %
Purchases and related costs (15) (15) - - %
Field operating costs (316) (360) 44 12 %
Segment general and administrative expenses (2)
(84) (83) (1) (1) %
Equity earnings in unconsolidated entities 5 - 5 N/A
Adjustments (3):
Depreciation and amortization of unconsolidated entities
2 1 1 **
Gains from derivative activities
(5) (13) 8 **
Deficiencies under minimum volume commitments, net
2 - 2 **
Equity-indexed compensation expense
4 4 - **
Segment Adjusted EBITDA
$ 731 $ 705 $ 26 4 %
Maintenance capital
$ 51 $ 97 $ (46) (47) %
Segment Adjusted EBITDA per barrel
$ 0.49 $ 0.47 $ 0.02 4 %
Year Ended December 31, Variance
Volumes (4)
2020 2019 Volumes %
Liquids storage (average monthly capacity in millions of barrels) (5)
109 110 (1) (1) %
Natural gas storage (average monthly working capacity in billions of cubic feet) 66 63 3 5 %
NGL fractionation (average volumes in thousands of barrels per day) 129 144 (15) (10) %
Facilities segment total volumes (average monthly volumes in millions of barrels) (6)
124 125 (1) (1) %
** Indicates that variance as a percentage is not meaningful.
(1)Revenues and costs and expenses include intersegment amounts.
(2)Segment general and administrative expenses reflect direct costs attributable to each segment and an allocation of other expenses to the segments. The proportional allocations by segment require judgment by management and are based on the business activities that exist during each period.
(3)Represents adjustments included in the performance measure utilized by our CODM in the evaluation of segment results. See Note 21 to our Consolidated Financial Statements for additional discussion of such adjustments.
(4)Average monthly volumes are calculated as total volumes for the year divided by the number of months in the year.
(5)Includes volumes (attributable to our interest) from facilities owned by unconsolidated entities.
(6)Facilities segment total volumes are calculated as the sum of: (i) liquids storage capacity; (ii) natural gas storage working capacity divided by 6 to account for the 6:1 mcf of natural gas to crude Btu equivalent ratio and further divided by 1,000 to convert to monthly volumes in millions; and (iii) NGL fractionation volumes multiplied by the number of days in the year and divided by the number of months in the year.
The following is a discussion of items impacting Facilities segment operating results.
Revenues, Purchases and Related Costs and Volumes. Variances in revenues, purchases and related costs, and average monthly volumes were primarily driven by the following:
•Rail Terminals. Revenues from our rail terminals decreased by $33 million for the year ended December 31, 2020 compared to the year ended December 31, 2019, primarily due to decreased activity at certain of our rail terminals resulting from less favorable market conditions, as well as lower volumes due to voluntary shut-ins and curtailments of crude oil production by producers.
•NGL Operations. Revenues from our NGL operations decreased by $21 million for the year ended December 31, 2020 compared to the year ended December 31, 2019, primarily due to the sale of certain NGL terminals in the fourth quarter of 2019 and the second quarter of 2020, net unfavorable foreign exchange impacts of approximately $4 million and lower revenues from our NGL processing facilities. Such unfavorable impacts were partially offset by the favorable impact of the receipt of a deficiency payment in 2020 of approximately $20 million upon the expiration of a multi-year contract.
•Natural Gas and Condensate Processing. Net revenues from our U.S. natural gas and condensate processing operations decreased by $11 million for the year ended December 31, 2020 compared to the year ended December 31, 2019 primarily due to the unfavorable impact of a $5 million payment to resolve a contractual dispute as well as a decrease in condensate processing volumes and rates.
•Crude Oil Storage. Revenues from our crude oil storage operations increased by $33 million for the year ended December 31, 2020 compared to the year ended December 31, 2019, primarily due to the addition of an aggregate of approximately 3 million barrels of storage capacity at our Cushing, Oklahoma, St. James, Louisiana and Midland, Texas terminals and increased activity at certain of our Mid-Continent terminals. Additionally, the unfavorable impact on revenues from the sale of our Los Angeles Basin terminals in October 2020 was largely offset by increased spot activity at certain of these terminals during the first three quarters of 2020.
The increase in equity earnings over the comparative period was from our 50% interest in Eagle Ford Terminals, which owns a crude oil storage facility in Corpus Christi, Texas that was placed in service in September of 2019.
Field Operating Costs. The decrease in field operating costs for the year ended December 31, 2020 compared to the year ended December 31, 2019 was primarily due to (i) lower maintenance activities due to timing changes, (ii) reduced activity at our rail terminals and the divestiture of certain NGL terminals, (iii) reductions in compensation costs including the benefit of wage subsidies received by our Canadian subsidiary and (iv) lower property taxes. Such favorable impacts were partially offset by lower mark-to-market gains in the current period on fuel hedges (which impacts field operating costs but are excluded from Segment Adjusted EBITDA and thus are reflected as an “Adjustment” in the table above).
Maintenance Capital. The decrease in maintenance capital spending for the year ended December 31, 2020 compared to the year ended December 31, 2019 was primarily due to timing changes, the impact of asset sales, the completion of multi-year reliability improvement programs and application of updated regulatory guidance, among other factors.
Supply and Logistics Segment
Revenues from our Supply and Logistics segment activities reflect the sale of gathered and bulk-purchased crude oil, as well as sales of NGL volumes. Generally, our segment results are impacted by (i) increases or decreases in our Supply and Logistics segment volumes (which consist of lease gathering crude oil purchases volumes and NGL sales volumes), (ii) the overall strength, weakness and volatility of market conditions, including regional differentials, and (iii) the effects of competition on our lease gathering and NGL margins. In addition, the execution of our risk management strategies in conjunction with our assets can provide upside in certain markets.
The following tables set forth our operating results from our Supply and Logistics segment:
Operating Results (1)
(in millions, except per barrel data)
Year Ended December 31, Variance
2020 2019 $ %
Revenues $ 22,059 $ 32,276 $ (10,217) (32) %
Purchases and related costs (22,099) (31,276) 9,177 29 %
Field operating costs (191) (258) 67 26 %
Segment general and administrative expenses (2)
(89) (110) 21 19 %
Adjustments (3):
Losses from derivative activities net of inventory valuation adjustments 484 173 311 **
Long-term inventory costing adjustments 44 (20) 64 **
Deficiencies under minimum volume commitments, net 1 - 1 **
Equity-indexed compensation expense 4 4 - **
Net (gain)/loss on foreign currency revaluation (3) 14 (17) **
Segment Adjusted EBITDA $ 210 $ 803 $ (593) (74) %
Maintenance capital $ 29 $ 29 $ - - %
Segment Adjusted EBITDA per barrel $ 0.43 $ 1.61 $ (1.18) (73) %
Average Daily Volumes (4)
(in thousands of barrels per day)
Year Ended December 31, Variance
2020 2019 Volume %
Crude oil lease gathering purchases 1,174 1,162 12 1 %
NGL sales 144 207 (63) (30) %
Supply and Logistics segment total volumes 1,318 1,369 (51) (4) %
** Indicates that variance as a percentage is not meaningful.
(1)Revenues and costs include intersegment amounts.
(2)Segment general and administrative expenses reflect direct costs attributable to each segment and an allocation of other expenses to the segments. The proportional allocations by segment require judgment by management and are based on the business activities that exist during each period.
(3)Represents adjustments included in the performance measure utilized by our CODM in the evaluation of segment results. See Note 21 to our Consolidated Financial Statements for additional discussion of such adjustments.
(4)Average daily volumes are calculated as the total volumes for the period divided by the number of days in the period.
The following table presents the range of the NYMEX West Texas Intermediate (“WTI”) benchmark price of crude oil (in dollars per barrel):
NYMEX WTI
Crude Oil Price
During the Year Ended December 31, Low High
2020 $ (38) $ 63
2019 $ 46 $ 66
Our crude oil and NGL supply, logistics and distribution operations are not directly affected by the absolute level of prices. Because the commodities that we buy and sell are generally indexed to the same pricing indices for both sales and purchases, revenues and costs related to purchases will fluctuate with market prices. However, the margins related to those sales and purchases will not necessarily have a corresponding increase or decrease. Additionally, net revenues are impacted by net gains and losses from certain derivative activities during the periods.
Our NGL operations are sensitive to weather-related demand, particularly during the approximate five-month peak heating season of November through March, and temperature differences from period-to-period may have a significant effect on NGL demand and thus our financial performance.
Segment Adjusted EBITDA and Volumes. The following summarizes the significant items impacting our Supply and Logistics Segment Adjusted EBITDA:
•Crude Oil Operations. Net revenues from our crude oil operations decreased for year ended December 31, 2020 compared to the year ended December 31, 2019, primarily due to a combination of (i) less favorable crude oil differentials, particularly the differential between the value of crude oil in the Permian Basin compared to the Gulf Coast market and (ii) the impact of lower volumes in higher margin areas, partially offset by volume increases in lower margin areas. Such unfavorable impacts were partially offset by the favorable impact of contango market conditions during the last three quarters of 2020.
•NGL Operations. Net revenues from our NGL operations decreased for the year ended December 31, 2020 compared to the year ended December 31, 2019, primarily due to (i) warmer weather during the fourth quarter of 2020, (ii) weaker fractionation spreads between the price of natural gas and the extracted NGL, (iii) lower border flows through our straddle plants and (iv) the absence of the favorable impact from certain non-recurring items recorded in the second quarter of 2019.
•Impact from Certain Derivative Activities, Net of Inventory Valuation Adjustments. The impact from certain derivative activities on our net revenues includes mark-to-market and other gains and losses resulting from certain derivative instruments that are related to underlying activities in another period (or the reversal of mark-to-market gains and losses from a prior period), losses on derivatives that are related to investing activities (such as the purchase of linefill) and inventory valuation adjustments, as applicable. See Note 13 to our Consolidated Financial Statements for a comprehensive discussion regarding our derivatives and risk management activities. These gains and losses impact our net revenues but are excluded from Segment Adjusted EBITDA and thus are reflected as an “Adjustment” in the table above.
•Long-Term Inventory Costing Adjustments. Our net revenues are impacted by changes in the weighted average cost of our crude oil and NGL inventory pools that result from price movements during the periods. These costing adjustments related to long-term inventory necessary to meet our minimum inventory requirements in third-party assets and other working inventory that was needed for our commercial operations. We consider this inventory necessary to conduct our operations and we intend to carry this inventory for the foreseeable future. These costing adjustments impact our net revenues but are excluded from Segment Adjusted EBITDA and thus are reflected as an “Adjustment” in the table above.
•Foreign Exchange Impacts. Our net revenues are impacted by fluctuations in the value of CAD to USD, resulting in foreign exchange gains and losses on U.S. denominated net assets within our Canadian operations. These non-cash gains and losses impact our net revenues but are excluded from Segment Adjusted EBITDA and thus are reflected as an “Adjustment” in the table above.
•Field Operating Costs. The decrease in field operating costs for the year ended December 31, 2020 compared to the year ended December 31, 2019 was primarily driven by a decrease in long-haul third-party trucking costs and a decrease in company personnel and truck costs as more of our supply was connected to pipelines and taken off trucks.
•Segment General and Administrative Expenses. The decrease in segment general and administrative expenses for the year ended December 31, 2020 compared to the year ended December 31, 2019 was primarily driven by (i) lower compensation costs including the benefit of wage subsidies received by our Canadian subsidiary, (ii) decreased travel and entertainment costs, (iii) a decrease in equity-based compensation costs on liability-classified awards (which are not included as an “Adjustment” in the table above) due to a decrease in our common unit price and (iv) general cost reductions associated with exiting low margin, high administrative cost businesses.
Other Income and Expenses
Depreciation and Amortization
Depreciation and amortization expense increased for the year ended December 31, 2020 compared to the year ended December 31, 2019 largely driven by additional depreciation expense associated with acquired assets, the completion of various investment capital projects and a reduction in the useful lives of certain assets.
Gains/Losses on Asset Sales and Asset Impairments, Net
The net loss on asset sales and asset impairments for the year ended December 31, 2020 included (i) non-cash impairment losses on held and used assets of approximately $541 million related to the write-down of (a) certain pipeline and other long-lived assets due to the current macroeconomic and geopolitical conditions including the collapse of oil prices driven by both the decrease in demand caused by the COVID-19 pandemic and excess supply, as well as changing market conditions and expected lower crude oil production in certain regions, and (b) idled or underutilized assets for which is it has been determined that it is unlikely that opportunities will exist in the future to recover our investment in these assets and (ii) net losses of approximately $178 million related to the sale of assets, including non-cash impairments recognized upon classification to assets held for sale.
The net loss on asset sales and asset impairments for the year ended December 31, 2019 was largely driven by a loss on the sale of a storage terminal in North Dakota. See Note 6 and Note 7 to our Consolidated Financial Statements for additional information regarding these asset impairments.
Goodwill Impairment Losses
During the first quarter of 2020, we recognized a goodwill impairment charge of $2.5 billion, representing the entire balance of goodwill. See Note 8 to our Consolidated Financial Statements for additional information.
Gain on/(Impairment of) Investments in Unconsolidated Entities, Net
During the year ended December 31, 2020, we recognized losses of $202 million related to the write-down of certain of our investments in unconsolidated entities. Additionally, we recognized a gain of $21 million related to our sale of a 10% interest in Saddlehorn Pipeline Company, LLC.
During the year ended December 31, 2019, we recognized a non-cash gain of $269 million related to a fair value adjustment resulting from the accounting for the contribution of our undivided joint interest in the Capline pipeline system for an equity interest in Capline Pipeline Company LLC. See Note 9 to our Consolidated Financial Statements for additional information regarding our unconsolidated entities.
Interest Expense
Interest expense is primarily impacted by:
•our weighted average debt balances;
•the level and maturity of fixed rate debt and interest rates associated therewith;
•market interest rates and our interest rate hedging activities; and
•interest capitalized on capital projects.
The following table summarizes the components impacting the interest expense variance (in millions, except percentages):
Average
LIBOR
Weighted Average
Interest Rate (1)
Interest expense for the year ended December 31, 2019
$ 425 2.2 % 4.4 %
Impact of lower capitalized interest 10
Impact of borrowings under credit facilities and PAA commercial paper program 3
Impact of issuance and retirement of PAA senior notes (4)
Other 2
Interest expense for the year ended December 31, 2020 $ 436 0.5 % 4.1 %
(1)Excludes commitment and other fees.
Interest expense increased for the year ended December 31, 2020 compared to the year ended December 31, 2019 primarily due to (i) a higher weighted average debt balance during 2020 driven by higher commercial paper and credit facility borrowings and (ii) lower capitalized interest in the 2020 period resulting from fewer capital projects under construction, partially offset by (iii) the impact from lower weighted average rates.
See Note 11 to our Consolidated Financial Statements for additional information regarding our debt activities during the periods presented.
Other Income, Net
The following table summarizes the components impacting Other income/(expense), net (in millions):
Year Ended December 31,
2020 2019
Gain related to mark-to-market adjustment of our Preferred Distribution Rate Reset Option (1)
$ 20 $ 2
Net gain on foreign currency revaluation (2)
13 15
Other 6 7
$ 39 $ 24
(1)See Note 13 to our Consolidated Financial Statements for additional information.
(2)The activity during 2020 was primarily related to the impact from the change in the USD to CAD exchange rate on the portion of our intercompany net investment that is not long-term in nature.
Income Tax (Expense)/Benefit
The decrease in current income tax expense for the year ended December 31, 2020 compared to the year ended December 31, 2019 was primarily due to lower taxable earnings from our Canadian operations. The increase in the deferred income tax benefit for the year ended December 31, 2020 compared to the year ended December 31, 2019 was primarily due to (i) the impact of lower earnings at PAA on income attributable to PAGP and (ii) lower year-over-year income as impacted by fluctuations in the derivative mark-to-market valuations in our Canadian operations, partially offset by the recognition of a deferred tax benefit of approximately $60 million during the second quarter of 2019 as a result of the reduction of the provincial tax rate in Alberta, Canada.
Liquidity and Capital Resources
General
Our primary sources of liquidity are (i) cash flow from operating activities (ii) borrowings under PAA’s credit facilities or commercial paper program and (iii) funds received from sales of equity and debt securities. In addition, we may supplement these sources of liquidity with proceeds from our divestiture program. Our primary cash requirements include, but are not limited to, (i) ordinary course of business uses, such as the payment of amounts related to the purchase of crude oil, NGL and other products, other expenses and interest payments on outstanding debt, (ii) investment and maintenance capital activities, (iii) acquisitions of assets or businesses, (iv) repayment of principal on long-term debt and (v) distributions to our Class A shareholders and noncontrolling interests. In addition, we may use cash for repurchases of common equity. We generally expect to fund our short-term cash requirements through cash flow generated from operating activities and/or borrowings under PAA’s commercial paper program or credit facilities. In addition, we generally expect to fund our long-term needs, such as those resulting from investment capital activities or acquisitions and refinancing long-term debt, through a variety of sources (either separately or in combination), which may include the sources mentioned above as funding for short-term needs and/or the issuance of additional equity or debt securities and the sale of assets.
As of December 31, 2020, although we had a working capital deficit of $587 million, we had approximately $2.2 billion of liquidity available to meet our ongoing operating, investing and financing needs, subject to continued covenant compliance, as noted below (in millions):
As of
December 31, 2020
Availability under PAA senior unsecured revolving credit facility (1) (2)
$ 1,507
Availability under PAA senior secured hedged inventory facility (1) (2)
1,197
Amounts outstanding under PAA commercial paper program (547)
Subtotal
2,157
Cash and cash equivalents
Total
$ 2,182
(1)Represents availability prior to giving effect to borrowings outstanding under the PAA commercial paper program, which reduce available capacity under the facilities.
(2)Available capacity under the PAA senior unsecured revolving credit facility and the PAA senior secured hedged inventory facility was reduced by outstanding letters of credit of $93 million and $36 million, respectively.
Usage of PAA’s credit facilities, which provide the financial backstop for PAA’s commercial paper program, is subject to ongoing compliance with covenants, as discussed further below. PAA’s borrowing capacity and borrowing costs are also impacted by its credit rating. See Item 1A. “Risk Factors-Risks Related to PAA’s Business-Loss of PAA’s investment grade credit rating or the ability to receive open credit could negatively affect its borrowing costs, ability to purchase crude oil, NGL and natural gas supplies or to capitalize on market opportunities.”
Current macroeconomic and geopolitical conditions including the collapse of oil prices driven by both the decrease in demand caused by the COVID-19 pandemic and excess supply has caused liquidity issues impacting many energy companies; however, we believe that we have, and will continue to have, the ability to access PAA’s commercial paper program and credit facilities, which we use to meet our short-term cash needs. We believe that our financial position remains strong and we have sufficient liquid assets, cash flow from operating activities and borrowing capacity under PAA’s credit agreements to meet our financial commitments, debt service obligations, contingencies and anticipated capital expenditures; however, extended disruptions in the financial markets and/or energy price volatility that adversely affect our business may have a materially adverse effect on our financial condition, results of operations or cash flows. See Item 1A. “Risk Factors” for further discussion regarding risks that may impact our liquidity and capital resources.
Credit Agreements, Commercial Paper Program and Indentures
PAA has three primary credit arrangements, which we use to meet our short-term cash needs. These include PAA’s $1.6 billion senior unsecured revolving credit facility maturing in 2024, $1.4 billion senior secured hedged inventory facility maturing in 2022 (excluding aggregate commitments of $45 million, which mature in 2021) and $3.0 billion unsecured commercial paper program that is backstopped by PAA’s revolving credit facility and its hedged inventory facility. Additionally, PAA has two $100 million term loans. The credit agreements for PAA’s revolving credit facilities (which impact PAA’s ability to access its commercial paper program because they provide the financial backstop that supports PAA’s short-term credit ratings) and PAA’s term loans and the indentures governing its senior notes contain cross-default provisions. A default under PAA’s credit agreements or indentures would permit the lenders to accelerate the maturity of the outstanding debt. As long as PAA is in compliance with the provisions in its credit agreements, its ability to make distributions of available cash is not restricted. PAA was in compliance with the covenants contained in its credit agreements and indentures as of December 31, 2020.
Cash Flow from Operating Activities
The primary drivers of cash flow from operating activities are (i) the collection of amounts related to the sale of crude oil, NGL and other products, the transportation of crude oil and other products for a fee, and the provision of storage and terminalling services for a fee and (ii) the payment of amounts related to the purchase of crude oil, NGL and other products and other expenses, principally field operating costs, general and administrative expenses and interest expense.
Cash flow from operating activities can be materially impacted by the storage of crude oil in periods of a contango market, when the price of crude oil for future deliveries is higher than current prices. In the month we pay for the stored crude oil, we borrow under the PAA credit facilities or commercial paper program (or use cash on hand) to pay for the crude oil, which negatively impacts operating cash flow. Conversely, cash flow from operating activities increases during the period in which we collect the cash from the sale of the stored crude oil. Similarly, the level of NGL and other product inventory stored and held for resale at period end affects our cash flow from operating activities.
In periods when the market is not in contango, we typically sell our crude oil during the same month in which we purchase it and we do not rely on borrowings under the PAA credit facilities or commercial paper program to pay for the crude oil. During such market conditions, our accounts payable and accounts receivable generally move in tandem as we make payments and receive payments for the purchase and sale of crude oil in the same month, which is the month following such activity. In periods during which we build inventory, regardless of market structure, we may rely on the PAA credit facilities or commercial paper program to pay for the inventory. In addition, we use derivative instruments to manage the risks associated with the purchase and sale of our commodities. Therefore, our cash flow from operating activities may be impacted by the margin deposit requirements related to our derivative activities. See Note 13 to our Consolidated Financial Statements for a discussion regarding our derivatives and risk management activities.
Net cash provided by operating activities for the years ended December 31, 2020, 2019 and 2018 was approximately $1.5 billion, $2.5 billion and $2.6 billion, respectively, and primarily resulted from earnings from our operations. Additionally, as discussed further below, changes during these periods in our inventory levels and associated margin balances required as part of our hedging activities impacted our cash flow from operating activities.
During 2020, we increased the volume of both our crude oil inventory to be stored during the contango market and our NGL inventory in anticipation of the 2020-2021 heating season as well as the margin balances required as part of our hedging activities, all of which was funded by short-term debt. The cash outflows associated with these activities were partially offset by lower prices for inventory purchased and stored at the end of the current period compared to the end of 2019. Cash provided by operating activities was favorably impacted by cash received for transactions for which the revenue has been deferred pending the completion of future performance obligations. See Note 3 to our Consolidated Financial Statements for additional information.
During 2019, our cash provided by operating activities was positively impacted by the proceeds from the sale of NGL and crude oil inventory that we held and also by the lower weighted average price of NGL inventory compared to prior year amounts.
During 2018, our cash provided by operating activities was favorably impacted by approximately $250 million of cash received for transactions for which the revenue has been deferred pending the completion of future performance obligations. The favorable impact was partially offset by an increase in the volume of crude oil inventory that we held, which was funded from earnings from our operations and proceeds from asset sales.
Investing Activities
In addition to our operating needs discussed above, we also use cash for our investment capital projects, maintenance capital activities and acquisition activities. Historically, we have financed these expenditures primarily with cash generated by operating activities discussed in “-Cash Flow from Operating Activities” above and the financing activities discussed in “-Financing Activities” below. In recent years, we have also used proceeds from our divestiture program, as discussed further below. We have made and will continue to make capital expenditures for investment capital projects, maintenance activities and acquisitions. However, in the near term, we do not plan to issue common equity to fund such activities.
Capital Expenditures
The following table summarizes our expenditures for acquisition capital, investment capital and maintenance capital (in millions):
Year Ended December 31,
2020 2019 2018
Investment capital (1) (2) (3)
$ 921 $ 1,340 $ 1,888
Maintenance capital (1)
216 287 252
Acquisition capital (4)
310 50 -
$ 1,447 $ 1,677 $ 2,140
(1)Capital expenditures made to expand the existing operating and/or earnings capacity of our assets are classified as “Investment capital.” Capital expenditures for the replacement and/or refurbishment of partially or fully depreciated assets in order to maintain the operating and/or earnings capacity of our existing assets are classified as “Maintenance capital.”
(2)“Investment capital” was previously termed “expansion capital.” We consider the term “investment capital” to be more descriptive.
(3)Includes contributions to unconsolidated entities, accounted for under the equity method of accounting, related to investment capital projects by such entities.
(4)Acquisition capital for 2020 primarily includes a crude oil gathering system located in the Delaware Basin.
Investment Capital Projects
Our investment capital programs consist of investments in midstream infrastructure projects that build upon our core assets and operations. For the years presented, substantially all of the investment capital was invested in our fee-based Transportation and Facilities segments. The majority of this investment capital consists of highly-contracted projects that complement our broader system capabilities and support the long-term needs of the upstream and downstream sectors of the industry value chain. The following table summarizes our investment in capital projects (in millions):
Year Ended December 31,
Projects 2020 2019 2018
Permian Basin Takeaway Pipeline Projects (1) (2)
$ 292 $ 440 $ 880
Complementary Permian Basin Projects (1)
200 503 671
Long-Haul Pipeline Projects (Non-Permian) (1)
195 98 20
Selected Facilities/Downstream Projects (3)
115 93 62
Other Projects 119 206 255
Total $ 921 $ 1,340 $ 1,888
(1)These projects will continue into 2021. See “-2021 Investment Capital Projects below.”
(2)Represents pipeline projects with takeaway capacity out of the Permian Basin, including (i) our 16% interest in Wink to Webster Pipeline and (ii) our 65% interest in the Cactus II Pipeline.
(3)Includes projects at our St. James and Cushing terminals.
2021 Investment Capital Projects. In April 2020, in response to the current dynamic and uncertain market conditions, we announced our plan to significantly reduce and continue to challenge our capital program. The majority of our 2021 investment capital program will be invested in our fee-based Transportation and Facilities segments. We expect that our investments will have minimal contributions to our 2021 results, but will provide growth for 2022 and beyond. Our 2021 capital program includes the following projects as of February 2021 with the estimated cost for the entire year (in millions):
Projects 2021
Permian Basin Takeaway Pipeline Projects $ 140
Long-Haul Pipeline Projects (Non-Permian) 115
Complementary Permian Basin Projects 85
Selected Facilities/Downstream Projects 50
Other Projects 35
Total Projected 2021 Investment Capital $ 425
Divestitures
We continue to evaluate potential sales of non-core assets and/or sales of partial interests in assets to strategic joint venture partners. The following table summarizes the proceeds received for sales of such assets, which were previously reported in our Transportation and Facilities segments:
Year Ended December 31,
2020 2019 2018
Proceeds from divestitures (1)
$ 451 $ 205 $ 1,334
(1)Includes proceeds from (i) a multi-year supply agreement related to the sale of certain NGL terminals in April 2020 and (ii) our formation of Red River Pipeline Company LLC in May 2019. See Note 7 and Note 12 to our Consolidated Financial Statements for additional information.
Proceeds from asset sales were used to fund our investment capital projects and reduce debt levels. See Note 7 to our Consolidated Financial Statements for additional detail regarding our divestiture transactions.
Ongoing Activities Related to Strategic Transactions
We are continuously engaged in the evaluation of potential transactions that support our current business strategy. While in the past such transactions have included acquisitions and large capital projects, consistent with our current strategic focus on capital discipline, leverage reduction, portfolio optimization and free cash flow generation, we are currently primarily focused on evaluating whether we should (i) sell assets that we regard as non-core or that we believe might be a better fit with the business and/or assets of a third-party buyer or (ii) sell partial interests in assets to strategic joint venture partners, in each case to optimize our asset portfolio and strengthen our balance sheet and leverage metrics. With respect to a potential divestiture, we may also conduct an auction process or may negotiate a transaction with one or a limited number of potential buyers. Such transactions could involve assets that, if sold or put into a joint venture or joint ownership arrangement, could have a material effect on our financial condition and results of operations.
We typically do not announce a transaction until after we have executed a definitive agreement. However, in certain cases in order to protect our business interests or for other reasons, we may defer public announcement of a transaction until closing or a later date. Past experience has demonstrated that discussions and negotiations regarding a potential transaction can advance or terminate in a short period of time. Moreover, the closing of any transaction for which we have entered into a definitive agreement may be subject to customary and other closing conditions, which may not ultimately be satisfied or waived. Accordingly, we can give no assurance that our current or future efforts with respect to any such transactions will be successful, and we can provide no assurance that our financial expectations with respect to such transactions will ultimately be realized. See Item 1A. “Risk Factors-Risks Related to PAA’s Business-Divestitures, joint ventures, joint ownership arrangements and acquisitions involve risks that may adversely affect PAA’s business.”
Financing Activities
Our financing activities primarily relate to funding investment capital projects, acquisitions and refinancing of debt maturities, as well as short-term working capital (including borrowings for NYMEX and ICE margin deposits) and hedged inventory borrowings related to our NGL business and contango market activities.
Borrowings and Repayments Under Credit Arrangements
During the year ended December 31, 2020, we had net borrowings under the PAA credit facilities and commercial paper program of $296 million. The net borrowings resulted primarily from borrowings during the period related to funding needs for inventory purchases and general partnership purposes.
During the year ended December 31, 2019, we had net borrowings under the PAA credit facilities and commercial paper program of $418 million. The net borrowings resulted primarily from borrowings during the period related to funding needs for general partnership purposes.
During the year ended December 31, 2018, we had net repayments on the PAA credit facilities and commercial paper program of $901 million. The net repayments resulted primarily from cash flow from operating activities and proceeds from asset sales, which offset borrowings during the period related to funding needs for capital investments, inventory purchases and other general partnership purposes.
In August 2018, PAA entered into an agreement for two $100 million term loans from the remarketing of its two $100 million bonds. The purchasers of the two term loans have the right to put, at par, the term loans in July 2023. The bonds mature by their terms in May 2032 and August 2035, respectively. See Note 11 to our Consolidated Financial Statements for additional information.
Senior Notes
Issuances of PAA Senior Notes. During 2020 and 2019, PAA issued senior unsecured notes as summarized in the table below (in millions):
Year Description Maturity Face Value Gross
Proceeds(1)
Net
Proceeds(2)
2020 3.80% Senior Notes issued at 99.794% of face value September 2030 $ 750 $ 748 $ 742 (3)
2019 3.55% Senior Notes issued at 99.801% of face value December 2029 $ 1,000 $ 998 $ 989 (4)
(1)Face value of notes less the applicable premium or discount (before deducting for initial purchaser discounts, commissions and offering expenses).
(2)Face value of notes less the applicable premium or discount, initial purchaser discounts, commissions and offering expenses.
(3)PAA used the net proceeds from the offering to repay the principal amounts of its 5.00% senior notes due February 2021.
(4)PAA used the net proceeds from the offering to partially repay the principal amounts of its 2.60% senior notes due December 2019 and 5.75% senior notes due January 2020 and for general partnership purposes.
Repayments of PAA Senior Notes. During 2020 and 2019, PAA repaid the following senior unsecured notes in full (in millions):
Year Description Repayment Date
2020 $600 million 5.00% Senior Notes due February 2021 November 2020 (1)
2019 $500 million 2.60% Senior Notes due December 2019 November 2019 (2)
2019 $500 million 5.75% Senior Notes due January 2020 December 2019 (2)
(1)PAA repaid these senior notes with proceeds from its 3.80% senior notes issued in June 2020 and cash on hand.
(2)PAA repaid these senior notes with proceeds from its 3.55% senior notes issued in September 2019 and cash on hand.
Additionally, during the year ended December 31, 2020, PAA repurchased $17 million of its outstanding senior notes on the open market and recognized a gain of $3 million on these transactions.
Registration Statements
PAGP Registration Statements. We have filed with the SEC a shelf registration statement that, subject to effectiveness at the time of use, allows us to issue up to an aggregate of $939 million of equity securities (“PAGP Traditional Shelf”). At December 31, 2020, we had approximately $939 million of unsold securities available under the PAGP Traditional Shelf. We also have access to a universal shelf registration statement (“PAGP WKSI Shelf”), which provides us with the ability to offer and sell an unlimited amount of equity securities, subject to market conditions and its capital needs. We did not conduct any offerings under the PAGP Traditional Shelf or PAGP WKSI Shelf during the years ended December 31, 2020, 2019 or 2018.
PAA Registration Statements. PAA periodically accesses the capital markets for both equity and debt financing. PAA has filed with the SEC a universal shelf registration statement that, subject to effectiveness at the time of use, allows PAA to issue up to an aggregate of $1.1 billion of debt or equity securities (“PAA Traditional Shelf”). PAA did not conduct any offerings under the PAA Traditional Shelf during the years ended December 31, 2020, 2019 or 2018. At December 31, 2020, PAA had approximately $1.1 billion of unsold securities available under the PAA Traditional Shelf. PAA also has access to a universal shelf registration statement (“PAA WKSI Shelf”), which provides it with the ability to offer and sell an unlimited
amount of debt and equity securities, subject to market conditions and capital needs. The offering of PAA’s $750 million, 3.80% senior notes in June 2020 was conducted under the PAA WKSI Shelf.
Common Equity Repurchase Program
In November 2020, the board of directors of our general partner approved a $500 million common equity repurchase program (the “Program”) to be utilized as an additional method of returning capital to investors. The Program authorizes the repurchase from time to time of up to $500 million of PAA’s common units and/or our Class A shares via open market purchases or negotiated transactions conducted in accordance with applicable regulatory requirements. Ultimately, the amount, timing and pace of potential repurchase activity will be determined by a number of factors, including market conditions, PAA’s financial performance and flexibility, PAA’s actual and expected Free Cash Flow after distributions, the absolute and relative equity prices of PAA’s common units and our Class A shares, and the extent to which PAA is positioned to achieve and maintain its targeted leverage ratio. No time limit has been set for completion of the Program, and the Program may be suspended or discontinued at any time. The Program does not obligate PAA or us to acquire a particular number of common units or Class A shares. Any PAA common units or Class A shares that are repurchased will be canceled.
PAA repurchased 6.2 million common units under the Program through open market purchases that settled during the year ended December 31, 2020. The total purchase price of these repurchases was $50 million, including commissions and fees. The remaining available capacity under the Program as of December 31, 2020 was $450 million. Additionally, PAA repurchased 350,000 common units under the Program for $3 million through open market purchases at the end of December 2020 that settled in January 2021.
Distributions to Our Class A Shareholders
We distribute 100% of our available cash to our Class A shareholders of record within 55 days following the end of each quarter. Available cash is generally defined as all of our cash and cash equivalents on hand at the end of each quarter less reserves established in the discretion of our general partner for future requirements. Our levels of financial reserves are established by our general partner and include reserves for the proper conduct of our business (including future capital expenditures and anticipated credit needs), compliance with law or contractual obligations and funding of future distributions to our shareholders. See Item 5. “Market for Registrant’s Shares, Related Shareholder Matters and Issuer Purchases of Equity Securities-Cash Distribution Policy” for additional discussion regarding available cash and distributions.
In response to the challenging near-term market conditions, we took steps to further strengthen our balance sheet, liquidity and long-term financial flexibility. In this regard, beginning with the May 2020 distribution, PAA’s distribution per common unit and our distribution per Class A share were reduced by 50% versus the distributions paid in February 2020, which reflects a reduction of $525 million on an annualized basis. See “-Executive Summary-Recent Events and Outlook” for further discussion.
On February 12, 2021, we paid a quarterly distribution of $0.18 per Class A share ($0.72 per Class A share on an annualized basis). See Note 12 to our Consolidated Financial Statements for details of distributions paid during the three years ended December 31, 2020.
Distributions to Noncontrolling Interests
Distributions to noncontrolling interests represent amounts paid on interests in consolidated entities that are not owned by us. As of December 31, 2020, noncontrolling interests in our subsidiaries consisted of (i) limited partner interests in PAA including a 69% interest in PAA’s common units and PAA’s Series A preferred units combined and 100% of PAA’s Series B preferred units, (ii) an approximate 21% limited partner interest in AAP and (iii) a 33% interest in Red River Pipeline Company LLC.
Distributions to PAA’s Series A preferred unitholders. Holders of PAA’s Series A preferred units are entitled to receive quarterly distributions, subject to customary anti-dilution adjustments, of $0.525 per unit ($2.10 per unit annualized). Subject to certain limitations, following January 28, 2021, the holders of PAA’s Series A preferred units may make a one-time election to reset the distribution rate. See Note 12 to our Consolidated Financial Statements for additional information.
Distributions to PAA’s Series B preferred unitholders. Holders of PAA’s Series B preferred units are entitled to receive, when, as and if declared by PAA’s general partner out of legally available funds for such purpose, cumulative cash distributions, as applicable. Through and including November 15, 2022, holders are entitled to a distribution equal to $61.25 per unit per year, payable semiannually in arrears on the 15th day of May and November. See Note 12 to our Consolidated Financial Statements for further discussion of PAA’s Series B preferred units, including distribution rates and payment dates after November 15, 2022.
Distributions to PAA’s common unitholders. On February 12, 2021, PAA paid a quarterly distribution of $0.18 per common unit ($0.72 per common unit on an annualized basis). See Note 12 to our Consolidated Financial Statements for details of distributions paid during the three years ended December 31, 2020.
Contingencies
For a discussion of contingencies that may impact us, see Note 19 to our Consolidated Financial Statements.
Commitments
Contractual Obligations. In the ordinary course of doing business, we purchase crude oil and NGL from third parties under contracts, the majority of which range in term from thirty-day evergreen to five years, with a limited number of contracts with remaining terms extending up to 14 years. We establish a margin for these purchases by entering into various types of physical and financial sale and exchange transactions through which we seek to maintain a position that is substantially balanced between purchases on the one hand and sales and future delivery obligations on the other. The table below includes purchase obligations related to these activities. Where applicable, the amounts presented represent the net obligations associated with our counterparties (including giving effect to netting buy/sell contracts and those subject to a net settlement arrangement). We do not expect to use a significant amount of internal capital to meet these obligations, as the obligations will be funded by corresponding sales to entities that we deem creditworthy or who have provided credit support we consider adequate.
The following table includes our best estimate of the amount and timing of these payments as well as other amounts due under the specified contractual obligations as of December 31, 2020 (in millions):
2021 2022 2023 2024 2025 Thereafter Total
Long-term debt and related interest payments (1)
$ 406 $ 1,183 $ 1,662 $ 1,083 $ 1,300 $ 8,337 $ 13,971
Leases (2)
108 100 77 63 49 304 701
Other obligations (3)
542 368 325 281 254 934 2,704
Subtotal 1,056 1,651 2,064 1,427 1,603 9,575 17,376
Crude oil, NGL and other purchases (4)
11,565 10,353 9,643 9,035 7,507 26,845 74,948
Total $ 12,621 $ 12,004 $ 11,707 $ 10,462 $ 9,110 $ 36,420 $ 92,324
(1)Includes debt service payments, interest payments due on PAA’s senior notes and the commitment fee on assumed available capacity under the PAA credit facilities, as well as long-term borrowings under PAA’s credit agreements and commercial paper program, if any. Although there may be short-term borrowings under PAA’s credit agreements and commercial paper program, we historically repay and borrow at varying amounts. As such, we have included only the maximum commitment fee (as if no short-term borrowings were outstanding on PAA’s credit agreements or commercial paper program) in the amounts above. For additional information regarding our debt obligations, see Note 11 to our Consolidated Financial Statements.
(2)Includes both operating and finance leases as defined by FASB guidance. Leases are primarily for (i) railcars, (ii) land, (iii) office space, (iv) storage tanks, (v) tractor trailers and (vi) vehicles. See Note 14 to our Consolidated Financial Statements for additional information.
(3)Includes (i) other long-term liabilities, (ii) storage, processing and transportation agreements (including certain agreements for which the amount and timing of expected payments is subject to the completion of underlying construction projects), (iii) certain rights-of-way easements and (iv) noncancelable commitments related to our investment capital projects, including projected contributions for our share of the capital spending of our equity method investments. The storage, processing and transportation agreements include approximately $2.0 billion associated with agreements to store crude oil at facilities and transport crude oil on pipelines owned by equity method investees at posted tariff rates or prices that we believe approximate market. A portion of our commitment to transport is supported by crude oil buy/sell or other agreements with third parties with commensurate quantities.
(4)Amounts are primarily based on estimated volumes and market prices based on average activity during December 2020. The actual physical volume purchased and actual settlement prices will vary from the assumptions used in the table. Uncertainties involved in these estimates include levels of production at the wellhead, weather conditions, changes in market prices and other conditions beyond our control.
Letters of Credit. In connection with supply and logistics activities, we provide certain suppliers with irrevocable standby letters of credit to secure our obligation for the purchase and transportation of crude oil, NGL and natural gas. Our liabilities with respect to these purchase obligations are recorded in accounts payable on our balance sheet in the month the product is purchased. Generally, these letters of credit are issued for periods of up to seventy days and are terminated upon completion of each transaction. Additionally, we issue letters of credit to support insurance programs, derivative transactions, including hedging-related margin obligations, and construction activities. At December 31, 2020 and 2019, we had outstanding letters of credit of approximately $129 million and $157 million, respectively.
Off-Balance Sheet Arrangements
We have no off-balance sheet arrangements as defined by Item 303 of Regulation S-K.
Investments in Unconsolidated Entities
We have invested in entities that are not consolidated in our financial statements. Certain of these entities are borrowers under credit facilities. We are neither a co-borrower nor a guarantor under any facilities of such entities. We may elect at any time to make additional capital contributions to any of these entities. The following table sets forth selected information regarding these entities as of December 31, 2020 (unaudited, dollars in millions):
Entity Type of Operation Our
Ownership
Interest Total
Entity
Assets Total Cash
and
Restricted
Cash Total
Entity
Debt
BridgeTex Pipeline Company, LLC Crude Oil Pipeline 20% $ 856 $ 35 $ -
Cactus II Pipeline LLC Crude Oil Pipeline (1)
65% $ 1,167 $ 44 $ -
Capline Pipeline Company LLC Crude Oil Pipeline 54% $ 1,217 $ 16 $ -
Diamond Pipeline LLC Crude Oil Pipeline (1)
50% $ 951 $ 8 $ -
Eagle Ford Pipeline LLC Crude Oil Pipeline (1)
50% $ 808 $ 33 $ -
Eagle Ford Terminals Corpus Christi LLC Crude Oil Terminal and Dock (1)
50% $ 220 $ 4 $ -
Red Oak Pipeline LLC Crude Oil Pipeline 50% $ 205 $ - $ -
Saddlehorn Pipeline Company, LLC Crude Oil Pipeline 30% $ 662 $ 40 $ -
STACK Pipeline LLC Crude Oil Pipeline (1)
50% $ 146 $ 1 $ -
White Cliffs Pipeline, LLC Crude Oil Pipeline 36% $ 518 $ 24 $ -
Wink to Webster Pipeline LLC Crude Oil Pipeline 16% $ 2,068 $ 68 $ -
Other investments $ 531 $ 49 $ 3
(1)We serve as operator of the asset.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
We are exposed to various market risks, including (i) commodity price risk, (ii) interest rate risk and (iii) currency exchange rate risk. We use various derivative instruments to manage such risks and, in certain circumstances, to realize incremental margin during volatile market conditions. Our risk management policies and procedures are designed to help ensure that our hedging activities address our risks by monitoring our exchange-cleared and over-the-counter positions, as well as physical volumes, grades, locations, delivery schedules and storage capacity. The board of directors of our general partner, acting through the Audit Committee, retains a general oversight role with respect to the management of these risks while management is directly responsible for our risk management activities. The Audit Committee has authorized the formation of a Risk Management Committee composed of senior members of management that oversees and works with our risk management function to ensure that we are in compliance with our risk policies and procedures and that we maintain related controls around commercial activities and certain aspects of corporate risk management. Our Risk Management Committee also approves all new risk management strategies through a formal process. The following discussion addresses each category of risk.
Commodity Price Risk
We use derivative instruments to hedge price risk associated with the following commodities:
•Crude oil
We utilize crude oil derivatives to hedge commodity price risk inherent in our Supply and Logistics and Transportation segments. Our objectives for these derivatives include hedging anticipated purchases and sales, stored inventory and basis differentials. We manage these exposures with various instruments including futures, forwards, swaps and options.
•Natural gas
We utilize natural gas derivatives to hedge commodity price risk inherent in our Supply and Logistics and Facilities segments. Our objectives for these derivatives include hedging anticipated purchases of natural gas. We manage these exposures with various instruments including futures, swaps and options.
•NGL and other
We utilize NGL derivatives, primarily propane and butane derivatives, to hedge commodity price risk inherent in our Supply and Logistics segment. Our objectives for these derivatives include hedging anticipated purchases and sales and stored inventory. We manage these exposures with various instruments including futures, forwards, swaps and options.
See Note 13 to our Consolidated Financial Statements for further discussion regarding our hedging strategies and objectives.
The fair value of our commodity derivatives and the change in fair value as of December 31, 2020 that would be expected from a 10% price increase or decrease is shown in the table below (in millions):
Fair Value Effect of 10%
Price Increase
Effect of 10%
Price Decrease
Crude oil
$ (158) $ (86) $ 88
Natural gas
1 $ 9 $ (9)
NGL and other
(144) $ (47) $ 47
Total fair value
$ (301)
The fair values presented in the table above reflect the sensitivity of the derivative instruments only and do not include the effect of the underlying hedged commodity. Price-risk sensitivities were calculated by assuming an across-the-board 10% increase or decrease in price regardless of term or historical relationships between the contractual price of the instruments and the underlying commodity price. In the event of an actual 10% change in near-term commodity prices, the fair value of our derivative portfolio would typically change less than that shown in the table as changes in near-term prices are not typically mirrored in delivery months further out.
Interest Rate Risk
Our use of variable rate debt and any forecasted issuances of fixed rate debt expose us to interest rate risk. Therefore, from time to time, we use interest rate derivatives to hedge interest rate risk associated with anticipated interest payments and, in certain cases, outstanding debt instruments. All of PAA’s senior notes are fixed rate notes and thus are not subject to interest rate risk. Our variable rate debt outstanding at December 31, 2020, approximately $914 million, was subject to interest rate re-sets that generally range from one day to approximately one month. The average interest rate on variable rate debt that was outstanding during the year ended December 31, 2020 was 1.4%, based upon rates in effect during the year. The fair value of our interest rate derivatives was an asset of $46 million as of December 31, 2020. A 10% increase in the forward LIBOR curve as of December 31, 2020 would have resulted in an increase of $15 million to the fair value of our interest rate derivatives. A 10% decrease in the forward LIBOR curve as of December 31, 2020 would have resulted in a decrease of $15 million to the fair value of our interest rate derivatives. See Note 13 to our Consolidated Financial Statements for a discussion of our interest rate risk hedging activities.
Currency Exchange Rate Risk
We use foreign currency derivatives to hedge foreign currency exchange rate risk associated with our exposure to fluctuations in the USD-to-CAD exchange rate. Because a significant portion of our Canadian business is conducted in CAD we use certain financial instruments to minimize the risks of unfavorable changes in exchange rates. These instruments include foreign currency exchange contracts, forwards and options. The fair value of our foreign currency derivatives was an asset of $2 million as of December 31, 2020. A 10% increase in the exchange rate (USD-to-CAD) would have resulted in a decrease of $3 million to the fair value of our foreign currency derivatives. A 10% decrease in the exchange rate (USD-to-CAD) would have resulted in an increase of $3 million to the fair value of our foreign currency derivatives. See Note 13 to our Consolidated Financial Statements for a discussion of our currency exchange rate risk hedging.
Preferred Distribution Rate Reset Option
The Preferred Distribution Rate Reset Option of PAA’s Series A preferred units is an embedded derivative that must be bifurcated from the related host contract, PAA’s partnership agreement, and recorded at fair value in our Consolidated Balance Sheets. The valuation model utilized for this embedded derivative contains inputs including PAA’s common unit price, ten-year United States treasury rates, default probabilities and timing estimates to ultimately calculate the fair value of PAA’s Series A preferred units with and without the Preferred Distribution Rate Reset Option. The fair value of this embedded derivative was a liability of $14 million as of December 31, 2020. A 10% increase or decrease in the fair value would have an impact of $1 million. See Note 13 to our Consolidated Financial Statements for a discussion of embedded derivatives.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Item 8. Financial Statements and Supplementary Data
See “Index to the Consolidated Financial Statements” on page.

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
Item 9. Changes In and Disagreements With Accountants on Accounting and Financial Disclosure
None.

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ITEM 9A. CONTROLS AND PROCEDURES
Item 9A. Controls and Procedures
Disclosure Controls and Procedures
We maintain written disclosure controls and procedures, which we refer to as our “DCP.” Our DCP is designed to ensure that information required to be disclosed by us in reports that we file under the Securities Exchange Act of 1934 (the “Exchange Act”) is (i) recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and (ii) accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, to allow for timely decisions regarding required disclosure.
Applicable SEC rules require an evaluation of the effectiveness of our DCP. Management, under the supervision and with the participation of our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of our DCP as of December 31, 2020, the end of the period covered by this report, and, based on such evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that our DCP is effective.
Internal Control over Financial Reporting
Management is responsible for establishing and maintaining adequate internal control over financial reporting. “Internal control over financial reporting” is a process designed by, or under the supervision of, our Chief Executive Officer and our Chief Financial Officer, and effected by our Board of Directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP. Our management, including our Chief Executive Officer and our Chief Financial Officer, has evaluated the effectiveness of our internal control over financial reporting as of December 31, 2020. See “Management’s Report on Internal Control Over Financial Reporting” on page of our Consolidated Financial Statements.
Our independent registered public accounting firm, PricewaterhouseCoopers LLP, assessed the effectiveness of our internal control over financial reporting, as stated in the firm’s report. See “Report of Independent Registered Public Accounting Firm” on page of our Consolidated Financial Statements.
Changes in Internal Control over Financial Reporting
There have been no changes in our internal control over financial reporting during the fourth quarter of 2020 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Certifications
The certifications of our Chief Executive Officer and Chief Financial Officer pursuant to Exchange Act Rules 13a-14(a) and 15d-14(a) are filed with this report as Exhibits 31.1 and 31.2. The certifications of our Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. 1350 are furnished with this report as Exhibits 32.1 and 32.2.

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ITEM 9B. OTHER INFORMATION
Item 9B. Other Information
There was no information that was required to be disclosed in a report on Form 8-K during the fourth quarter of 2020 that has not previously been reported.
PART III

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ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Item 10. Directors and Executive Officers of Our General Partner and Corporate Governance
The information required by this item will be set forth in the Proxy Statement for our 2021 Annual Meeting, which will be filed with the SEC within 120 days after the end of the fiscal year ended December 31, 2020, and is incorporated herein by reference thereto.
Directors and Executive Officers
As of the date of filing this report, the following individuals were serving as our executive officers and/or directors:
Name Principal Occupation or Employment
Willie Chiang (1)(2)
Chairman of the Board and Chief Executive Officer
Harry N. Pefanis (1)(2)
President and Chief Commercial Officer
Chris R. Chandler (1)
Executive Vice President and Chief Operating Officer
Al Swanson (1)
Executive Vice President and Chief Financial Officer
Jeremy L. Goebel (1)
Executive Vice President - Commercial
Richard K. McGee (1)
Executive Vice President, General Counsel and Secretary
Chris Herbold (1)
Senior Vice President and Chief Accounting Officer
Greg L. Armstrong (2)
Senior Advisor to the Chief Executive Officer (former Chairman and Chief Executive Officer)
Victor Burk (2)
Managing Director, Alvarez and Marsal
Kevin McCarthy (2)
Vice Chairman, Kayne Anderson Capital Advisors, L.P.
Gary R. Petersen (2)
Managing Partner, EnCap Investments L.P.
Alexandra D. Pruner (2)
Senior Advisor, Perella Weinberg Partners
John T. Raymond (2)
Managing Partner and Chief Executive Officer, The Energy & Minerals Group
Bobby S. Shackouls (2)
Former Chairman and CEO, Burlington Resources Inc.
Christopher M. Temple (2)
President, DelTex Capital LLC
Lawrence M. Ziemba (2)
Former Executive Vice President, Refining, Phillips 66
(1) Executive officer (for purposes of Item 401(b) of Regulation S-K)
(2) Director
A complete list of our officers, including the executive officers listed above, is available on our website at www.plainsallamerican.com under About Us-Leadership.

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ITEM 11. EXECUTIVE COMPENSATION
Item 11. Executive Compensation
The information required by this item will be set forth in the Proxy Statement for our 2021 Annual Meeting, which will be filed with the SEC within 120 days after the end of the fiscal year ended December 31, 2020, and is incorporated herein by reference thereto.

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters
The information required by this item will be set forth in the Proxy Statement for our 2021 Annual Meeting, which will be filed with the SEC within 120 days after the end of the fiscal year ended December 31, 2020, and is incorporated herein by reference thereto.

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Item 13. Certain Relationships and Related Transactions, and Director Independence
The information required by this item will be set forth in the Proxy Statement for our 2021 Annual Meeting, which will be filed with the SEC within 120 days after the end of the fiscal year ended December 31, 2020, and is incorporated herein by reference thereto.

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ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
Item 14. Principal Accountant Fees and Services
The information required by this item will be set forth in the Proxy Statement for our 2021 Annual Meeting, which will be filed with the SEC within 120 days after the end of the fiscal year ended December 31, 2020, and is incorporated herein by reference thereto.
PART IV

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ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
Item 15. Exhibits and Financial Statement Schedules
(a) (1) Financial Statements
See “Index to the Consolidated Financial Statements” set forth on Page.
(2) Financial Statement Schedules
All schedules are omitted because they are either not applicable or the required information is shown in the Consolidated Financial Statements or notes thereto.
(3) Exhibits
Exhibit No. Description
2.1* - Simplification Agreement, dated as of July 11, 2016, by and among PAA GP Holdings LLC, Plains GP Holdings, L.P., Plains All American GP LLC, Plains AAP, L.P., PAA GP LLC and Plains All American Pipeline, L.P. (incorporated by reference to Exhibit 2.1 to PAA’s Current Report on Form 8-K filed July 14, 2016).
2.2* - Securities Purchase Agreement dated as of January 19, 2017 by and between COG Operating LLC, as seller, and Plains Pipeline, L.P., as purchaser (the schedules and exhibits have been omitted pursuant to Item 601(b)(2) of Regulation S-K) (incorporated by reference to Exhibit 2.1 to PAA’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2017).
2.3* - Securities Purchase Agreement dated as of January 19, 2017 by and between Frontier Midstream Solutions, LLC, as seller, and Plains Pipeline, L.P., as purchaser (the schedules and exhibits have been omitted pursuant to Item 601(b)(2) of Regulation S-K) (incorporated by reference to Exhibit 2.2 to PAA’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2017).
3.1 - Seventh Amended and Restated Agreement of Limited Partnership of Plains All American Pipeline, L.P. dated as of October 10, 2017 (incorporated by reference to Exhibit 3.1 to PAA’s Current Report on Form 8-K filed October 12, 2017).
3.2 - Seventh Amended and Restated Limited Liability Company Agreement of Plains All American GP LLC dated November 15, 2016 (incorporated by reference to Exhibit 3.3 to our Current Report on Form 8-K filed November 21, 2016).
3.3 - Eighth Amended and Restated Limited Partnership Agreement of Plains AAP, L.P. dated November 15, 2016 (incorporated by reference to Exhibit 3.4 to our Current Report on Form 8-K filed November 21, 2016).
3.4 - Amendment No. 1 dated September 26, 2018 to the Eighth Amended and Restated Limited Partnership Agreement of Plains AAP, L.P. (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K filed October 2, 2018).
3.5 - Amendment No. 2 dated May 23, 2019 to the Eighth Amended and Restated Limited Partnership Agreement of Plains AAP, L.P. (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K filed May 30, 2019).
3.6 - Limited Liability Company Agreement of PAA GP LLC dated December 28, 2007 (incorporated by reference to Exhibit 3.3 to PAA’s Current Report on Form 8-K filed January 4, 2008).
3.7 - Certificate of Limited Partnership of Plains GP Holdings, L.P. (incorporated by reference to Exhibit 3.1 to our Registration Statement on Form S-1 (333-190227) filed July 29, 2013).
3.8 - Second Amended and Restated Agreement of Limited Partnership of Plains GP Holdings, L.P. dated as of November 15, 2016 (incorporated by reference to Exhibit 3.2 to our Current Report on Form 8-K filed November 21, 2016).
3.9 - Amendment No. 1 dated April 6, 2020 to the Second Amended and Restated Agreement of Limited Partnership of Plains GP Holdings, L.P. (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K filed April 9, 2020).
3.10 - Certificate of Formation of PAA GP Holdings LLC (incorporated by reference to Exhibit 3.3 to our Registration Statement on Form S-1 (333-190227) filed July 29, 2013).
3.11 - Third Amended and Restated Limited Liability Company Agreement of PAA GP Holdings LLC dated as of February 16, 2017 (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K filed February 21, 2017).
3.12 - Amendment No. 1 dated October 1, 2018 to the Third Amended and Restated Limited Liability Company Agreement of PAA GP Holdings LLC (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K filed August 20, 2018).
3.13 - Amendment No. 2 dated December 10, 2018 to the Third Amended and Restated Limited Liability Company Agreement of PAA GP Holdings LLC (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K filed December 11, 2018).
3.14 - Amendment No. 3 dated November 21, 2019 to the Third Amended and Restated Limited Liability Company Agreement of PAA GP Holdings LLC (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K filed November 27, 2019).
4.1 - Indenture dated September 25, 2002 among Plains All American Pipeline, L.P., PAA Finance Corp. and Wachovia Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to PAA’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2002).
4.2 - Sixth Supplemental Indenture (Series A and Series B 6.70% Senior Notes due 2036) dated May 12, 2006 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and Wachovia Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to PAA’s Current Report on Form 8-K filed May 12, 2006).
4.3 - Tenth Supplemental Indenture (Series A and Series B 6.650% Senior Notes due 2037) dated October 30, 2006 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.2 to PAA’s Current Report on Form 8-K filed October 30, 2006).
4.4 - Twentieth Supplemental Indenture (3.65% Senior Notes due 2022) dated March 22, 2012 among Plains All American Pipeline, L.P., PAA Finance Corp. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to PAA’s Current Report on Form 8-K filed March 26, 2012).
4.5 - Twenty-First Supplemental Indenture (5.15% Senior Notes due 2042) dated March 22, 2012 among Plains All American Pipeline, L.P., PAA Finance Corp. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.3 to PAA’s Current Report on Form 8-K filed March 26, 2012).
4.6 - Twenty-Second Supplemental Indenture (2.85% Senior Notes due 2023) dated December 10, 2012, by and among Plains All American Pipeline, L.P., PAA Finance Corp. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to PAA’s Current Report on Form 8-K filed December 12, 2012).
4.7 - Twenty-Third Supplemental Indenture (4.30% Senior Notes due 2043) dated December 10, 2012, by and among Plains All American Pipeline, L.P., PAA Finance Corp. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.3 to PAA’s Current Report on Form 8-K filed December 12, 2012).
4.8 - Twenty-Fourth Supplemental Indenture (3.85% Senior Notes due 2023) dated August 15, 2013, by and among Plains All American Pipeline, L.P., PAA Finance Corp. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed August 15, 2013).
4.9 - Twenty-Fifth Supplemental Indenture (4.70% Senior Notes due 2044) dated April 23, 2014, by and among Plains All American Pipeline, L.P., PAA Finance Corp. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed April 29, 2014).
4.10 - Twenty-Sixth Supplemental Indenture (3.60% Senior Notes due 2024) dated September 9, 2014, by and among Plains All American Pipeline, L.P., PAA Finance Corp. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed September 11, 2014).
4.11 - Twenty-Eighth Supplemental Indenture (4.90% Senior Notes due 2045) dated December 9, 2014, by and among Plains All American Pipeline, L.P., PAA Finance Corp. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.3 to our Current Report on Form 8-K filed December 11, 2014).
4.12 - Twenty-Ninth Supplemental Indenture (4.65% Senior Notes due 2025) dated August 24, 2015, by and among Plains All American Pipeline, L.P., PAA Finance Corp. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to PAA’s Current Report on Form 8-K filed August 26, 2015).
4.13 - Thirtieth Supplemental Indenture (4.50% Senior Notes due 2026) dated November 22, 2016, by and among Plains All American Pipeline, L.P., PAA Finance Corp. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to PAA’s Current Report on Form 8-K filed November 29, 2016).
4.14 - Thirty-First Supplemental Indenture (3.55% Senior Notes due 2029) dated September 16, 2019, by and among Plains All American Pipeline, L.P., PAA Finance Corp. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to PAA’s Current Report on Form 8-K filed September 17, 2019).
4.15 - Thirty-Second Supplemental Indenture (3.80% Senior Notes due 2030) dated June 11, 2020, by and among Plains All American Pipeline, L.P., PAA Finance Corp. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to PAA’s Current Report on Form 8-K filed June 11, 2020).
4.16 - Shareholder and Registration Rights Agreement dated October 21, 2013 by and among Plains GP Holdings, L.P. and the other parties signatory thereto (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed October 25, 2013).
4.17 † - Description of Our Securities.
10.1 - Credit Agreement dated as of August 19, 2011 among Plains All American Pipeline, L.P., as Borrower; certain subsidiaries of Plains All American Pipeline, L.P. from time to time party thereto, as Designated Borrowers; Bank of America, N.A., as Administrative Agent; and the other Lenders party thereto (incorporated by reference to Exhibit 10.1 to PAA’s Current Report on Form 8-K filed August 25, 2011).
10.2 - First Amendment to Credit Agreement dated as of June 27, 2012, among Plains All American Pipeline, L.P. and Plains Midstream Canada ULC, as Borrowers; Bank of America, N.A., as Administrative Agent, Swing Line Lender and L/C Issuer; Wells Fargo Bank, National Association, as an L/C Issuer; and the other Lenders party thereto (incorporated by reference to Exhibit 10.2 to PAA’s Current Report on Form 8-K filed July 3, 2012).
10.3 - Second Amendment to Credit Agreement dated as of August 16, 2013, among Plains All American Pipeline, L.P. and Plains Midstream Canada ULC, as Borrowers; Bank of America, N.A., as Administrative Agent, Swing Line Lender and L/C Issuer; Wells Fargo Bank, National Association, as an L/C Issuer; and the other Lenders party thereto (incorporated by reference to Exhibit 10.2 to PAA’s Current Report on Form 8-K filed August 20, 2013).
10.4 - Third Amendment to Credit Agreement dated as of August 11, 2016, among Plains All American Pipeline, L.P. and Plains Midstream Canada ULC, as Borrowers; Bank of America, N.A., as Administrative Agent, Swing Line Lender and L/C Issuer; Wells Fargo Bank, National Association, as an L/C Issuer; and the other Lenders party thereto (incorporated by reference to Exhibit 10.1 to PAA’s Current Report on Form 8-K filed August 17, 2016).
10.5 - Third Amended and Restated Credit Agreement dated as of August 19, 2011 by and among Plains Marketing, L.P., as Borrower, Plains All American Pipeline, L.P., as Guarantor, Bank of America, N.A., as Administrative Agent, and the other Lenders party thereto (incorporated by reference to Exhibit 10.2 to PAA’s Current Report on Form 8-K filed August 25, 2011).
10.6 - First Amendment to Third Amended and Restated Credit Agreement dated as of June 27, 2012, among Plains Marketing, L.P. and Plains Midstream Canada ULC, as Borrowers; Plains All American Pipeline, L.P., as Guarantor; Bank of America, N.A., as Administrative Agent, Swing Line Lender and L/C Issuer; and the other Lenders and L/C Issuers party thereto (incorporated by reference to Exhibit 10.1 to PAA’s Current Report on Form 8-K filed July 3, 2012).
10.7 - Second Amendment to Third Amended and Restated Credit Agreement dated as of August 16, 2013, among Plains Marketing, L.P. and Plains Midstream Canada ULC, as Borrowers; Plains All American Pipeline, L.P., as Guarantor; Bank of America, N.A., as Administrative Agent, Swing Line Lender and L/C Issuer; Wells Fargo Bank, National Association, as an L/C Issuer; and the other Lenders and L/C Issuers party thereto (incorporated by reference to Exhibit 10.1 to PAA’s Current Report on Form 8-K filed August 20, 2013).
10.8 - Third Amendment to Third Amended and Restated Credit Agreement dated as of August 11, 2016, among Plains Marketing, L.P. and Plains Midstream Canada ULC, as Borrowers; Plains All American Pipeline, L.P., as Guarantor; Bank of America, N.A., as Administrative Agent, Swing Line Lender and L/C Issuer; Wells Fargo Bank, National Association, as an L/C Issuer; and the other Lenders and L/C Issuers party thereto (incorporated by reference to Exhibit 10.3 to PAA’s Current Report on Form 8-K filed August 17, 2016).
10.9 - Fourth Amendment to Third Amended and Restated Credit Agreement dated as of August 16, 2017, among Plains Marketing, L.P. and Plains Midstream Canada ULC, as Borrowers; Plains All American Pipeline, L.P., as Guarantor; Bank of America, N.A., as Administrative Agent, Swing Line Lender and L/C Issuer; Wells Fargo Bank, National Association, as an L/C Issuer; and the other Lenders and L/C Issuers party thereto (incorporated by reference to Exhibit 10.6 to our Quarterly Report on Form 10-Q for the quarter ended September 30, 2017).
10.10 - Contribution and Assumption Agreement dated December 28, 2007, by and between Plains AAP, L.P. and PAA GP LLC (incorporated by reference to Exhibit 10.2 to PAA’s Current Report on Form 8-K filed January 4, 2008).
10.11 - Omnibus Agreement by and among PAA GP Holdings LLC, Plains GP Holdings, L.P., Plains All American GP LLC, Plains AAP, L.P., PAA GP LLC, and Plains All American Pipeline, L.P., dated November 15, 2016 (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed November 21, 2016).
10.12 - Amended and Restated Administrative Agreement by and among PAA GP Holdings LLC, Plains GP Holdings, L.P., Plains All American GP LLC, Plains AAP, L.P., PAA GP LLC, and Plains All American Pipeline, L.P., dated November 15, 2016 (incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K filed November 21, 2016).
10.13** - Amended and Restated Employment Agreement between Plains All American GP LLC and Greg L. Armstrong dated as of June 30, 2001 (incorporated by reference to Exhibit 10.1 to PAA’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2001).
10.14** - First Amendment to Amended and Restated Employment Agreement dated December 4, 2008 between Plains All American GP LLC and Greg L. Armstrong (incorporated by reference to Exhibit 10.49 to PAA’s Annual Report on Form 10-K for the year ended December 31, 2008).
10.15** - Waiver Agreement dated as of December 23, 2010 between Plains All American GP LLC and Greg L. Armstrong (incorporated by reference to Exhibit 10.31 to PAA’s Annual Report on Form 10-K for the year ended December 31, 2010).
10.16** - Waiver Agreement dated October 21, 2013 to the Amended and Restated Employment Agreement dated June 30, 2001 of Greg L. Armstrong (incorporated by reference to Exhibit 10.4 to our Current Report on Form 8-K filed October 25, 2013).
10.17** - Second Amended and Restated Employment Agreement dated effective October 1, 2018 between Plains All American GP LLC and Greg L. Armstrong (incorporated by reference to Exhibit 10.6 to our Quarterly Report on Form 10-Q for the quarter ended September 30, 2018).
10.18** - Third Amended and Restated Employment Agreement dated effective January 1, 2020 between Plains All American GP LLC and Greg L. Armstrong (incorporated by reference to Exhibit 10.31 to our Annual Report on Form 10-K for the year ended December 31, 2019).
10.19** - Amended and Restated Employment Agreement between Plains All American GP LLC and Harry N. Pefanis dated as of June 30, 2001 (incorporated by reference to Exhibit 10.2 to PAA’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2001).
10.20** - First Amendment to Amended and Restated Employment Agreement dated December 4, 2008 between Plains All American GP LLC and Harry N. Pefanis (incorporated by reference to Exhibit 10.50 to PAA’s Annual Report on Form 10-K for the year ended December 31, 2008).
10.21** - Amendment No. 2 dated August 15, 2019 to Harry Pefanis Amended and Restated Employment Agreement (incorporated by reference to Exhibit 10.1 to our Quarterly Report on Form 10-Q for the quarter ended September 30, 2019).
10.22** - Waiver Agreement dated as of December 23, 2010 between Plains All American GP LLC and Harry N. Pefanis (incorporated by reference to Exhibit 10.32 to PAA’s Annual Report on Form 10-K for the year ended December 31, 2010).
10.23** - Waiver Agreement dated October 21, 2013 to the Amended and Restated Employment Agreement dated June 30, 2001 of Harry N. Pefanis (incorporated by reference to Exhibit 10.5 to our Current Report on Form 8-K filed October 25, 2013).
10.24** - Employment Agreement between Plains All American GP LLC and Willie Chiang dated July 10, 2015 (incorporated by reference to Exhibit 10.53 to PAA’s Annual Report on Form 10-K for the year ended December 31, 2015).
10.25** - Amended and Restated Employment Agreement dated effective October 1, 2018 between Plains All American GP LLC and Willie Chiang (incorporated by reference to Exhibit 10.7 to our Quarterly Report on Form 10-Q for the quarter ended September 30, 2018).
10.26** - First Amendment to Plains AAP, L.P. Class B Restricted Units Agreement dated August 25, 2016 (Willie Chiang) (incorporated by reference to Exhibit 10.8 to PAA’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2016).
10.27** - Second Amendment dated March 22, 2018 to Plains AAP, L.P. Class B Restricted Units Agreement (Willie Chiang) (incorporated by reference to Exhibit 10.1 to our Quarterly Report on Form 10-Q for the quarter ended March 31, 2018).
10.28** - LTIP Grant Letter dated August 16, 2018 (Willie Chiang) incorporated by reference to Exhibit 10.8 to our Quarterly Report on Form 10-Q for the quarter ended September 30, 2018).
10.29** - Plains All American 2013 Long-Term Incentive Plan (incorporated by reference to Exhibit A to PAA’s Definitive Proxy Statement filed on October 3, 2013).
10.30** - Plains All American PNG Successor Long-Term Incentive Plan (incorporated by reference to Exhibit 4.4 to PAA’s Registration Statement on Form S-8 (333-193139) filed December 31, 2013).
10.31** - PAA Natural Gas Storage, L.P. 2010 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.2 to PNG’s Current Report on Form 8-K filed May 11, 2010).
10.32** - Plains GP Holdings, L.P. Long Term Incentive Plan, (incorporated by reference to Exhibit 10.3 to our Current Report on Form 8-K filed October 25, 2013).
10.33** - Form of Plains AAP, L.P. Class B Restricted Units Agreement (incorporated by reference to Exhibit 10.1 to PAA’s Current Report on Form 8-K filed January 4, 2008).
10.34** - Form of Amendment to the Plains AAP, L.P. Class B Restricted Units Agreement, dated October 18, 2013 (incorporated by reference to Exhibit 10.6 to our Current Report on Form 8-K filed October 25, 2013).
10.35** - Form of Amendment to Plains AAP, L.P. Class B Restricted Units Agreement dated August 25, 2016 (incorporated by reference to Exhibit 10.6 to PAA’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2016 filed November 8, 2016).
10.36** - Form of First Amendment dated March 22, 2018 to Amended and Restated Plains AAP, L.P. Class B Restricted Units Agreement dated August 25, 2016 (Officers) (incorporated by reference to Exhibit 10.2 to our Quarterly Report on Form 10-Q for the quarter ended March 31, 2018).
10.37** - Form of PAA LTIP Grant Letter for Officers (August 2016) (incorporated by reference to Exhibit 10.5 to PAA’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2016).
10.38** - Form of Amendment dated March 22, 2018 to PAA LTIP Grant Letter dated August 25, 2016 (Officers) (incorporated by reference to Exhibit 10.4 to our Quarterly Report on Form 10-Q for the quarter ended March 31, 2018).
10.39** - Form of PAA LTIP Grant Letter for Officers (March 2018) (incorporated by reference to Exhibit 10.5 to our Quarterly Report on Form 10-Q for the quarter ended March 31, 2018).
10.40** - Form of Director LTIP Grant Letter (February 2017) - Director Grant - Designated Directors and Audit Committee Members (PAA Plan) (incorporated by reference to Exhibit 10.1 to PAA’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2017).
10.41** - Form of Director LTIP Grant Letter (February 2017) - Audit Committee Supplement (PAA Plan) (incorporated by reference to Exhibit 10.2 to PAA’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2017).
10.42** - Form of Director LTIP Grant Letter (February 2017) - Independent Director Grant (PAA Plan) (incorporated by reference to Exhibit 10.3 to PAA’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2017).
10.43** - Form of Director LTIP Grant Letter (February 2017) - Director Grant - Designated Directors and Audit Committee Members (PAGP Plan) (incorporated by reference to Exhibit 10.1 to our Quarterly Report on Form 10-Q for the quarter ended March 31, 2017).
10.44** - Form of Director LTIP Grant Letter (February 2017) - Audit Committee Supplement (PAGP Plan) (incorporated by reference to Exhibit 10.2 to our Quarterly Report on Form 10-Q for the quarter ended March 31, 2017).
10.45** - Form of Director LTIP Grant Letter (February 2017) - Independent Director Grant (PAGP Plan) (incorporated by reference to Exhibit 10.3 to our Quarterly Report on Form 10-Q for the quarter ended March 31, 2017).
10.46** - Form of Director LTIP Grant Letter (August 2018) (incorporated by reference to Exhibit 10.66 to our Annual Report on Form 10-K for the year ended December 31, 2018).
10.47** - Director LTIP Grant Letter (December 2018) (incorporated by reference to Exhibit 10.66 to our Annual Report on Form 10-K for the year ended December 31, 2018).
10.48** - Form of LTIP Grant Letter dated August 15, 2019 (Officers) (incorporated by reference to Exhibit 10.2 to our Quarterly Report on Form 10-Q for the quarter ended September 30, 2019).
10.49** - Form of LTIP Grant Letter dated August 15, 2019 (Directors) (incorporated by reference to Exhibit 10.3 to our Quarterly Report on Form 10-Q for the quarter ended September 30, 2019).
10.50** - Director LTIP Grant Letter (January 2020) (incorporated by reference to Exhibit 10.72 to our Annual Report on Form 10-K for the year ended December 31, 2019).
10.51** - Form of LTIP Grant Letter dated August 13, 2020 (Officers) (incorporated by reference to Exhibit 10.1 to our Quarterly Report on Form 10-Q for the quarter ended September 30, 2020).
10.52** - Form of LTIP Grant Letter dated August 13, 2020 (Directors) (incorporated by reference to Exhibit 10.2 to our Quarterly Report on Form 10-Q for the quarter ended September 30, 2020).
10.53 - Contribution Agreement dated October 21, 2013, by and among Plains GP Holdings, L.P., PAA GP Holdings LLC and the other parties signatory thereto (incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K filed October 25, 2013).
10.54** † - Form of Special Retention LTIP Grant Letter dated November 20, 2019.
10.55** † - Form of LTIP Grant Letter dated December 21, 2017 (Goebel).
10.56** † - Form of LTIP Grant Letter dated May 1, 2018 (Chandler).
10.57** † - Form of LTIP Grant Letter dated May 1, 2018 (Chandler).
21.1 † - List of Subsidiaries of Plains GP Holdings, L.P.
23.1 † - Consent of PricewaterhouseCoopers LLP.
31.1 † - Certification of Principal Executive Officer pursuant to Exchange Act Rules 13a-14(a) and 15d-14(a).
31.2 † - Certification of Principal Financial Officer pursuant to Exchange Act Rules 13a-14(a) and 15d-14(a).
32.1 †† - Certification of Principal Executive Officer pursuant to 18 U.S.C. 1350.
32.2 †† - Certification of Principal Financial Officer pursuant to 18 U.S.C. 1350.
101. INS† - XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
101.SCH† - Inline XBRL Taxonomy Extension Schema Document
101.CAL† - Inline XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF† - Inline XBRL Taxonomy Extension Definition Linkbase Document
101.LAB† - Inline XBRL Taxonomy Extension Label Linkbase Document
101.PRE† - Inline XBRL Taxonomy Extension Presentation Linkbase Document
104† - Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)
† Filed herewith.
†† Furnished herewith.
* Certain schedules have been omitted pursuant to Item 601(b)(2) of Regulation S-K. A copy of any omitted schedule will be furnished supplementally to the SEC upon request.
** Management compensatory plan or arrangement.