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

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

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•	our ability to pay distributions to our Class A shareholders;

•	our expected receipt of, and amounts of, distributions from Plains AAP, L.P.;

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declines in the actual or expected volume of crude oil and NGL shipped, processed, purchased, stored, fractionated and/or gathered at or through the use of our assets, whether due to declines in production from existing oil and gas reserves, reduced demand, failure to develop or slowdown in the development of additional oil and gas reserves, whether from reduced cash flow to fund drilling or the inability to access capital, or other factors;

•	the effects of competition, including the effects of capacity overbuild in areas where we operate;

•	market distortions caused by over-commitments to infrastructure projects, which impacts volumes, margins, returns and overall earnings;

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

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

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

•	maintenance of PAA’s credit rating and ability to receive open credit from suppliers and trade counterparties;

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

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

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

•	the impact of current and future laws, rulings, governmental regulations, accounting standards and statements, and related interpretations;

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

•	the availability of, and our ability to consummate, acquisition or combination opportunities;

•	the successful integration and future performance of acquired assets or businesses and the risks associated with operating in lines of business that are distinct and separate from historical operations;

•	the currency exchange rate of the Canadian dollar;

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

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

•	non-utilization of our assets and facilities;

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

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

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•	the effectiveness of our risk management activities;

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

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

•	general economic, market or business conditions and the amplification of other risks caused by volatile financial markets, capital constraints and pervasive liquidity concerns; and

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

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(1)	Through a “pass-through” voting right as a result of PAA’s ownership of our Class C shares, PAA’s common unitholders have the effective right to vote, pro rata with the holders of our Class A and Class B shares, for the election of eligible directors.

(2)	Represents percentage ownership of PAA Common Unit Equivalents.

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(1)	Represents the number of AAP units for which the outstanding Class B units of AAP (referred to herein as the “AAP Management Units”) will be exchangeable, assuming the conversion of all such units at a rate of approximately 0.941 AAP units for each AAP Management Unit.

(2)	Assumes conversion of all outstanding AAP Management Units into AAP units.

(3)	Each Class C share represents a non-economic limited partner interest in us. Through a “pass-through” voting right as a result of PAA’s ownership of our Class C shares, PAA’s common unitholders have the effective right to vote, pro rata with the holders of our Class A and Class B shares, for the election of eligible directors.

(4)	Amount does not include (i) 48,606 PAA common units that will become issuable to AAP that relate to AAP Management Units that were outstanding but not earned as of December 31, 2018 and (ii) 183,819 PAA common units that were issued to AAP in January 2019 in respect of AAP Management units that became earned effective December 31, 2018.

(5)	Represents percentage ownership of PAA Common Unit Equivalents. PAA’s Series B preferred units are not convertible into common units and are not included in PAA Common Unit Equivalents.

(6)	PAA holds direct and indirect ownership interests in consolidated operating subsidiaries including, but not limited to, Plains Marketing, L.P., Plains Pipeline, L.P. and PMC.

(7)

PAA holds indirect equity interests in unconsolidated entities including Advantage Pipeline, L.L.C. (“Advantage”), BridgeTex Pipeline Company, LLC (“BridgeTex”), Cactus II Pipeline LLC (“Cactus II”), Caddo Pipeline LLC (“Caddo”), Cheyenne Pipeline LLC (“Cheyenne”), Diamond Pipeline LLC (“Diamond”), Eagle Ford Pipeline LLC (“Eagle Ford Pipeline”), Eagle Ford Terminals Corpus Christi LLC (“Eagle Ford Terminals”), Midway Pipeline LLC (“Midway Pipeline”), Saddlehorn Pipeline Company, LLC (“Saddlehorn”), Settoon Towing, LLC (“Settoon Towing”), STACK Pipeline LLC (“STACK”) and White Cliffs Pipeline, L.L.C. (“White Cliffs”).

•	running a safe, reliable, environmentally and socially responsible operation, which includes driving operational excellence, cost savings, asset optimization and improved efficiencies throughout the organization;

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•	developing and implementing growth projects that (i) address evolving crude oil and NGL needs in the midstream transportation and infrastructure sector and (ii) are well positioned to benefit from long-term industry trends and opportunities;

•	using its transportation, terminalling, storage, processing and fractionation assets in conjunction with its supply and logistics activities to provide flexibility for customers, capture market opportunities, address physical market imbalances, mitigate inherent risks and increase margin; and

•	selectively pursuing strategic and accretive acquisitions that complement its existing asset base and distribution capabilities.

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Many of PAA’s assets are strategically located and operationally flexible. 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 assets include pipeline, rail, barge, truck and storage assets, which provide PAA’s customers and PAA with significant flexibility and optionality to satisfy demand and balance markets, particularly during a dynamic period of changing product flows and recent developments with respect to rising crude oil exports.

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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 an extensive understanding of the North American physical crude oil and NGL markets.

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PAA’s supply and logistics activities typically generate a positive margin with the opportunity to realize incremental margins. We believe the variety of activities executed within PAA’s Supply and Logistics segment in combination with PAA’s risk management strategies 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).

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PAA has the strategic and technical skills and the financial flexibility to continue to pursue acquisition and expansion opportunities, whether on its own or through joint ventures. Since 1998, PAA has completed and integrated over 90 acquisitions with an aggregate purchase price of approximately $13.2 billion. Since 1998, PAA has also implemented expansion capital projects totaling over $14.4 billion. In addition, considering PAA’s investment grade credit ratings at two of three agencies, liquidity and capital structure, PAA believes it has the financial resources and strength necessary to finance future strategic expansion, joint venture and acquisition opportunities. As of December 31, 2018, PAA had approximately $2.9 billion of liquidity available, including cash and cash equivalents and availability under its committed credit facilities, subject to continued covenant compliance.

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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 industry experience, and an average of 16 years with PAA or its predecessors and affiliates. In addition, through their ownership of PAA common units and grants of phantom units and interests in us, PAA’s management team has a vested interest in PAA’s continued success.

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

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a long-term debt-to-Adjusted EBITDA multiple averaging between 3.5x and 4.0x, which has been the historical target range and is currently under internal review (“Adjusted EBITDA” is earnings before interest, taxes, depreciation and amortization (including our proportionate share of depreciation and amortization and gains and losses on significant asset sales by unconsolidated entities), gains and losses on asset sales and asset impairments, and gains on sales of investments in unconsolidated entities, adjusted for selected items that impact comparability. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations—Non-GAAP Financial Measures” for a discussion of our selected items that impact comparability and our non-GAAP measures.);

•	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.

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(1)	As applicable, the approximate purchase price includes total cash paid and debt assumed, including amounts for working capital and inventory.

(2)	Approximate purchase price of $180 million, net of cash, inventory and other working capital acquired.

(3)	Approximate purchase price of $1.075 billion, net of working capital acquired. In 2018, PAA sold a 30% interest in BridgeTex. See Note 9 to our Consolidated Financial Statements for more information. PAA accounts for its 20% interest in BridgeTex under the equity method of accounting.

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(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. Amounts reflect our expectation that certain projects will be owned in a joint venture structure with a proportionate share of the project cost dispersed among the partners.

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(1)	Data reflects actuals through October 2018.

(2)	Amounts may not recalculate due to rounding.

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(1)	Data reflects actuals through November 2018.

(2)	Amounts may not recalculate due to rounding.

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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.

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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.

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•	the absolute prices of NGL products and their prices relative to natural gas and crude oil;

•	drilling activity and wet natural gas production in developing liquids-rich production areas;

•	available processing, fractionation, storage and transportation capacity;

•	petro-chemical demand driven by the build-out or new builds of Ethylene Cracker capacity (ethane demand) and Propane Dehydrogenation facilities (propane demand);

•	increased export capacity for both ethane and propane;

•	diluent requirements for heavy Canadian oil;

•	regulatory changes in gasoline specifications affecting demand for butane;

•	seasonal demand from refiners;

•	seasonal weather-related demand; and

•	inefficiencies caused by regional supply and demand imbalances.

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•	17,965 miles of active crude oil and NGL pipelines and gathering systems;

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

•	830 trailers (primarily in Canada); and

•	50 transport and storage barges and 20 transport tugs through our interest in Settoon Towing.

(1)	Includes total mileage from pipelines owned by unconsolidated entities.

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(2)	Represents average daily volumes for the entire year attributable to our interest. Average daily volumes are calculated as the total volumes (attributable to our interest) for the year divided by the number of days in the year. Volumes reflect tariff movements and thus may be included multiple times as volumes move through our integrated system.

(3)	Includes pipelines operated by a third party.

•	Mesa Pipeline. We own a 63% undivided interest in and are the operator of Mesa Pipeline, which transports crude oil from Midland, Texas to a refinery at Big Spring, Texas, and to connecting carriers at Colorado City, Texas, with capacity of up to 400,000 barrels per day (approximately 252,000 barrels per day attributable to our interest).

•	Sunrise Pipeline. Our Sunrise Pipeline, which transports crude oil from Midland, Texas to connecting carriers at Colorado City, Texas, has a capacity of approximately 350,000 barrels per day.

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Basin Pipeline (Permian to Cushing).  We own an 87% undivided joint interest 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.

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BridgeTex Pipeline (Permian to Houston). After the sale of a portion of our interest in the third quarter of 2018, we now own a 20% interest in BridgeTex Pipeline Company, LLC, a joint venture with a subsidiary of Magellan Midstream Partners, L.P. (“Magellan”) and an affiliate of OMERS Infrastructure Management Inc. Such joint venture owns a crude oil pipeline (the “BridgeTex Pipeline”) with a capacity of 440,000 barrels per day that originates at Colorado City, Texas, receiving volumes from our Basin and Sunrise Pipelines, and extends to Houston, Texas. The BridgeTex Pipeline is operated by Magellan. See Note 9 to our Consolidated Financial Statements for additional information regarding the sale of a portion of our interest in BridgeTex Pipeline Company, LLC.

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Sunrise II Pipeline. In 2018, as part of our Sunrise expansion project, we added 500,000 barrels per day of capacity by looping the line from Midland, Texas to Colorado City, Texas and extended the line from Colorado City, Texas to Wichita Falls, Texas. We sold 100,000 barrels per day of the new capacity from Midland, Texas to Wichita Falls, Texas to a third party. We operate the Sunrise II Pipeline and own 400,000 barrels of the capacity. The Sunrise expansion is underpinned by long-term shipper commitments and was placed into service in November 2018. Our Sunrise II Pipeline transports crude oil from Midland, Texas and Colorado City, Texas to connecting carriers at Wichita Falls, Texas.

•	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, Texas to our Eagle Ford joint venture pipeline system.

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Cactus II Pipeline (Permian to Corpus Christi). Cactus II Pipeline is a joint-venture pipeline, of which we own 65%, that is currently under construction. Cactus II Pipeline will be a new Permian mainline system extending directly to the Corpus Christi, Texas market. In February 2018, we announced that Cactus II Pipeline was fully committed with long-term third-party contracts following the conclusion of a second binding open season. Cactus II Pipeline will have a capacity of 670,000 barrels per day and is expected to be placed into partial service in the second half of 2019.

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Wink to Webster Pipeline. In January 2019, we announced the formation of Wink to Webster Pipeline LLC (“W2W Pipeline”), a joint venture with subsidiaries of ExxonMobil and Lotus Midstream, LLC. We own a 20% interest in W2W Pipeline, which is currently developing a new pipeline system that will originate in the Permian Basin in West Texas and transport crude oil to the Texas Gulf Coast. The pipeline system will provide more than 1 million barrels per day of crude oil and condensate capacity, and the project is targeted to commence operations in the first half of 2021.

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•	approximately 77 million barrels of crude oil storage capacity primarily at our terminalling and storage locations;

•	approximately 32 million barrels of NGL storage capacity;

•	approximately 63 billion cubic feet (“Bcf”) of natural gas storage working gas capacity;

•	approximately 25 Bcf of owned base gas;

•	seven 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 211,000 barrels per day, and an isomerization and fractionation facility in California with an aggregate processing capacity of approximately 15,000 barrels per day;

•	33 crude oil and NGL rail terminals located throughout the United States and Canada. See “Rail Facilities” below for an overview of various terminals and “Supply and Logistics” regarding our use of railcars;

•	five marine facilities in the United States; and

•	approximately 425 miles of active pipelines that support our facilities assets.

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

(2)	While natural gas processing volumes and capacity amounts are presented, they currently are not a significant driver of our segment results.

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

(4)	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.

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•	the purchase of U.S. and Canadian crude oil at the wellhead, and the bulk purchase of crude oil at pipeline, terminal and rail facilities;

•	the storage of inventory during contango market conditions and the seasonal storage of NGL and natural gas;

•	the purchase of NGL from producers, refiners, processors and other marketers;

•	the extraction of NGL from gas processed at our facilities;

•	the resale or exchange of crude oil and NGL at various points along the distribution chain to refiners, operators of petrochemical facilities, exporters or other resellers; and

•	the transportation of crude oil and NGL on trucks, barges, railcars, pipelines and vessels from various delivery points, market hub locations or directly to end users such as refineries, processors and fractionation facilities.

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•	15 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;

•	750 trucks and 900 trailers; and

•	9,100 crude oil and NGL railcars.

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•	an individual who is a citizen or resident of the United States;

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•	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 subjected 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.

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•	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

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•	our Class A shares constitute a United States real property interest by reason of our status as a United States real property holding corporation (“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.

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•	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.

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•	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.

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•	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;

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•	domestic and international economic, legal and regulatory factors related to PAA’s performance; and

•	other factors described in these “Risk Factors.”

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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;

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◦	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).

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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

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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.

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•	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.

•	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 growth 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;

•	Despite the fact that PAA will expend significant amounts of capital during the construction phase of these 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;

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•	PAA may construct pipelines, facilities or other assets in anticipation of market demand that dissipates or market growth that never materializes;

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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 have no control.

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•	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.

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•	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);

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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.

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•	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.

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(1)	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 14 to our Consolidated Financial Statements for additional information.

(2)	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.

(3)	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.

(4)

Facilities segment total is 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.

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•	Executive Summary

•	Acquisitions and Capital Projects

•	Critical Accounting Policies and Estimates

•	Recent Accounting Pronouncements

•	Results of Operations

•	Outlook

•	Liquidity and Capital Resources

•	Favorable regional crude oil differentials and higher lease gathering and NGL margins in our Supply and Logistics segment, as well as more favorable impacts in the 2018 period from the mark-to-market of certain derivative instruments;

•	Favorable results from our Transportation segment, primarily from our pipelines in the Permian Basin region, driven by higher volumes from increased production and our recently completed capital expansion projects, which more than offset the impact of asset sales;

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•	Net gains recognized during the 2018 period associated with asset sales (including a gain on the sale of a portion of our interest in BridgeTex), as compared to net losses recognized during the 2017 period associated with asset sales, impairments and accelerated depreciation; and

•	Lower interest expense primarily driven by a lower weighted average debt balance in the 2018 period as a result of our efforts to implement the PAA Leverage Reduction Plan announced in August 2017 (discussed further below).

(1)	Acquisitions of initial investments or additional interests in unconsolidated entities are included in “Acquisition capital.” Subsequent contributions to unconsolidated entities related to expansion projects of such entities are recognized in “Expansion capital.” We account for our investments in such entities under the equity method of accounting.

(2)	Capital expenditures made to expand the existing operating and/or earnings capacity of our assets are classified as “Expansion 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.”

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(1)	Represents pipeline projects with takeaway capacity out of the Permian Basin, including our Sunrise expansion and our 65% interest in the Cactus II Pipeline.

(2)	These projects will continue into 2019. See “—Liquidity and Capital Resources—Acquisitions, Investments, Expansion Capital Expenditures and Divestitures —2019 Capital Projects.”

(3)	Includes projects at our St. James, Fort Saskatchewan and Cushing terminals.

(4)	Represents contributions related to our 50% interest in Diamond Pipeline LLC.

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(1)	Net of amounts paid for the remaining interest in a non-core pipeline that was subsequently sold.

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•	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.

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

(2)	Effective for the fourth quarter of 2018, we reclassified amounts related to gains and losses on asset sales and asset impairments from “Depreciation and amortization” to “(Gains)/losses on asset sales and asset impairments, net” on our Consolidated Statements of Operations. This change was applied retrospectively. See Note 1 to our Consolidated Financial Statements for additional discussion.

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(1)	Over the past several years, we have increased our participation in strategic pipeline joint ventures, which are accounted for under the equity method of accounting. We exclude our proportionate share of the depreciation and amortization expense and gains and losses on significant asset sales by 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, as well as the mark-to-market adjustment related to our Preferred Distribution Rate Reset Option. See Note 13 to our Consolidated Financial

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(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 writedowns 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 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 17 to our Consolidated Financial Statements for a comprehensive 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 gains and losses that were not related to our core operating results for the period 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 18 to our Consolidated Financial Statements for additional information regarding the Line 901 incident.

(8)	Includes acquisition-related expenses associated with the ACC Acquisition in February 2017. See Note 7 to our Consolidated Financial Statements for additional information.

(9)	Includes net losses incurred in connection with the early redemption of our (i) $600 million, 6.50% senior notes due May 2018 and (ii) $350 million, 8.75% senior notes due May 2019. See Note 11 to our Consolidated Financial Statements for additional information.

(10)	Adjusted EBITDA includes Other income/(expense), net per our Consolidated Statements of Operations, adjusted for selected items impacting comparability (“Adjusted Other income/(expense), net”). Segment Adjusted EBITDA does not include Adjusted Other income/(expense), net.

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

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

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

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Permian Basin region. Total revenues, net of purchases and related costs, increased by approximately $218 million for the year ended December 31, 2018 compared to the year ended December 31, 2017 and by approximately $174 million for the year ended December 31, 2017 compared to the year ended December 31, 2016 primarily due to higher volumes from increased production and our recently completed capital expansion projects. These increases included (i) higher volumes on our gathering systems of approximately 329,000 and 163,000 barrels per day, including our ACC system, which was acquired in February 2017, (ii) higher volumes of approximately 363,000 and 263,000 barrels per day on our intra-basin pipelines and (iii) a volume increase of approximately 185,000 and 283,000 barrels per day on our long-haul pipelines, including our Sunrise pipeline expansion, which was placed in service in the fourth quarter of 2018, as well as our equity interest in BridgeTex discussed further below.

•	South Texas / Eagle Ford region. Equity earnings from our 50% interest in Eagle Ford Pipeline LLC was favorably impacted for each of the comparative periods by higher volumes from our Cactus pipeline.

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Central region. The decrease in revenues for the year ended December 31, 2018 compared to the year ended December 31, 2017 was primarily due to the sale of certain of our Mid-Continent Area System assets in the fourth quarter of 2017, including the sale of a portion of our interest in our Midway pipeline for which our remaining interest is now accounted for under the equity method of accounting. However, such unfavorable results were partially offset by additional movements on our Red River pipeline in 2018.

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Gulf Coast region. The decrease in revenues for the year ended December 31, 2018 compared to the year ended December 31, 2017 was primarily due to (i) lower volumes on the Capline pipeline once the Diamond joint venture pipeline was placed in service in late 2017 and (ii) taking the Capline pipeline out of service beginning in the fourth quarter of 2018. We are currently pursuing an opportunity to reverse the flow of the pipeline. See the “Outlook—Outlook for Certain Idled and Underutilized Assets” section below for additional information.

•	Rocky Mountain region. The decrease in revenues and volumes for the year ended December 31, 2018 compared to the year ended December 31, 2017 was primarily due to the sale of certain pipelines and related assets in the fourth quarter of 2017 and the second quarter of 2018, partially offset by higher volumes on certain of our remaining pipelines.

•

Other. The increase in other revenue for the year ended December 31, 2018 compared to the year ended December 31, 2017 was primarily due to greater loss allowance revenue driven by higher volumes and prices in 2018. The decrease in volumes on our Canadian crude oil pipelines in 2018 compared to 2017 was partially due to the temporary outage of a connecting carrier. Additionally, the impact on revenues from the decrease in volumes was partially offset by increased tariff rates on certain of the pipelines.

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

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

(5)	The decrease in average monthly working capacity of natural gas storage facilities over the comparative periods was driven by adjustments for (i) the sale of our Bluewater natural gas storage facility in June 2017, (ii) changes in base gas and (iii) the net capacity change between capacity additions from fill and dewater operations and capacity losses from salt creep.

(6)

Facilities segment total volumes is 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.

•

NGL Storage, NGL Fractionation and Canadian Gas Processing. Revenues decreased by $14 million for the year ended December 31, 2018 compared to the year ended December 31, 2017 primarily due to the sale of a natural gas processing facility in the second quarter of 2018 and decreases in fees at certain of our storage and fractionation facilities. These unfavorable variances were partially offset by the favorable impacts of (i) increased volumes and fees associated with placing an additional 1.6 million barrels of NGL storage capacity into service in the second half of 2017 at our Fort Saskatchewan facility and (ii) higher volumetric gains at certain facilities in the 2018 period.

•	Crude Oil Storage. Revenues decreased by $16 million for the year ended December 31, 2018 compared to the year ended December 31, 2017 primarily due to the sale of certain of our Bay Area, California terminal assets in December 2017. These lower results were partially offset by higher revenues from increased activity at our Cushing and St. James terminals.

•

Natural Gas Storage. Revenues, net of purchases and related costs, decreased by $2 million for the year ended December 31, 2018 compared to the year ended December 31, 2017 primarily due to (i) the June 2017 sale of our Bluewater natural gas storage facility, (ii) the absence of a one-time fee recognized during the first quarter of 2017 related to the early termination of a storage contract at our Pine Prairie facility and (iii) increased storage costs incurred to manage customer activity in 2018. These unfavorable impacts were partially offset by the favorable impact of expiring contracts replaced at higher rates and more favorable market conditions for hub services at certain of our natural gas storage facilities.

	Revenues decreased slightly for the year ended December 31, 2017 compared to the same 2016 period. Lower results due to the June 2017 sale of our Bluewater natural gas storage facility were largely offset by contributions from higher rates on new contracts replacing expiring contracts and more favorable market conditions for hub services.

•	Rail Terminals. Revenues increased by $26 million for the year ended December 31, 2018 compared to the year ended December 31, 2017 primarily due to higher activity at certain of our rail terminals resulting from more favorable market conditions.

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(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 20 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.

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Crude Oil Operations. Net revenues from our crude oil supply and logistics operations increased for the year ended December 31, 2018 compared to the year ended December 31, 2017 primarily due to favorable grade differentials, primarily in the Permian Basin and Western Canada. Such favorable impacts more than offset the benefit to the 2017 period of the contango market conditions. See the “Market Overview and Outlook” section below for additional discussion of recent market conditions.

•

NGL Operations. Net revenues from our NGL operations increased for the year ended December 31, 2018 compared to the same period in 2017 primarily due to (i) an audit recovery in 2018 related to a profit-sharing arrangement, (ii) lower supply costs at our straddle plants relative to NGL values, (iii) favorable impacts from a wider isobutane/normal butane differential and (iv) modifications made to our contracting strategies in the 2017-2018 heating season.

•

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

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Long-Term Inventory Costing Adjustments. Our net revenues are impacted by changes in the weighted average cost of our crude oil and NGL inventory pools that result from price movements during the periods. These costing adjustments related to long-term inventory necessary to meet our minimum inventory requirements in third-party assets and other working inventory that was needed for our commercial operations. 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 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 increase in field operating costs for the year ended December 31, 2018 compared to the year ended December 31, 2017 was primarily driven by higher third-party trucking costs due to an increase in lease gathering volumes and higher fuel costs due to longer hauls and increased volumes.

•

Segment General and Administrative Expenses. The increase in segment general and administrative expenses for the year ended December 31, 2018 compared to the year ended December 31, 2017 was primarily driven by (i) an increase in equity-indexed compensation expense due to a smaller impact from the decrease in PAA unit price for the 2018 period compared to the decrease in PAA unit price for the 2017 period as well as shorter service periods for awards outstanding during 2018 compared to 2017 and (ii) an increase in personnel costs due primarily to general salary increases and employee severance costs associated with personnel reductions. A portion of equity-indexed compensation expense was associated with awards that will or may be settled in PAA common units (which impact our general and administrative expenses but are excluded from Segment Adjusted EBITDA and thus are reflected as an “Adjustment” in the table above).

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•	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.

(1)	Excludes commitment and other fees.

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

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

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(1)	Amounts outstanding under the PAA commercial paper program reduce available capacity under the facilities. There were no outstanding PAA commercial paper borrowings at December 31, 2018.

(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 $166 million and $18 million, respectively.

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(1)	Amounts reflect our expectation that certain projects will be owned in a joint venture structure with a proportionate share of the project cost dispersed among the partners.

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(1)	Amounts are net of costs associated with the offerings.

(2)	We pay commissions to our sales agents in connection with issuances of Class A shares under our Continuous Offering Program. We paid $1 million of such commissions during the year ended December 31, 2017.

(3)

Pursuant to the Omnibus Agreement entered into in conjunction with the Simplification Transactions, we used the net proceeds from the sale of our Class A shares, after deducting the sales agents’ commissions and offering expenses, to purchase from AAP a number of AAP units equal to the number of Class A shares sold in such offering at a price equal to the net proceeds from such offering. Also pursuant to the Omnibus Agreement, immediately following such purchase and sale, AAP used the net proceeds it received from such sale of AAP units to us to purchase from PAA an equivalent number of common units of PAA.

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(1)	Amounts are net of costs associated with the offerings.

(2)	PAA pays commissions to its sales agents in connection with common unit issuances under its Continuous Offering Program. PAA paid $1 million and $8 million of such commissions during 2017 and 2016, respectively. The net proceeds from these offerings were used for general partnership purposes.

(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. The net proceeds from the offering were used to repay outstanding borrowings under the credit facilities or the PAA commercial paper program and for general partnership purposes.

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(1)	These senior notes were repaid with cash on hand and proceeds from borrowings under the PAA credit facilities and commercial paper program.

(2)	In conjunction with the early redemptions of these PAA senior notes, we recognized a loss of approximately $40 million, recorded to “Other income/(expense), net” in our Consolidated Statement of Operations.

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(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 the credit agreements and the PAA commercial paper program, if any. Although there may be short-term borrowings under the PAA credit agreements and the PAA 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 the PAA credit agreements or the PAA commercial paper program) in the amounts above. For additional information regarding our debt obligations, see Note 11 to our Consolidated Financial Statements.

(2)	Leases are primarily for (i) railcars, (ii) land and surface rentals, (iii) office buildings, (iv) pipeline assets and (v) vehicles and trailers. Includes operating and capital leases as defined by FASB guidance, as well as obligations for rights-of-way easements.

(3)

Includes (i) other long-term liabilities, (ii) storage, processing and transportation agreements and (iii) noncancelable commitments related to our capital expansion projects, including projected contributions for our share of the capital spending of our equity method investments. The transportation agreements include approximately $750 million associated with an agreement to transport crude oil at posted tariff rates on a pipeline that is owned by an equity method investee, in which we own a 50% interest. Our commitment to transport is supported by crude oil buy/sell agreements with third parties (including Oxy) with commensurate quantities.

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(4)

Amounts are primarily based on estimated volumes and market prices based on average activity during December 2018. 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.

(1)	Asset is currently under construction by the entity and has not yet been placed in service.

(2)	We serve as operator of the pipeline.

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•	Crude oil

•	Natural gas

•	NGL and other

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*	Effective March 1, 2019

(1)	Executive officer (for purposes of Item 401(b) of Regulation S-K)

(2)	Director

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†	Filed herewith.

††	Furnished herewith.

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•	the permanent elimination of PAA’s incentive distribution rights (“IDRs”) and the economic rights associated with its 2% general partner interest in exchange for the issuance by PAA to AAP of 245.5 million PAA common units (including approximately 0.8 million units to be issued in the future) and the assumption by PAA of all of AAP’s outstanding debt ($642 million);

•	the implementation of a unified governance structure pursuant to which the board of directors of GP LLC was eliminated and an expanded board of directors of our general partner assumed oversight responsibility over both us and PAA;

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the provision for annual shareholder elections beginning in 2018 for the purpose of electing certain directors, and the participation of PAA’s common unitholders and Series A preferred unitholders in such elections through PAA’s ownership of our Class C shares, which provide PAA, as the sole holder of such Class C shares, the right to vote, as directed by PAA’s common and Series A preferred unitholders, in elections of eligible directors together with the holders of our Class A and Class B shares;

•

the execution by AAP of a reverse split to adjust the number of AAP units such that the number of outstanding AAP units (assuming the conversion of AAP Class B units (the “AAP Management Units”) into AAP units) equaled the number of PAA common units received by AAP at the closing of the Simplification Transactions. Simultaneously, we executed reverse splits to adjust the number of (i) Class A shares outstanding to equal the number of AAP units we owned following AAP’s reverse unit split and (ii) Class B shares outstanding to equal the number of AAP units owned by AAP’s unitholders other than us following AAP’s reverse unit split. These reverse splits, along with the Omnibus Agreement, resulted in economic alignment between our Class A shareholders and PAA’s common unitholders, such that the number of outstanding Class A shares equals the number of AAP units owned by us, which in turn equals the number of PAA common units held by AAP that are attributable to our interest in AAP. The Plains Entities also entered into an Omnibus Agreement, pursuant to which such one-to-one relationship will be maintained subsequent to the closing of the Simplification Transactions; and

•

the creation of a right for certain holders of the AAP units to cause AAP to redeem such AAP units in exchange for an equal number of PAA common units held by AAP. Holders of AAP units other than us and GP LLC continue to have the right to exchange their AAP units (together with the corresponding Class B shares and, if applicable, units of our general partner) for our Class A shares on a one-for-one basis.

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•	The limited partners of PAA and AAP lack (i) substantive “kick-out rights” (i.e., the right to remove the general partner) based on a simple majority or lower vote and (ii) substantive participation rights and thus lack the ability to block actions of the general partner that most significantly impact the economic performance of PAA and AAP, respectively.

•	AAP is the primary beneficiary of PAA because it has the power to direct the activities that most significantly impact PAA’s performance and the right to receive benefits, and obligation to absorb losses, that could be significant to PAA.

•	PAGP is the primary beneficiary of AAP because it has the power to direct the activities that most significantly impact AAP’s performance and the right to receive benefits, and obligation to absorb losses, that could be significant to AAP.

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(1)	Includes approximately $116 million associated with crude oil sales agreements that are entered into in conjunction with storage arrangements and future inventory exchanges. Such amount is expected to be recognized as revenue in the first quarter of 2019.

(2)	Includes $100 million associated with long-term capacity agreements with Cactus II Pipeline LLC. See Note 9 for additional information.

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(1)	Includes revenues from certain contracts for which the amount and timing of revenue is subject to the completion of underlying construction projects.

•	Minimum volume commitments related to the assets of equity method investees — Contracts include those related to the Eagle Ford, BridgeTex, STACK, Caddo, Saddlehorn, White Cliffs, Cheyenne, Diamond and Cactus II pipeline systems;

•	Acreage dedications — Contracts include those related to the Permian Basin, Eagle Ford, Central, Rocky Mountain and Canada regions;

•	Supply and Logistics buy/sell arrangements — Contracts include agreements with future committed volumes on certain Permian Basin, Eagle Ford, Central and Canada region systems;

•	All other Supply and Logistics contracts, due to the election of practical expedients related to variable consideration and short-term contracts, as discussed below;

•	Transportation and Facilities contracts that are short-term, as discussed below;

•	Contracts within the scope of ASC Topic 840, Leases; and

•	Contracts within the scope of ASC Topic 815, Derivatives and Hedging.

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(1)	The balance is comprised primarily of accounts receivable associated with buy/sell arrangements that are not within the scope of Topic 606.

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(1)	Price per unit of measure is comprised of a weighted average associated with various grades, qualities and locations. Accordingly, these prices may not coincide with any published benchmarks for such products.

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(1)	We include rights-of-way, which are intangible assets, in our Pipelines and related facilities amounts within property and equipment.

•	whether there is an indication of 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.

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•	certain of our Bay Area terminal assets located in California;

•	our Bluewater natural gas storage facility located in Michigan;

•	certain non-core pipelines in the Rocky Mountain and Bakken regions, including PAA’s interest in SLC Pipeline LLC;

•	non-core pipeline segments primarily located in the Midwestern United States; and

•	a 40% undivided interest in a segment of our Red River Pipeline extending from Cushing, Oklahoma to the Hewitt Station near Ardmore, Oklahoma for our net book value.

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(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 currently under construction by the entity and has not yet been placed in service.

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(1)	We include rights-of-way, which are intangible assets, in our pipeline and related facilities amounts within property and equipment. See Note 6 for a discussion of property and equipment.

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(1)	We classified these PAA commercial paper notes and credit facility borrowings as short-term as of December 31, 2017, as these notes and borrowings were primarily designated as working capital borrowings, were required to be repaid within one year and were primarily for hedged NGL and crude oil inventory and NYMEX and ICE margin deposits.

(2)	As of December 31, 2018, we classified the $500 million, 2.60% PAA senior notes due December 2019 as long-term, and as of December 31, 2017, we classified a portion of the PAA commercial paper notes and the PAA senior unsecured hedged inventory facility borrowings as long-term based on our ability and intent to refinance such amounts on a long-term basis.

(3)	PAA’s fixed-rate senior notes had a face value of approximately $9.0 billion at both December 31, 2018 and 2017. We estimated the aggregate fair value of these notes as of December 31, 2018 and 2017 to be approximately $8.6 billion

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(1)	These senior notes were repaid with cash on hand and proceeds from borrowings under the PAA credit facilities and commercial paper program.

(2)	In conjunction with the early redemptions of these PAA senior notes, we recognized a loss of approximately $40 million, recorded to “Other income/(expense), net” in our Consolidated Statement of Operations.

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•	grant liens on certain property;

•	incur indebtedness, including capital leases;

•	sell substantially all of its assets or enter into a merger or consolidation;

•	engage in certain transactions with affiliates; and

•	enter into certain burdensome agreements.

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(1)	Amounts are net of costs associated with the offerings.

(2)	We pay commissions to our sales agents in connection with issuances of Class A shares under our Continuous Offering Program. We paid $1 million of such commissions during the year ended December 31, 2017.

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(1)	Amounts are net of costs associated with the offerings.

(2)	PAA pays commissions to sales agents in connection with common unit issuances under its Continuous Offering Program. PAA paid $1 million and $8 million of such commissions during 2017 and 2016, respectively.

(1)

During the Initial Distribution Period, PAA elected to pay distributions on its Series A preferred units in additional Series A preferred units. The Initial Distribution Period ended with the February 2018 distribution; as such, with respect to quarters ending after the Initial Distribution Period, distributions on PAA’s Series A preferred units are paid in cash. During 2018, 2017 and 2016, PAA issued additional Series A preferred units in lieu of cash distributions of $37 million, $139 million and $89 million, respectively.

(2)	PAA paid a pro-rated initial distribution on the Series B preferred units on November 15, 2017 to holders of record at the close of business on November 1, 2017 in an amount equal to approximately $5.9549 per unit.

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(1)

Prior to the Simplification Transactions, AAP was entitled to receive (i) distributions with respect to its 2% indirect general partner interest in PAA and (ii) as the holder of PAA’s IDRs, incentive distributions if the amount PAA distributed with respect to any quarter exceeded certain specified levels. The Simplification Transactions, which closed on November 15, 2016, included the permanent elimination of PAA’s IDRs and the economic rights associated with its 2% general partner interest in exchange for the issuance by PAA to AAP of approximately 244.7 million common units. As such, beginning with the distribution pertaining to the fourth quarter of 2016, AAP is no longer entitled to receive distributions on the IDRs or general partner interest. During the years ended December 31, 2018 and 2017, AAP received distributions on the PAA common units it owned.

(1)

Includes $33 million that was borrowed under the AAP senior secured revolving credit facility. AAP agreed to borrow funds under its credit agreement as necessary to make a special true-up distribution to its partners that, when added to the distributions paid to AAP in respect of its 2% general partner interest in PAA and the IDRs, equaled the total distribution its partners would have received if the closing of the Simplification Transactions had occurred immediately prior to the record date for the third quarter distribution.

(2)	The amount of the distribution paid to AAP’s partners in November 2016 assumed that the Simplification Transactions had closed as of the date of record for the third quarter distribution. Pursuant to the Omnibus Agreement entered into as part of the Simplification Transactions, AAP’s expenses will be paid by PAA. Therefore, no cash was reserved from this distribution for future expenses of AAP.

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•	A net long position of 3.4 million barrels associated with our crude oil purchases, which was unwound ratably during January 2019 to match monthly average pricing.

•	A net short time spread position of 10.1 million barrels, which hedges a portion of our anticipated crude oil lease gathering purchases through March 2020.

•	A crude oil grade basis position of 54.6 million barrels through December 2020. These derivatives allow us to lock in grade basis differentials.

•	A net short position of 6.1 million barrels through March 2021 related to anticipated net sales of our crude oil and NGL inventory.

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(1)	Derivatives not designated as a hedge. For the year ended December 31, 2016, Supply and Logistics segment revenues includes a gain of $2 million related to derivatives in hedging relationships.

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(2)	Derivatives in hedging relationships.

(1)	Derivatives in hedging relationships.

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(1)	Derivative assets and liabilities are presented above on a net basis but do not include related cash margin deposits.

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•	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; and

•	our ability to lend proceeds of any future indebtedness incurred by us to AAP, and AAP’s corresponding ability to lend such proceeds to PAA, in each case on substantially the same terms as incurred by us.

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(1)	A majority of these revenues are included in “Supply and Logistics segment revenues” on our Consolidated Statements of Operations.

(2)	Crude oil purchases that are part of inventory exchanges under buy/sell transactions are netted with the related sales, with any margin presented in “Purchases and related costs” in our Consolidated Statements of Operations.

(1)	We have a netting arrangement with certain related parties. Receivables and payables are presented net of such amounts.

(2)	Includes amounts related to crude oil purchases and sales, transportation services and amounts owed to us or advanced to us related to expansion projects of equity method investees where we serve as construction manager.

(3)	We have an agreement to transport crude oil at posted tariff rates on a pipeline that is owned by an equity method investee, in which we own a 50% interest. Our commitment to transport is supported by crude oil buy/sell agreements with third parties (including Oxy) with commensurate quantities.

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(1)	Of the 29.0 million total awards authorized, 12.4 million awards are currently available. The remaining balance has already vested or is currently outstanding.

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(1)	Amounts do not include PAGP LTIP awards.

(2)

Approximately 0.6 million, 0.6 million and 0.5 million PAA common units were issued, net of tax withholding of approximately 0.2 million, 0.2 million and 0.3 million units during 2018, 2017 and 2016, respectively, in connection with the settlement of vested awards. The remaining PAA awards (approximately 0.9 million, 0.9 million and 1.1 million units) that vested during 2018, 2017 and 2016, respectively, were settled in cash.

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(1)	Amounts do not include fair value associated with awards containing performance conditions that are not considered to be probable of occurring at December 31, 2018.

(1)

Includes operating and capital leases as defined by FASB guidance, as well as obligations for rights-of-way easements. Leases are primarily for (i) railcars, (ii) land and surface rentals, (iii) office buildings, (iv) pipeline assets and (v) vehicles and trailers. We recognize expense on a straight-line basis over the life of the agreement, as applicable. Lease expense for 2018, 2017 and 2016 was $199 million, $207 million and $198 million, respectively.

(2)

Primarily includes third-party storage and transportation agreements and pipeline throughput agreements, as well as approximately $750 million associated with an agreement to transport crude oil at posted tariff rates on a pipeline that is owned by an equity method investee, in which we own a 50% interest. Our commitment to transport is supported by crude oil buy/sell agreements with third parties (including Oxy) with commensurate quantities. Expense associated with these storage, transportation and throughput agreements was approximately $228 million, $197 million and $157 million for 2018, 2017 and 2016, respectively.

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(1)	The sum of the four quarters may not equal the total year due to rounding.

(2)	Gross margin is calculated as Total revenues less (i) Purchases and related costs, (ii) Field operating costs, (iii) Depreciation and amortization and (iv) (Gains)/losses on asset sales and asset impairments, net.

(3)	Represents cash distributions declared and paid in the period presented.

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(1)

Transportation revenues from external customers include certain inventory exchanges with our customers where our Supply and Logistics segment has transacted the inventory exchange and serves as the shipper on our pipeline systems. See Note 3 for a discussion of our related accounting policy. We have included an estimate of the revenues from these inventory exchanges in our Transportation segment revenue from external customers presented above and adjusted those revenues out such that Total revenue from External customers reconciles to our Consolidated Statements of Operations. This presentation is consistent with the information provided to our CODM.

(2)

Segment revenues include intersegment amounts that are eliminated in Purchases and related costs and Field operating costs in our Consolidated Statements of Operations. Intersegment activities are conducted at posted tariff rates where applicable, or otherwise at rates similar to those charged to third parties or rates that we believe approximate market at the time the agreement is executed or renegotiated.

(3)	Expenditures for acquisition capital and expansion capital, including investments in unconsolidated entities.

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(1)	Represents adjustments utilized by our CODM in the evaluation of segment results.

(2)	Includes our proportionate share of the depreciation and amortization and gains and losses on significant asset sales of equity method investments.

(3)

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, 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 Segment 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.

(4)

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 exclude the impact of changes in the average cost of the long-term inventory (that result from fluctuations in market prices) and writedowns of such inventory that result from price declines from Segment Adjusted EBITDA.

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(5)

We 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. Our CODM views the inclusion of the contractually committed revenues associated with that period as meaningful to Segment Adjusted EBITDA 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.

(6)	Includes equity-indexed compensation expense associated with awards that will or may be settled in units.

(7)	Includes gains and losses from the revaluation of foreign currency transactions and monetary assets and liabilities.

(8)	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 18 for additional information regarding the Line 901 incident.

(9)	Includes acquisition-related expenses associated with the ACC Acquisition. See Note 7 for additional discussion. An adjustment for these non-recurring expenses is included in the calculation of Segment Adjusted EBITDA for the year ended December 31, 2017 as our CODM does not view such expenses as integral to understanding our core segment operating performance.

(1)	Revenues are primarily attributed to each region based on where the services are provided or the product is shipped.

(1)	Excludes long-term derivative assets and long-term deferred tax assets.