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 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;

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

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

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

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

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

•	the occurrence of a natural disaster, catastrophe, terrorist attack (including eco-terrorist attacks) or other event, including 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;

•	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 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;

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

•	the effectiveness of our risk management activities;

•	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;

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•	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;

•	factors affecting demand for natural gas and natural gas storage services and rates;

•	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 and refined products, 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)	We will hold an annual meeting for the election of eligible PAGP GP directors beginning in 2018. See Item 10. “Directors and Executive Officers of our General Partner and Corporate Governance” for further information regarding governance of the Plains Entities, including changes as a result of the Simplification Transactions.

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(1)	As of December 31, 2016, the PAGP GP Board consisted of 10 members. In February 2017, the limited liability agreement of PAGP GP was amended and restated to provide for two additional directors. See Item 10. “Directors and

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(2)	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 the rate of approximately 0.941 AAP units for each AAP Management Unit.

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

(4)	Each Class C share represents a non-economic limited partner interest in us and carries with it the right to vote, pro rata with the holders of our Class A and Class B shares, for the election of eligible PAGP GP directors.

(5)	Amount does not include 792,074 PAA common units that will become issuable to AAP that relate to AAP Management Units that are outstanding but not earned. See Note 16 to our Consolidated Financial Statements for additional discussion of the AAP Management Units.

(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 BridgeTex Pipeline Company, LLC (“BridgeTex”), Butte Pipe Line Company (“Butte”), 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”), Frontier Aspen LLC (“Frontier”), Saddlehorn Pipeline Company, LLC (“Saddlehorn”), Settoon Towing, LLC (“Settoon Towing”), STACK Pipeline LLC (“STACK”) and White Cliffs Pipeline LLC (“White Cliffs”).

•	optimizing its existing assets and realizing cost efficiencies through operational improvements;

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

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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; 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 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.

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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 base level of 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 a base level of margin, the amount of which may vary depending on market conditions (such as commodity price levels, differentials and certain competitive factors). In certain market scenarios, PAA may be able to realize incremental margins that meaningfully exceed such base levels.

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PAA has the evaluation, integration and engineering skill sets and the financial flexibility to continue to pursue acquisition and expansion opportunities. Since 1998, PAA has completed and integrated over 90 acquisitions with an aggregate purchase price of approximately $13.2 billion including the February 2017 acquisition of the Alpha Crude Connector gathering system. Since 1998, PAA has also implemented expansion capital projects totaling approximately $11.4 billion. In addition, considering PAA’s investment grade credit rating, liquidity and capital structure, we believe PAA has the financial resources and strength necessary to finance future strategic expansion and acquisition opportunities. As of December 31, 2016, PAA had approximately $2.4 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 31 years of industry experience, and an average of 19 years with PAA or its predecessors and affiliates. In addition, through their ownership of PAA common units, grants of phantom units and interests in us, AAP units and AAP Management Units, 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 (adjusted EBITDA is earnings before interest, taxes, depreciation and amortization and further 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)

Excludes PAA’s acquisition of all of the outstanding publicly-traded common units of PAA Natural Gas Storage, L.P. (“PNG”) on December 31, 2013 (referred to herein as the “PNG Merger”), as we historically consolidated PNG into our financial statements for financial reporting purposes in accordance with generally accepted accounting principles in the United States (“GAAP”). As consideration for the PNG Merger, PAA issued approximately 14.7 million of its common units with a value of approximately $760 million.

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

(3)	Purchase price subject to working capital and other adjustments. See Note 6 to our Consolidated Financial Statements for additional information regarding this acquisition.

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

(5)	Approximate purchase price of $1.075 billion, net of working capital acquired. PAA accounts for its 50% interest in BridgeTex under the equity method of accounting.

(6)	Purchase price includes approximately $17 million of imputed interest. A prepayment of $50 million was made during 2011. Approximate purchase price of $1.192 billion, net of working capital, linefill and long-term inventory acquired.

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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.

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(1)	Amounts are derived from the EIA’s Short-Term Energy Outlook.

(2)	Amounts may not recalculate due to rounding.

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(1)	Amounts may not recalculate due to rounding.

•	Ethane. 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.

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

•	Normal butane. 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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•	19,200 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;

•	810 trailers (primarily in Canada); and

•	120 transport and storage barges and 60 transport tugs through our interest in Settoon Towing.

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(1)	Ownership percentage varies on each pipeline and gathering system ranging from approximately 20% to 100%.

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

(3)	Pipelines operated by a third party.

(4)	Includes total mileage and volumes (attributable to our interest) from pipelines owned by unconsolidated entities.

(5)	Except for the segment of the All American Pipeline between Pentland and Emidio, the pipeline has been shut down since May 19, 2015, following the Line 901 incident.

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•	approximately 80 million barrels of crude oil and refined products storage capacity primarily at our terminalling and storage locations;

•	approximately 32 million barrels of NGL storage capacity;

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•	approximately 97 Bcf of natural gas storage working capacity;

•	approximately 31 Bcf of owned base gas;

•	nine 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;

•	34 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;

•	six major marine facilities in the United States; and

•	approximately 1,000 miles of active pipelines that support our facilities assets.

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(1)	Amount includes approximately 1 million barrels of capacity for which we hold lease options (all of which have been exercised).

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

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

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

(5)	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, the bulk purchase of crude oil at pipeline, terminal and rail facilities, and the purchase of cargos at their load port and various other locations in transit;

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

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

•	the purchase and sale of natural gas.

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

•	5 million barrels of crude oil and NGL linefill in pipelines owned by third parties and other long-term inventory;

•	820 trucks and 1,065 trailers; and

•	10,660 crude oil and NGL railcars.

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•	Extend reporting requirements to all hazardous liquid gravity and gathering lines;

•	Require inspections of pipelines in areas affected by extreme weather, natural disasters, and other similar events, and periodic inline integrity assessments of pipelines that are located outside of high consequence areas of at least once every ten years;

•	Use of leak detection systems on hazardous liquid pipelines in all locations;

•	Modify the provisions for making pipeline repairs;

•	Require that all pipelines subject to the integrity management requirements be capable of accommodating inline inspection tools within 20 years; and

•	Clarifications to improve certainty and compliance to certain existing regulations.

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•	The Oil Spill Response Bill allows volunteer cleanup crews to be paid as contractors, requires oil skimmers to be placed along the coastline at all times, and prohibits the use of dispersants until the EPA issues rules on dispersant safety.

•	The Pipeline Safety: Inspections Bill (SB 295) mandates annual pipeline inspections commencing January 1, 2017, with the State Fire Marshal responsible for annually inspecting all intrastate pipelines and operators of intrastate pipelines under the jurisdiction of the State Fire Marshal.

•	The Oil Spill Response: Environmentally and Ecologically Sensitive Areas Bill (AB 864) requires automatic shut-offs for pipelines located in environmentally sensitive areas.

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

•	a corporation (or other entity treated as a corporation for U.S. federal income tax purposes) created or organized in or under the laws of the United States, any state thereof or the District of Columbia;

•	an estate the income of which is subject to U.S. federal income tax regardless of its source; or

•	a trust (i) the administration of which is 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

•	our Class A shares constitute a United States real property interest by reason of our status as a USRPHC for U.S. federal income tax purposes.

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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;

•	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;

◦	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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•	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;

•	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 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

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•	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.

•	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 indemnified, or the indemnity is not from a credit-worthy party, 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.

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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 expected, 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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(1)	Cash distributions pertaining to the quarter presented. These distributions were declared and paid in the following calendar quarter.  See the “Cash Distribution Policy” section below for a discussion of our policy regarding distribution payments.

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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;

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(1)	Basic and diluted net income per Class A share for 2013 were calculated based on net income attributable to PAGP for the period following the closing of our initial public offering on October 21, 2013 and basic weighted average Class A shares outstanding weighted for the same period.

(2)	Represents cash distributions declared and paid during the year presented. See Note 11 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) crude oil, refined products and NGL terminalling and storage capacity; (ii) rail load and unload volumes multiplied by the number of days in the year and divided by the number of months in the year; (iii) 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 (iv) 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

•	Market Overview and Outlook

•	Liquidity and Capital Resources

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Lower operating results, primarily due to less favorable crude oil and NGL market conditions, increased competition and the impact of mark-to-market losses on certain derivative instruments, partially offset by (i) contributions from our recently completed acquisition and capital expansion projects and (ii) lower field operating costs, largely due to lower trucking costs associated with our supply and logistics activities and the absence of costs related to the Line 901 incident, which occurred in May 2015;

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Higher depreciation and amortization expense primarily resulting from (i) our recently completed capital expansion projects, (ii) impairment losses related to certain of our rail and other terminal assets and (iii) assets taken out of service and the discontinuation of certain capital projects, all partially offset by net gains related to non-core assets sales and joint venture formations completed during the 2016 period;

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•	Higher interest expense primarily related to financing activities associated with our capital investments;

•	Gains recognized during 2016 related to the mark-to-market impact of our Preferred Distribution Rate Reset Option; and

•	Lower income tax expense primarily due to lower earnings from our Canadian operations and the impact from the cumulative revaluation of Canadian net deferred tax liabilities resulting from an Alberta, Canada provincial tax rate increase enacted during the comparative 2015 period.

(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 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)	We account for our 50% interest in BridgeTex under the equity method of accounting. See Note 8 to our Consolidated Financial Statements for further discussion of our equity method investments.

(1)	In January 2017, we sold an undivided 40% interest in a segment of the Red River Pipeline.

(2)	These projects will continue into 2017. See “—Liquidity and Capital Resources—Acquisitions, Divestitures and Expansion Capital Expenditures—2017 Capital Projects.”

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(3)	Includes railcar purchases, as well as rail projects near St. James, LA; Tampa, CO; Bakersfield, CA; Carr, CO; Manitou, ND; Van Hook, ND; Yorktown, VA; and Kerrobert, Canada rail projects.

(4)	Represents contributions related to our 40% investment interest in Saddlehorn.

(5)	Represents contributions related to our 50% investment interest.

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

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(1)	Over the past several years, we have increased our participation in pipeline strategic joint ventures, which are accounted for under the equity method of accounting. Our proportionate share of the depreciation and amortization expense associated with such unconsolidated entities is excluded when reviewing Adjusted EBITDA, similar to our consolidated pipelines.

(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 12 to our Consolidated Financial Statements for a comprehensive discussion regarding our derivatives and risk management activities.

(3)	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

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(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 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 4 to our Consolidated Financial Statements for additional inventory disclosures.

(5)

Our total equity-indexed compensation expense includes expense associated with awards that will or may be settled in units and awards that will or may be settled in cash. The awards that will or may be settled in units are included in our 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 our diluted net income per unit calculation, as applicable, and the majority of the awards are expected to be settled in 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 16 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 12 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 17 to our Consolidated Financial Statements for additional information.

(8)	Adjusted EBITDA includes Other income/(expense), net adjusted for selected items impacting comparability. Segment adjusted EBITDA is exclusive of such amounts.

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

(2)	Field operating costs and Segment general and administrative expenses exclude equity-indexed compensation expense, which is presented separately in the table above.

(3)	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.

(4)	Represents adjustments included in the performance measure utilized by our CODM in the evaluation of segment results. See Note 19 to our Consolidated Financial Statements for additional discussion of such adjustments.

(5)	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.

(6)	Area systems include volumes (attributable to our interest) from pipelines owned by unconsolidated entities.

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Permian Basin region. The increase in revenues for 2016 compared to 2015 was primarily driven by (i) higher volumes associated with the expansion of our pipeline systems in the Delaware Basin, (ii) higher volumes on our takeaway pipelines and (iii) a full year of service of our Cactus pipeline, which was placed in service in April 2015. Revenues increased for 2015 over 2014 primarily due to (i) results from our Cactus pipeline and (ii) higher volumes related to increased production, primarily associated with the expansion of our pipeline system in the Delaware Basin. The increase in equity earnings for 2015 over 2014 was driven by earnings from our interest in BridgeTex, which we acquired in November 2014.

•

South Texas / Eagle Ford region. Revenues decreased in 2016 compared to 2015 due to production declines in the region. Revenues increased for 2015 over 2014 due to higher volumes driven by the extension of our gathering system and increased production. Equity earnings increased for 2015 over 2014 due to higher earnings from our interest in Eagle Ford Pipeline LLC, primarily driven by higher throughput on the Eagle Ford pipeline system. The higher throughput was due to a combination of (i) the connection to our Cactus pipeline in April 2015 and (ii) increased crude oil production in the Eagle Ford region.

•	Western region. Revenues and volumes decreased for each of the comparative periods presented primarily due to pipeline downtime on our All American Pipeline associated with the Line 901 incident that occurred in the second quarter of 2015. See Note 17 to our Consolidated Financial Statements for additional information regarding this incident.

•	Rocky Mountain region. The decrease in revenues for 2016 compared to 2015 was largely driven by (i) lower volumes due to production declines and increased competition and (ii) the sale of 50% of our investment in Cheyenne Pipeline in June 2016, subsequent to which it was accounted for under the equity method of accounting.

•	Gulf Coast region. Revenues and volumes decreased for 2016 compared to 2015 primarily due to the sale of certain of our Gulf Coast pipelines in March and July 2016. These decreases were partially offset by increased volumes on the Capline and Pascagoula pipelines, which were favorably impacted by higher refinery demand, but were at lower tariff rates than the pipelines that were sold.

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•	Central region. The decrease in revenues for 2016 compared to 2015 was largely driven by lower volumes due to production declines in the Mid-Continent area, as well as the sale of 50% of our investment in STACK in August 2016, subsequent to which it was accounted for under the equity method of accounting.

•	Canada. Revenues decreased for 2016 as compared to 2015 and for 2015 as compared to 2014 due to unfavorable foreign exchange impacts of $9 million and $38 million, respectively, which more than offset revenue increases from higher tariff rates on certain of our pipelines and related system assets in each of the comparative periods.

•	NGL pipelines. Revenues increased for 2016 as compared to 2015 primarily due to contributions from the Western Canada NGL assets we acquired in August 2016.

•	Other. The variances for the comparative periods presented were related to pipeline loss allowance revenue. Loss allowance revenue decreased for the comparative periods presented due to a lower average realized price per barrel. The decrease in loss allowance revenue for 2015 compared to 2014 was partially offset by higher volumes.

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

(2)	Field operating costs and Segment general and administrative expenses exclude equity-indexed compensation expense, which is presented separately in the table above.

(3)	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.

(4)	Represents adjustments included in the performance measure utilized by our CODM in the evaluation of segment results. See Note 19 to our Consolidated Financial Statements for additional discussion of such adjustments.

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

(6)	Facilities segment total is calculated as the sum of: (i) crude oil, refined products and NGL terminalling and storage capacity; (ii) rail load and unload volumes multiplied by the number of days in the year and divided by the number of months in the year; (iii) natural gas storage working capacity divided by 6 to account for the 6:1 mcf of natural gas to

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NGL Storage, NGL Fractionation and Canadian Gas Processing — Revenues increased by $53 million for the year ended December 31, 2016 over the same 2015 period primarily due to (i) contributions from the Western Canada NGL assets we acquired in August 2016, (ii) contributions from ongoing expansion projects at our Fort Saskatchewan facility and (iii) higher fees at certain of our NGL storage and fractionation facilities. Such increases were partially offset by unfavorable foreign exchange fluctuation impacts of $10 million, which were largely offset in our Supply and Logistics segment results.

•

Crude Oil Storage — Revenues increased by $24 million for the year ended December 31, 2016 over the year ended December 31, 2015 primarily due to (i) aggregate capacity expansions of approximately 4 million barrels at our St. James and Cushing terminals and (ii) increased utilization at certain of our West Coast terminals. Such increases were partially offset by lower results due to the sale of certain of our East Coast terminals in April 2016.

•

Rail Terminals — Revenues decreased by $17 million for the year ended December 31, 2016 compared to the year ended December 31, 2015 primarily due to (i) lower volumes at our U.S. terminals as a result of production declines in the Bakken and less favorable market conditions, partially offset by (i) revenue associated with minimum volume commitments at certain of our terminals and (ii) revenues and volumes from our Canadian NGL rail terminal that came online in April 2016.

•	Gulf Coast Gas Processing — Revenues decreased by $13 million for the year ended December 31, 2015 compared to the same 2014 period, primarily due to lower volumes and decreased margins driven by lower commodity prices. Revenues remained relatively consistent for the year ended December 31, 2016 compared to the same 2015 period.

•

Natural Gas Storage Operations — Net revenues decreased by $12 million for the year ended December 31, 2015 compared to the year ended December 31, 2014 primarily due to (i) declines in market rates for natural gas storage, which resulted in lower rates on new contracts replacing expiring contracts, and (ii) reduced hub services opportunities. In addition, the 2014 period was unfavorably impacted by costs incurred to manage deliverability requirements in conjunction with the extended period of severe cold weather experienced during the first quarter of 2014. Revenues remained relatively consistent for the year ended December 31, 2016 compared to the same 2015 period.

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(1)	Revenues and costs include intersegment amounts.

(2)	Field operating costs and Segment general and administrative expenses exclude equity-indexed compensation expense, which is presented separately in the table above.

(3)	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.

(4)	Represents adjustments included in the performance measure utilized by our CODM in the evaluation of segment results. See Note 19 to our Consolidated Financial Statements for additional discussion of such adjustments.

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Crude Oil Operations — Net revenues from our crude oil supply and logistics operations decreased for the year ended December 31, 2016 compared to the year ended December 31, 2015 primarily due to continued and intensifying competition, largely due to overbuilt infrastructure underwritten with volume commitments and the effect of such on differentials, as well as volume declines in certain areas, which negatively impacted our unit margins. See the “Market Overview and Outlook” section below for additional discussion of recent market conditions.

•	NGL Operations — Net revenues from our NGL operations decreased for the year ended December 31, 2016 compared to the year ended December 31, 2015, largely due to (i) higher storage and processing fees for the 2016 periods, which are primarily reflected in our Facilities segment and (ii) higher supply costs driven by competition, which more than offset higher sales volumes.

•	Impact from Certain Derivative Activities, Net of Inventory Valuation Adjustments — The mark-to-market of certain of our derivative activities impacting 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-

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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.

•

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. In addition, the depreciation of CAD relative to USD resulted in lower net USD costs of approximately $15 million for 2016 compared to 2015 and $41 million for 2015 compared to 2014. Such costs are primarily associated with intercompany facility fees and are largely offset in our Facilities segment results.

•	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 on floating rate debt; and

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•	interest capitalized on capital projects.

(1)	Excludes commitment and other fees.

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(1)	Represents availability prior to giving effect to amounts outstanding under the PAA commercial paper program, which reduce available capacity under the facilities.

(2)	Available capacity under the PAA senior unsecured revolving credit facility and the PAA senior secured hedged inventory facility was reduced by outstanding letters of credit of $20 million and $53 million, respectively.

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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 $8 million, $1 million and $9 million of such commissions during 2016, 2015 and 2014, respectively. The net proceeds from these offerings were used for general partnership purposes.

(3)	A portion of the net proceeds from such offering was used to repay borrowings under the PAA commercial paper program and the remaining net proceeds were used for general partnership purposes, including expenditures for our 2015 capital program.

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(1)	Face value of notes less the applicable premium or discount (before deducting for initial purchaser discounts, commissions and offering expenses).

(2)	Face value of notes less the applicable premium or discount, initial purchaser discounts, commissions and offering expenses.

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

(4)	The net proceeds from this offering were used to repay outstanding borrowings under the PAA commercial paper program (a portion of which was used to fund the acquisition of a 50% interest in BridgeTex). See Note 8 to our Consolidated Financial Statements for further discussion.

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(1)	Includes projected capital projects associated with our recently acquired Alpha Crude Connector gathering system.

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(1)

Includes debt service payments, interest payments due on PAA’s senior notes, the commitment fee on assumed available capacity under the PAA credit facilities, and long-term borrowings under the PAA commercial paper program. Although there may be short-term borrowings under the PAA credit facilities 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 facilities or the PAA commercial paper program) in the amounts above. For additional information regarding our debt obligations, see Note 10 to our Consolidated Financial Statements.

(2)	Leases are primarily for (i) surface rentals, (ii) office rent, (iii) pipeline assets and (iv) trucks, trailers and railcars. Includes capital and operating 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) non-cancelable 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 $855 million associated with an agreement to transport crude oil 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.

(4)

Amounts are primarily based on estimated volumes and market prices based on average activity during December 2016. 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.

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(1)	In February 2017, Settoon signed a definitive agreement to sell its Liquid Bulk division that is expected to close in the first half of 2017, subject to customary closing conditions, including receipt of regulatory approvals. Settoon intends to use a portion of the proceeds from such sale to pay off all of its outstanding debt.

•	Crude oil

•	Natural gas

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•	NGL and other

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•	Three of the members are designated to serve on the board of directors of PAGP GP by the three members of PAGP GP that currently hold board designation rights (affiliates of The Energy & Minerals Group, Kayne Anderson Investment Management Inc. and Occidental Petroleum Corporation);

•	Six of the members (three of whom must be independent directors eligible to serve on the audit committee) are elected, and may be removed, by the board of directors of PAGP GP; and

•	One of the members is the Chief Executive Officer and two of the members are appointed by majority vote of the board of directors of PAGP GP.

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*	Indicates chairman of committee.

(1)	Unless otherwise described, the position indicates the position held with GP LLC; directors serve on the board of directors of PAGP GP.

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(2)

The PAGP GP LLC Agreement specifies that the Chief Executive Officer of PAGP GP will be a member of the board of directors. Under the PAGP GP LLC Agreement, three of the members of PAGP GP each have the right to appoint one director each to the PAGP GP board of directors. Mr. Raymond is serving as a member of our board of directors by virtue of his appointment by EMG Investment, LLC (“EMG”), of which he is the sole member of the general partner of its manager. Mr. Sinnott is serving as a member of our board of directors by virtue of his appointment by KAFU Holdings, L.P., which is affiliated with Kayne Anderson Investment Management, Inc., of which he is President. Mr. Figlock is serving as a member of our board of directors by virtue of his appointment by Occidental Holding Company (Pipeline), Inc., a subsidiary of Occidental Petroleum Corporation (“Oxy”), of which he is Vice President and Treasurer.  The remaining directors, other than Mr. Armstrong who serves as a director by virtue of his capacity as CEO of PAGP GP, were appointed pursuant to the PAGP GP LLC Agreement. See Item 12. “Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters—Beneficial Ownership of Plains AAP, L.P.”

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1.	Maintain a solid balance sheet, sound credit metrics and ample liquidity;

2.	Execute PAA’s capital program in order to facilitate cash flow growth underpinned by MVCs and position PAA to benefit meaningfully as U.S. production volumes increase; and

3.	Optimize PAA’s assets and focus the organization to deliver the best results possible under whatever conditions are encountered in the near term.

•	Raising $2.4 billion of common and preferred equity on terms considered by PAA to be fair and reasonable during challenging and volatile market conditions;

•	Completing a complex simplification transaction that significantly reduced PAA’s cost of equity capital and enhanced its ability to fund its activities;

•	Executing a $1.4 billion capital expansion program generally on time and on budget;

•	Initiating and completing approximately $550 million of asset sales at attractive multiples and advancing discussions on an additional $670 million of asset sales transactions that are now fully contracted and expected to close during the first half of 2017;

•	Entering into various joint venture transactions that reduced risk and the level of PAA’s capital commitments;

•	Initiating a review to challenge and reduce operating costs to adapt and strengthen PAA’s organization for the future; and

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•	Executing a strategic NGL acquisition for approximately $204 million and positioning PAA to complete the acquisition of a strategic crude oil gathering system in the Northern Delaware Basin in early 2017 for approximately $1.2 billion.

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(1)

Grant date fair values are presented for (i) LTIP phantom unit grants awarded to Messrs. Swanson, Chiang, McGee and Nerbonne in 2016, (ii) LTIP phantom unit grants awarded to Mr. Chiang in 2015, (iii) AAP Management Unit grants awarded to Mr. Chiang in 2015, and (iv) a portion of an AAP Management Unit grant awarded to Mr. McGee in 2013 and amended in 2016.  Dollar amounts in the table represent the aggregate grant date fair value of phantom units and AAP Management Units awarded based on the probable outcome of underlying performance conditions pursuant to FASB ASC Topic 718.  The amount presented for Mr. McGee includes incremental grant date fair value of $1,139,180 resulting from the modification in 2016 of previously granted AAP Management Unit awards. Specifically, the AAP Management Unit award originally granted to Mr. McGee in March 2013 was amended in 2016 in connection with the Simplification Transactions so that the portion of such grant that had not yet become earned (approximately 61,000 units or 25%) would, instead of becoming earned upon the payment by PAA of an annualized quarterly distribution of $2.85 per common unit, become earned on the first date subsequent to March 31, 2017 upon which PAA pays an annualized quarterly distribution of $2.20 per common unit and generates distributable cash flow of $1.5 billion or more on a trailing four quarter basis (subject to adjustment under certain circumstances to account for significant asset sales). The incremental grant date fair value of $1,139,180 represents the increase in grant date fair value of such award relative to the original March 2013 grant date fair value of such AAP Management units. The modification in 2016 of previously granted LTIP phantom unit awards and AAP Management Unit awards for Messrs. Chiang and Nerbonne did not result in any incremental grant date fair value relative to the grant date fair value of such awards as of their respective dates of issuance. For LTIP phantom unit grants and AAP Management Unit grants awarded in 2015, the performance threshold for the first tranche of vesting was deemed probable of occurring on the grant date.  The aggregate maximum grant date fair value of phantom unit grants and AAP Management Unit grants awarded to Mr. Chiang in 2015, assuming that the highest level of performance conditions will be met, was $17,197,332.  For LTIP phantom unit grants awarded in 2016, the performance thresholds for the first, second and third tranches of vesting were deemed probable of occurring on the grant date.  The maximum grant date fair

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(2)

GP LLC matches 100% of employees’ contributions to its 401(k) plan in cash, subject to certain limitations in the plan. All Other Compensation for 2016 includes $2,348 in such contributions for Mr. Armstrong and $15,900 for each of Messrs. Pefanis, Chiang, Swanson, McGee and Nerbonne. The remaining amount represents premium payments on behalf of such Named Executive Officer for group term life insurance and, for Mr. Nerbonne only, a car allowance of $8,400.

(1)	For a description of the vesting terms of these awards, see “Compensation Discussion and Analysis—Application in 2016—Long Term Incentive Awards”.

(2)	Represents incremental grant date fair value resulting from the modification in 2016 of the unearned portion of AAP Management Unit awards originally granted in March 2013. See Footnote 1 to the Summary Compensation Table for a description.

(3)	These phantom units, which include associated DERs payable in cash, will vest 100% on December 14, 2018.

(4)

Represents the grant date fair values of LTIP phantom units granted in 2016 based on the probable outcome of underlying performance conditions pursuant to FASB ASC Topic 718.  The performance thresholds for the first, second and third tranches of vesting of the LTIP phantom units granted in 2016 was deemed probable of occurring on the grant date.  The aggregate maximum grant date fair value of phantom unit grants awarded in 2016, assuming that the highest level of performance conditions will be met, was $3,115,120 for Mr. Swanson, $3,724,600 for Mr. Chiang, $3,115,120 for Mr. McGee and $2,803,217 for Mr. Nerbonne.

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(1)

Market value of phantom units reported in these columns is calculated by multiplying the closing market price ($32.29) of PAA’s common units at December 30, 2016 (the last trading day of the fiscal year) by the number of units. No discount is applied for remaining performance threshold or service period requirements. Market value of AAP Management Units is calculated by (i) assuming that such AAP Management Units are converted into AAP units based on the conversion factor of approximately 0.941 AAP units and PAGP Class B shares for each AAP Management Unit, (ii) assuming the exchange of the resulting AAP units and PAGP Class B shares for PAGP Class A shares on a one-for-one basis, and (iii) multiplying such resulting number of PAGP Class A shares by the closing market price ($34.68) of PAGP’s Class A shares at December 30, 2016 (the last trading day of the fiscal year).

(2)

Represents the unvested portion of phantom units granted in 2013 under PAA’s Long-Term Incentive Plan.  All performance thresholds have been met.  Accordingly, subject to continued employment, these phantom units will vest as follows:  (i) one-half will vest on the August 2017 distribution date, and (ii) one-half will vest on the August 2018 distribution date.  Upon vesting, the phantom units are payable on a one-for-one basis in PAA common units.  All of the DERs associated with these phantom units are currently payable.  The DERs expire when the associated phantom units vest.

(3)

Represents the pre-conversion number of AAP Management Units held by Mr. Chiang, each of which represents a profits interest in AAP, entitling him to participate in future profits and losses from operations, current distributions from operations, and an interest in future appreciation or depreciation in AAP’s asset values, but does not represent an interest in the capital of AAP on the applicable grant date of the AAP Management Units. These AAP Management Units become earned as follows: 50% will become earned on the first date subsequent to March 31, 2017 upon which PAA pays a quarterly distribution of at least $0.55 per common unit ($2.20 annualized) and generates distributable cash flow of $1.5

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(4)

Represents the pre-conversion number of earned AAP Management Units held by Mr. McGee. Despite the fact that these AAP Management Units are earned, they are treated as stock that has not vested for purposes of this table due to the fact that they remain subject to a call right held by AAP that entitles AAP to purchase such AAP Management Units for (i) an amount equal to 75% of their fair market value upon the termination of employment prior to December 31, 2019 (with respect to 195,755 AAP Management Units) or (ii) an amount equal to 50-75% of their fair market value upon the termination of employment prior to December 31, 2020 (with respect to 183,520 AAP Management Units).

(5)

Represents the remaining 25% of the AAP Management Units originally granted to Mr. McGee in March 2013. These AAP Management Units will become earned on the first date subsequent to March 31, 2017 upon which PAA pays an annualized quarterly distribution of $2.20 per common unit and PAA generates distributable cash flow of $1.5 billion or more on a trailing four quarter basis (subject to adjustment under certain circumstances to account for significant asset sales).

(6)

Represents AAP Management Units originally granted to Mr. Nerbonne in July 2015. These AAP Management Units will become earned as follows: (i) subsequent to March 31, 2017, 25% upon the payment by PAA of an annualized quarterly distribution of $2.20 per common unit and the generation by PAA of distributable cash flow of $1.5 billion or more on a trailing four quarter basis; (ii) 25% upon the payment by PAA of an annualized quarterly distribution of $2.30 per common unit and the generation by PAA of distributable cash flow of $1.75 billion or more on a trailing four quarter basis; (iii) 25% upon the payment by PAA of an annualized quarterly distribution of $2.40 per common unit and the generation by PAA of distributable cash flow of $1.9 billion or more on a trailing four quarter basis; and (iv) 25% upon the payment by PAA of an annualized quarterly distribution of $2.40 per common unit and the generation by PAA of distributable cash flow of $2.05 billion or more on a trailing four quarter basis. Distributable cash flow will be subject to adjustment under certain circumstances to account for significant asset sales.

(7)

Represents phantom units granted to Mr. Chiang in 2015 under PAA’s Long-Term Incentive Plan.  In August 2016, the terms of these phantom units were modified such that they will vest 40% on the later of the August 2018 distribution date and the date PAA pays an annualized quarterly distribution of $2.30 per common unit; 30% on the later of the August 2019 distribution date and the date PAA pays an annualized quarterly distribution of $2.40 per common unit; and 30% on the later of the August 2020 distribution date and the date PAA pays an annualized quarterly distribution of $2.50 per common unit. The phantom units also vest upon termination of employment under certain circumstances. See “—Employment Contracts” and “—Potential Payments Upon Termination or Change-in-Control.” Any phantom units that have not vested as of the August 2021 distribution date will be forfeited. Upon vesting, the phantom units are payable on a one-for-one basis in common units.  The phantom units have associated DERs that are currently vested and payable in cash on each distribution payment date.

(8)	Represents phantom units granted in 2016 under PAA’s Long-Term Incentive Plan. For a description of the vesting terms of these awards, see “Compensation Discussion and Analysis—Application in 2016—Long-Term Incentive Awards”.

(9)	Represents phantom units granted to Mr. Nerbonne in 2016 under PAA’s Long-Term Incentive Plan. These phantom units, which include DERs payable in cash, will vest 100% on December 14, 2018.

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(1)	Represents the gross number of phantom units that vested during the year ended December 31, 2016. The actual number of units delivered was net of income tax withholding.

(2)	Consistent with the terms of the applicable Long-Term Incentive Plan, the value realized upon vesting is computed by multiplying the closing market price ($29.00) of PAA’s common units on August 11, 2016 (the date preceding the vesting date) by the number of units that vested.

(3)	Consistent with the terms of the applicable Long-Term Incentive Plan, the value realized upon vesting is computed by multiplying the closing market price ($29.15) of PAA’s common units on August 12, 2016 (the vesting date) by the number of units that vested.

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(1)

The employment agreements between GP LLC and Messrs. Armstrong and Pefanis provide that if (i) their employment with GP LLC is terminated as a result of their death, (ii) they terminate their employment with GP LLC (a) because of a disability (as defined in Section 409A of the Code) or (b) for good reason (as defined below), or (iii)  GP LLC terminates their employment without cause (as defined below), they are entitled to a lump-sum amount equal to the product of (1) the sum of their (a) highest annual base salary paid prior to their date of termination and (b) highest annual bonus paid or payable for any of the three years prior to the date of termination, and (2) the lesser of (i) two or (ii) the number of days remaining in the term of their employment agreement divided by 360. The amount provided in the table assumes for each executive a termination date of December 30, 2016, and also assumes a highest annual base salary of $375,000 and highest

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(2)

Pursuant to their employment agreements, if Messrs. Armstrong and Pefanis terminate their employment with GP LLC within three (3) months of a change in control (as defined below), they are entitled to a lump-sum payment in an amount equal to the product of (i) three and (ii) the sum of (a) their highest annual base salary previously paid to them and (b) their highest annual bonus paid or payable for any of the three years prior to the date of such termination. The amount provided in the table assumes a change in control and termination date of December 30, 2016, and also assumes a highest annual base salary of $375,000 and highest annual bonus of $3,900,000 for Mr. Armstrong, and a highest annual base salary of $300,000 and highest annual bonus of $3,800,000 for Mr. Pefanis.

(3)

The letters evidencing the 2013 phantom unit grants awarded to the Named Executive Officers, and the 2015 phantom unit grant awarded to Mr. Chiang, provide that in the event of their death or disability (as defined below), all of their then outstanding phantom units and associated DERs will be deemed nonforfeitable, and (i) any unvested phantom units that had satisfied all of the vesting criteria as of the date of their termination but for the passage of time would vest on the next

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(4)

Pursuant to the 2013 phantom unit grants held by the Named Executive Officers, in the event their employment is terminated other than in connection with a change of control (as defined in footnote 5 below) or by reason of death or disability (as defined in footnote 3 above), all of the phantom units and associated DERs (regardless of vesting) then outstanding under such phantom unit grants would automatically be forfeited as of the date of termination; provided, however, that if GP LLC terminated their employment other than for cause (as defined in footnote 5 below), any unvested phantom units that had satisfied all of the vesting criteria as of the date of their termination but for the passage of time would be deemed nonforfeitable and would vest on the next following distribution date. Pursuant to the 2016 phantom unit grants held by the Named Executive Officers, in the event their employment is terminated other than in connection with a change of control (as defined in footnote 5 below) or by reason of death or disability (as defined in footnote 3 above), all of the phantom units and associated DERs (regardless of vesting) then outstanding under such phantom unit grants would automatically be forfeited as of the date of termination; provided, however, that if GP LLC terminated their employment other than for cause (as defined in footnote 5 below), any unvested phantom units that would, but for such termination and forfeiture, vest on a specified distribution date (either August 2019, August 2020, August 2021 or August 2022) during the twelve month period immediately following such termination, shall be deemed nonforfeitable on the date of such termination and shall vest on the next following distribution date. Mr. Chiang’s employment agreement also provides that his 2015 phantom unit grant will vest in full if he has not received the Executive Promotion and is terminated by GP LLC other than for cause or he terminates his employment for good reason prior to December 31, 2018 (see “—Employment Contracts” for additional information regarding Mr. Chiang’s employment agreement). The dollar value amount provided assumes that (i) the Named Executive Officers (other than Mr. Chiang) were terminated without cause on December 30, 2016, and (ii) Mr. Chiang had not received the Executive Promotion and was terminated without cause or terminated his employment for good reason on December 30, 2016.  As a result of the foregoing, in the event of the termination of the Named Executive Officers under the circumstances described above on December 31, 2016, (i) all of the phantom units covered by the 2013 phantom unit grants held by the Named Executive Officers and the 2015 phantom unit grant held by Mr. Chiang would have vested on or before February 14, 2017 (the February 2017 distribution date), and (ii) all remaining phantom units held by the Named Executive Officers would have become automatically forfeited as of such date of termination.  That portion of the dollar value given that is attributable to PAA phantom units is based on the market value of PAA’s common units on December 30, 2016 ($32.29 per unit).

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(5)

The letters evidencing phantom unit grants awarded to the Named Executive Officers provide that in the event of a change in status (as defined below), all of the then outstanding phantom units and associated DERs will be deemed nonforfeitable, and such phantom units will vest in full (i.e., the phantom units will become payable in the form of one PAA common unit per phantom unit) upon the next following distribution date.  Additionally, Mr. Chiang’s employment agreement provides that his phantom unit grants will vest in full if he terminates his employment within 90 days after a change of control (as defined below) prior to December 31, 2018 and in connection therewith he does not receive the Executive Promotion (see “—Employment Contracts” for additional information regarding Mr. Chiang’s employment agreement). Assuming (i) that a change in status occurred on December 30, 2016, (ii) that a change of control occurred 90 days prior to December 30, 2016, and (iii) that, in connection with the change of control, Mr. Chiang did not receive the Executive Promotion and terminated his employment on December 30, 2016, all outstanding phantom units and the associated DERs would have become nonforfeitable as of December 30, 2016, and such phantom units would vest on the February 2017 distribution date.  That portion of the dollar value given that is attributable to PAA phantom units is based on the market value of PAA’s common units on December 30, 2016 ($32.29 per unit), without discount for service period.

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(6)

Pursuant to their employment agreements with GP LLC, if Messrs. Armstrong or Pefanis are terminated other than (i) for cause (as defined in footnote 1 above), (ii) by reason of death or (iii) by resignation (unless such resignation is due to a disability or for good reason (each as defined in footnote 1 above)), then they are entitled to continue to participate, for a period which is the lesser of two years from the date of termination or the remaining term of the employment agreement, in such health and accident plans or arrangements as are made available by GP LLC to its executive officers generally. The amounts provided in the table assume a termination date of December 30, 2016.

(7)

Pursuant to their employment agreements, Messrs. Armstrong and Pefanis will be reimbursed for any excise tax due under Section 4999 of the Code as a result of compensation (parachute) payments made under their respective employment agreements. The values provided for this benefit assume that Messrs. Armstrong and Pefanis were terminated in connection with a change in control effective as of December 30, 2016.

(8)

Pursuant to the AAP Management Unit grant agreements of Messrs. Chiang, McGee and Nerbonne, AAP retained a call right to purchase any earned AAP Management Units at a discount to fair market value equal to 25%, 50%, or 75% of fair market value depending on the date of exercise of the call right (which value is referred to in the AAP Management Unit grant agreements as the “Call Value” as defined below) of such AAP Management Units, which call right is exercisable upon the termination of such Named Executive Officer’s employment with GP LLC and its affiliates prior to a stated date (January 1, 2020 for Mr. McGee’s 2011 grant, January 1, 2021 for Mr. McGee’s 2013 grant and January 1, 2023 for the grants to Messrs. Chiang and Nerbonne; such dates being referred to as the “Applicable Stated Date”); provided, however, that such call right is not applicable (i) in the case of the termination of such Named Executive Officer’s employment without cause (defined below), (ii) in the event of a resignation by such Named Executive Officer with good reason (defined below), and (iii) in Mr. Chiang’s case, in the event of his death or disability.  Additionally, Mr. Chiang’s employment agreement provides that his AAP Management Units will vest in full if he has not received the Executive Promotion and is terminated by GP LLC other than for cause (as defined below) or he terminates his employment for good reason prior to December 31, 2018 (see “—Employment Contracts” for additional information regarding Mr. Chiang’s employment agreement).  If Messrs. Chiang, McGee and Nerbonne are terminated without cause or terminate their employment for good reason, or if such Named Executive Officer remains employed past their Applicable Stated Date, any earned AAP Management Units are no longer subject to the call right and are deemed to have “vested.”  As of December 31, 2016, approximately 86% of the AAP Management Units held by Mr. McGee had been earned, but all of such AAP Management Units remained subject to AAP’s call right, and none of the AAP Management Units held by Mr. Chiang or Mr. Nerbonne had been earned.  Assuming a termination of employment without cause or for good reason on December 31, 2016 and assuming that Mr. Chiang had not received the Executive Promotion prior to that date, all of the AAP Management Units held by Mr. Chiang, 86% of the AAP Management Units held by Mr. McGee, and none of the AAP Management Units held by Mr. Nerbonne would become vested and would no longer be subject to the call right.  Because the call right provides for a discounted purchase price equal to 50% of fair market value in the case of Mr. McGee, in such event the applicable Named Executive Officer would “benefit” by virtue of the fact that such officer’s AAP Management Units could no longer be purchased by AAP at a discount.  The value reflected in the table above for Mr. McGee represents the implied value of such “benefit”, calculated as of December 31, 2016 by (i) assuming that Mr. McGee’s earned AAP Management Units are converted into AAP units based on the conversion factor of approximately 0.941 AAP units and PAGP Class B shares for each AAP Management Unit, (ii) assuming the exchange of the resulting AAP units and PAGP Class B shares for PAGP Class A shares on a one-for-one basis, and (iii) multiplying such resulting number of PAGP Class A shares by an amount equal to 50% of the closing market price ($34.68) of PAGP’s Class A shares at December 30, 2016 (the last trading day of the fiscal year).  The value reflected in the table above for Mr. Chiang represents the implied value of such “benefit”, calculated as of December 30, 2016 by (i) assuming that Mr. Chiang’s AAP Management Units are converted into AAP units based on the conversion factor of approximately 0.941 AAP units and PAGP Class B shares for each AAP Management Unit, (ii) assuming the exchange of the resulting AAP units and PAGP Class B shares for PAGP Class A shares on a one-for-one basis, and (iii) multiplying such resulting number of PAGP Class A shares by an amount equal to 100% of the closing market price ($34.68) of PAGP’s Class A shares at December 30, 2016 (the last trading day of the fiscal year).

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(9)

Pursuant to the AAP Management Unit grant agreements, upon the occurrence of a Change in Control, any earned AAP Management Units (and any AAP Management Units that will become earned in less than 180 days) become vested units and, to the extent any AAP Management Units remain unearned, an incremental 25% of the number of AAP Management Units originally granted pursuant to the applicable grant becomes vested.  Mr. Chiang’s employment agreement also provides that his AAP Management Units will vest in full if he terminates his employment within 90 days after a change of control prior to December 31, 2018 and in connection therewith he does not receive the Executive Promotion (see “—Employment Contracts” for additional information regarding Mr. Chiang’s employment agreement).  As of December 31, 2016, none of the AAP Management Units held by Mr. Chiang or Mr. Nerbonne had been earned, but all of Mr. McGee’s AAP Management Units had become earned with the exception of 25% of the units covered by his 2013 grant.  Accordingly, assuming that a Change in Control occurred on December 30, 2016 (or in the case of Mr. Chiang, 90 days prior to December 30, 2016) and that in connection with such Change in Control, Mr. Chiang had not received the Executive Promotion, all of the AAP Management Units held by Mr. Chiang and Mr. McGee, and 25% held by Mr. Nerbonne would become vested and would no longer be subject to the call right.  Because the call right provides for a discounted purchase price relative to fair market value as described above, the applicable Named Executive Officer would “benefit” from a Change in Control by virtue of the fact that such officer’s AAP Management Units could no longer be purchased by AAP at such discount.  The value reflected in the table above for Messrs. Chiang, McGee and Nerbonne represents the implied value of such “benefit”, calculated as of December 30, 2016 by (i) assuming that such executive’s vested AAP Management Units are converted into AAP units based on the conversion factor of approximately 0.941 AAP units and PAGP Class B shares for each AAP Management Unit, (ii) assuming the exchange of the resulting AAP units and PAGP Class B shares for PAGP Class A shares on a one-for-one basis, and (iii) multiplying such resulting number of PAGP Class A shares by an amount equal to the applicable percentage (100% for Mr. Chiang, 50% for Mr. McGee’s 2011 grant, 62.5% for Mr. McGee’s 2013 grant, and 25% for Mr. Nerbonne) (taking any applicable discount into account) of the closing market price ($34.68) of PAGP’s Class A shares at December 30, 2016 (the last trading day of the fiscal year).

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(10)	If Messrs. Swanson, Chiang, McGee or Nerbonne were terminated for cause, GP LLC would be obligated to pay base salary through the date of termination, with no other payment obligation triggered by the termination under any employment arrangement.

(11)

Mr. Chiang’s employment agreement provides that in the event of his death or disability prior to December 31, 2018, if less than 187,760 of his AAP Management Units have been earned, he shall vest in such number of additional AAP Management Units as may be necessary to cause the total number of vested AAP Management Units to equal 187,760.  Mr. Chiang’s AAP Management Unit grant agreement also provides that in the event of his death or disability, AAP will not have a call right and all of his earned AAP Management Units will vest.  As of December 30, 2016, none of Mr. Chiang’s AAP Management Units had been earned.  The dollar value given assumes Mr. Chiang’s death or disability on December 30, 2016 and represents the implied value of such “benefit,” calculated as of December 30, 2016 by (i) assuming that Mr. Chiang’s vested AAP Management Units are converted into AAP units based on the conversion factor of approximately 0.941 AAP units and PAGP Class B shares for each AAP Management Unit, (ii) assuming the exchange of the resulting AAP units and PAGP Class B shares for PAGP Class A shares on a one-for-one basis, and (iii) multiplying such resulting number of PAGP Class A shares by the closing market price ($34.68) of PAGP’s Class A shares at December 30, 2016 (the last trading day of the fiscal year).

(1)	For Messrs. Petersen, Symonds and Temple, fees paid in 2016 include fees for service on the conflicts committee established by the board of directors of GP LLC in connection with the Simplification Transactions.

(2)

The dollar value of LTIPs granted during 2016 is based on the grant date fair value computed in accordance with FASB ASC Topic 718. See Note 16 to our Consolidated Financial Statements for additional discussion regarding the calculation of grant date fair values. In connection with the August 2016 vesting of director LTIP awards issued prior to the consummation of the Simplification Transactions, Messrs. Goyanes, Symonds and Temple each were granted 5,000 PAA phantom units, and Messrs. Petersen, Raymond and Sinnott each were granted 2,500 PAA phantom units by virtue of the automatic re-grant feature of the vested awards. Upon vesting of such PAA director LTIP awards in August 2016 (other

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(3)	Mr. Figlock’s compensation is assigned to Oxy.

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•	each person who is known to us to beneficially own more than 5% of the Class A shares;

•	each person who is known to us to beneficially own more than 5% of the Class B shares;

•	the Named Executive Officers of our general partner;

•	each of the directors of our general partner; and

•	all of the directors and executive officers of our general partner as a group.

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(1)

Class A shares beneficially owned do not include any Class A shares issuable in connection with the exchange of any Class B shares, whether such Class B shares are currently outstanding or issuable following the conversion of any AAP Management Units.  Although holders of our Class B shares have the right, at any time and from time to time, to immediately exchange (the “Exchange Right”) their Class B shares, together with a like number of AAP units and general partner units, for our Class A shares on a one-for-one basis, the fact that such Exchange Right may be settled in cash at AAP’s option results in such Class A shares not being deemed to be beneficially owned by the holders of our Class B shares.

(2)

As long as our Class A shares are publicly traded, a holder of vested AAP Management Units will be entitled to convert such AAP Management Units into Class B shares and a like number of AAP units based on a conversion ratio of approximately 0.941 AAP units (and Class B shares) for each AAP Management Unit. Accordingly, figures presented for Class B shares beneficially owned and percentage of Class B shares beneficially owned are presented on a fully diluted basis and include Class B shares to be issued upon the conversion of all outstanding AAP Management Units based on such 0.941 conversion ratio.

(3)	This information has been derived from a Schedule 13G filed with the SEC on January 27, 2017.

(4)

Richard A. Kayne is Chief Executive Officer and Director of Kayne Anderson Investment Management, Inc., which is the general partner of Kayne Anderson Capital Advisors, L.P. (“KACALP”). Various accounts under the management or control of KACALP own 6,364,041 Class A shares. Mr. Kayne may be deemed to beneficially own such shares. In addition, Mr. Kayne directly owns or has sole voting and dispositive power over 549,917 Class A shares. Mr. Kayne disclaims beneficial ownership of any of our Class A shares other than Class A shares held by him or attributable to him by virtue of his interests in the accounts that own our Class A shares.

(5)	Represents the number of Class B shares beneficially owned by Mr. Chiang through his beneficial ownership of 353,489 AAP units and Class B shares, based on a conversion ratio of 0.941 AAP units and Class B shares for each AAP Management Unit.

(6)	Represents the number of Class B shares beneficially owned by Mr. McGee through his (i) direct ownership of 14,739 AAP units and Class B shares and (ii) beneficial ownership of 414,607 AAP units and Class B shares, based on a conversion ratio of 0.941 AAP units and Class B shares for each AAP Management Unit.

(7)	Represents the number of Class B shares beneficially owned by Mr. Nerbonne through his (i) direct ownership of 4,913 AAP units and Class B shares and (ii) beneficial ownership of 53,023 AAP units and Class B shares, based on a conversion ratio of 0.941 AAP units and Class B shares for each AAP Management Unit.

(8)

Mr. Raymond is (i) the sole member of the general partner of the manager of EMG Investment, LLC, which entity owns 45,632,121 Class B shares, and (ii) the sole member of Lynx Holdings I, LLC, which entity owns 3,183,216 Class B shares. As such, Mr. Raymond has sole voting and dispositive power over the Class B shares owned by each of EMG Investment, LLC and Lynx Holdings I, LLC. Mr. Raymond disclaims any deemed beneficial ownership of the interests owned by EMG Investment, LLC beyond his pecuniary interest therein.

(9)

Mr. Sinnott has shared voting and dispositive power over the Class B shares owned by (i) KAFU Holdings, L.P. (“KAFU”), which entity owns 933,224 Class B shares, (ii) KAFU Holdings (QP), L.P. (“KAFU QP”), which entity owns 21,172,741 Class B shares, and (iii) KAFU Holdings II, L.P. (“KAFU II”), which entity owns 2,551,869 Class B shares.  Mr. Sinnott disclaims any deemed beneficial ownership of the interests owned by KAFU, KAFU QP and KAFU II beyond his pecuniary interest therein.

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(10)	The executive officers of our general partner as a group directly own 11,113,323 AAP units and Class B shares and beneficially own 959,323 AAP units and Class B shares based on a conversion ratio of 0.941 AAP units and Class B shares for each AAP Management Unit.

(11)	As of February 15, 2017, no Class A shares or Class B shares were pledged by directors or Named Executive Officers.

(1)	AAP owns approximately 243.4 million PAA common units and a 100% member interest in PAA GP LLC, which owns PAA’s non-economic general partner interest.

(2)

Prior to December 31, 2016, PAA Management, L.P. owned an approximate 3.3% interest in AAP represented by approximately 8.2 million AAP units. Effective as of December 31, 2016, PAA Management, L.P. was liquidated and the AAP units owned by it (together with the associated Class B shares and GP Units) were distributed pro rata to its owners, including certain current and former members of senior management. AAP units received by our Named Executive Officers in connection with this pro rata distribution included 2,071,859 for Mr. Armstrong; 1,181,676 for Mr. Pefanis; 433,620 for Mr. Swanson; 14,739 for Mr. McGee and 4,913 for Mr. Nerbonne; all executive officers as a group received an aggregate of 4,840,602 AAP units. Mr. Chiang did not have an ownership interest in PAA Management, L.P.

(3)	Includes, among others, certain current and former members of management who (i) have converted AAP Management Units into AAP units and PAGP Class B shares and (ii) received AAP units and PAGP Class B shares as a result of the pro rata distribution by PAA Management, L.P. described in footnote 2 above.

(4)

Represents a profits interest in AAP in the form of AAP Management Units owned by certain members of management.  On January 1, 2016, a significant number of AAP Management Units vested and a portion of such vested units have since been converted into AAP units and our Class B shares.  Additionally, a portion of the resulting AAP units and Class B shares has been exchanged for our Class A shares.  As a result of such conversions and exchanges as well as open market purchases, as of February 15, 2017, Named Executive Officers and executive officers as a group owned the following AAP Management Units, AAP units and Class A shares (none of our outside directors own any AAP Management Units):

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(1)

The Plains GP Holdings, L.P. Long Term Incentive Plan (the “LTIP”) was adopted by our general partner in connection with our IPO in October 2013.  The LTIP contemplates the issuance or delivery of up to 3,755,208 Class A shares to satisfy awards under the LTIP. In accordance with Item 201(d) of Regulation S-K, column (c) excludes the securities disclosed in column (a). However, any phantom Class A shares represented in column (a) that are not satisfied by the issuance of Class A shares become “available for future issuance.”

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•	the permanent elimination of PAA’s IDRs and the economic rights associated with PAA’s 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);

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•	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 PAGP GP assumed oversight responsibility over both PAA and PAGP;

•

the provision for annual PAGP shareholder elections beginning in 2018 with certain directors with expiring terms in 2018, and the participation of PAA common unitholders and Series A preferred unitholders in such elections through PAA’s ownership of newly issued Class C shares in PAGP, which provide PAA, as the sole holder, the right to vote in elections of eligible PAGP directors together with the holders of PAGP 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 Management Units into AAP units) equaled the number of PAA common units received by AAP at the closing of the Simplification Transactions. Simultaneously, PAGP executed a reverse split to adjust the number of PAGP Class A and Class B shares outstanding to equal the number of AAP units it owns following AAP’s reverse unit split. These reverse splits, along with the Omnibus Agreement described below, resulted in economic alignment between PAA’s common unitholders and PAGP’s Class A shareholders, such that the number of outstanding PAGP Class A shares equals the number of AAP units owned by PAGP, which in turn equals the number of PAA common units held by AAP. PAA also entered into an Omnibus Agreement with the PAGP Entities, 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, subject to certain limitations, 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.

•

that all direct or indirect expenses of any of the Plains Entities will be paid by PAA, other than income taxes, if any, of PAGP GP, PAGP, GP LLC, AAP and PAA GP LLC. Such direct or indirect expenses include, but are not limited to (i) compensation for the directors of PAGP GP, (ii) director and officer liability insurance, (iii) listing exchange fees, (iv) investor relations expenses, and (v) fees related to legal, tax, financial advisory and accounting services;

•	the mechanics by which the number of PAGP Class C shares outstanding will equal, at all times, the number of PAA’s units that are outstanding and entitled to vote, other than such voting units held by AAP;

•	the mechanics by which (i) the total number of PAGP’s outstanding Class A shares will equal the number of AAP Units held by PAGP, and (ii) the total number of PAA common units held by AAP will equal the sum of the number of outstanding AAP units and the number of AAP units that are issuable to the holders of vested and earned AAP Management Units;

•	the ability of PAGP to issue additional Class A shares and related obligation of PAGP to use the net proceeds therefrom to purchase a like number of AAP units from AAP, and the corresponding obligation of AAP to use the net proceeds therefrom to purchase a like number of PAA common units from PAA; and

•

the ability of PAGP to lend proceeds of any future indebtedness incurred by it to AAP, and AAP’s corresponding obligation to lend such proceeds to PAA, in each case on substantially the same terms as incurred by PAGP (also clarifying that PAA will reimburse the net fees and expenses in connection with the incurrence of such debt; provided that PAA will only be required to reimburse such net fees and expenses on one occasion with respect to each incurrence of indebtedness by PAA from AAP).

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(1)	Audit fees include those related to (a) our annual audit (including internal control evaluation and reporting); (b) the audit of certain joint ventures of which we are the operator, and (c) work performed on our registration of publicly held debt and equity.

(2)	Audit-related fees for the year ended December 31, 2016 are primarily comprised of fees associated with the audits of financial statements prepared in conjunction with divestiture transactions.  Such fees were reimbursed to us by the purchasers.  Audit-related fees also include fees for the audits of our benefit plan in both periods presented.

(3)	Tax fees are related to tax processing as well as the preparation of Forms K-1 for PAA unitholders and international tax planning work associated with the structure of our Canadian investment.

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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;

•

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

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•

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 a reverse split to adjust the number of Class A and Class B shares outstanding to equal the number of AAP units we own 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. 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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(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 pipeline 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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(1)	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 5 for a discussion of property and equipment.

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(1)	Emission reduction credits, once surrendered in exchange for environmental permits, are finite-lived.

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(1)	We classified these PAA commercial paper notes and credit facility borrowings as short-term at December 31, 2016 and 2015, 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)	At December 31, 2016, includes borrowings of $410 million for cash margin deposits with NYMEX and ICE, which are associated with financial derivatives used for hedging purposes.

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(3)	As of December 31, 2016 and 2015, we classified a portion of our commercial paper notes as long-term and as of December 31, 2015, we classified PAA’s $175 million, 5.88% senior notes due August 2016 as long-term based on PAA’s ability and intent to refinance such amounts on a long-term basis under its credit facilities.

(4)	On November 15, 2016, as part of the Simplification Transactions, PAA assumed and immediately repaid all of AAP’s outstanding debt.

(5)

PAA’s fixed-rate senior notes (including current maturities) had a face value of approximately $10.3 billion and $9.8 billion as of December 31, 2016 and 2015, respectively. We estimated the aggregate fair value of these notes as of December 31, 2016 and 2015 to be approximately $10.4 billion and $8.6 billion, respectively. PAA’s fixed-rate senior notes are traded among institutions, and these trades are routinely published by a reporting service. Our determination of fair value is based on reported trading activity near year end. We estimate that the carrying value of outstanding borrowings under the credit facilities and the PAA commercial paper program approximates fair value as interest rates reflect current market rates. The fair value estimates for the PAA senior notes, the credit facilities and the PAA commercial paper program are based upon observable market data and are classified in Level 2 of the fair value hierarchy.

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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)	Includes 25,910,938 Class A shares issued to Oxy immediately preceding the sale of such shares in an underwritten secondary public offering.

(1)	The distribution paid to our Class A shareholders in the first quarter of 2014 was based on the prorated distribution received from AAP attributable to the period beginning on the date of the closing of our IPO through the end of the fourth quarter of 2013.

(1)	During the years ended December 31, 2016, 2015 and 2014, AAP’s incentive distributions were reduced by approximately $18 million, $22 million and $23 million, respectively, which were agreed to in connection with certain acquisitions.

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(1)

The distribution paid by AAP in the first quarter of 2014 was prorated as of the date of the consummation of our IPO, such that the owners of AAP prior to our IPO received the portion of the distribution attributable to the period prior to our IPO, and the owners of AAP at the date of record of January 31, 2014, including us, received the portion of the distribution attributable to the period beginning on the date of the IPO through the end of the fourth quarter of 2013.

(2)

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.

(3)	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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(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 $8 million, $1 million and $9 million of such commissions during 2016, 2015 and 2014, respectively.

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•	A net long position of 3.6 million barrels associated with our crude oil purchases, which was unwound ratably during January 2017 to match monthly average pricing.

•	A net short time spread position of 5.2 million barrels, which hedges a portion of our anticipated crude oil lease gathering purchases through January 2018.

•	A crude oil grade basis position of 43.8 million barrels through December 2019. These derivatives allow us to lock in grade basis differentials.

•	A net short position of 12.2 Bcf through May 2017 related to anticipated sales of natural gas inventory.

•	A net short position of 34.5 million barrels through December 2019 related to anticipated net sales of our crude oil and NGL inventory.

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(1)

During the year ended December 31, 2016, we reclassified losses of approximately $2 million and $2 million from AOCI to Supply and Logistics segment revenues and Interest expense, net, respectively, due to anticipated hedged transactions being probable of not occurring. During the year ended December 31, 2015, we reclassified a loss of approximately $4 million from AOCI to Interest expense, net due to an anticipated hedged transaction being probable of not occurring. During the year ended December 31, 2014, all of our hedged transactions were probable of occurring.

(2)	Amounts in Interest expense, net include a loss of $4 million during the year ended December 31, 2016 attributable to the ineffective portion of cash flow hedges. No ineffectiveness was recognized for cash flow hedges during the years ended December 31, 2015 and 2014.

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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.

(1)	Purchases and related costs include crude oil buy/sell transactions that are accounted for as inventory exchanges and are presented net in our Consolidated Statements of Operations.

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(1)	Approximately 4.3 million of the 8.9 million outstanding PAA LTIP awards also include DERs, of which 1.6 million had vested as of December 31, 2016.

(2)	LTIP units outstanding do not include AAP Management Units or PAGP LTIP awards.

(3)

Certain LTIP awards vest upon the later of a certain date or the attainment of performance conditions requiring the attainment of certain annualized PAA distribution levels or upon the attainment of such levels alone. For purposes of this disclosure, vesting dates are based on an estimate of future distribution levels and assume that all grantees remain employed by us through the vesting date. As of December 31, 2016, a distribution of $2.20 per PAA common unit was deemed probable of occurring in the reasonably foreseeable future (and was initially determined to be probable in the third quarter of 2016).

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(1)	Amounts do not include AAP Management Units or PAGP LTIP awards.

(2)

Approximately 0.5 million, 0.5 million and 0.6 million PAA common units were issued, net of tax withholding of approximately 0.3 million, 0.3 million and 0.3 million units during 2016, 2015 and 2014, respectively, in connection with the settlement of vested awards. The remaining PAA awards (approximately 1.1 million, 1.3 million and 1.0 million units) that vested during 2016, 2015 and 2014, respectively, were settled in cash.

(3)	During the third quarter of 2016 modifications were made to the vesting criteria of 2.2 million PAA LTIP units. In accordance with FASB guidance on share-based payments, the grant date fair values of these awards were adjusted as of the modification date.

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(1)	Of the $35 million grant date fair value, $22 million had been recognized through December 31, 2016 on a cumulative basis. Of this amount, $2 million, $1 million and $7 million was recognized as expense during the years ended December 31, 2016, 2015 and 2014, respectively.

(2)	During the third quarter of 2016 modifications were made to the distribution performance thresholds of the 0.8 million unearned AAP Management Units. In accordance with FASB guidance on share-based payments, the grant date fair values of these awards were adjusted as of the modification date.

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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, 2016.

(2)	Includes unamortized fair value associated with AAP Management Units and PAGP LTIP awards.

(1)	Includes capital and operating leases as defined by FASB guidance as well as obligations for rights-of-way easements. Lease expense for 2016, 2015 and 2014 was $198 million, $164 million and $145 million, respectively.

(2)

Primarily includes third-party storage and transportation agreements and pipeline throughput agreements, as well as approximately $855 million associated with an agreement to transport crude oil 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)	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 and (iii) Depreciation and amortization.

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

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(1)

Transportation revenues from external customers include inventory exchanges that are substantially similar to tariff-like arrangements with our customers. Under these arrangements, our Supply and Logistics segment has transacted the inventory exchange and serves as the shipper on our pipeline systems. See Note 2 for discussion of our related accounting policy. We have included an estimate of the revenues from these inventory exchanges in our Transportation segment revenue presented above and adjusted those revenues out such that Total revenue from External customers reconciles to our Consolidated Statement 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 sales are conducted at posted tariff rates, 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 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.

(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

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(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.

(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.

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†	Filed herewith.

††	Furnished herewith.

*	Certain confidential portions of this exhibit have been omitted pursuant to an Application for Confidential Treatment under Rule 24b-2 under the Exchange Act. This exhibit, with the omitted language, has been filed separately with the Securities and Exchange Commission.

**	Certain schedules have been omitted pursuant to Item 601(b)(2) of Regulation S-K. A copy of any omitted schedule will be furnished supplementally to the SEC upon request.

***	Management compensatory plan or arrangement.