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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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o
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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Delaware
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76-0582150
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(State or other jurisdiction of
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(I.R.S. Employer
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incorporation or organization)
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Identification No.)
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333 Clay Street, Suite 1600, Houston, Texas
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77002
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(Address of principal executive offices)
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(Zip Code)
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Title of Each Class
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Name of Each Exchange on Which Registered
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Common Units
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New York Stock Exchange
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Large Accelerated Filer
x
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Accelerated Filer
o
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Non-Accelerated Filer
o
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Smaller Reporting Company
o
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(Do not check if a smaller reporting company)
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Page
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•
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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;
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the effects of competition;
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market distortions caused by producer over-commitments to new or recently constructed infrastructure projects, which impacts volumes, margins, returns and overall earnings;
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unanticipated changes in crude oil market structure, grade differentials and volatility (or lack thereof);
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environmental liabilities or events that are not covered by an indemnity, insurance or existing reserves;
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maintenance of our credit rating and ability to receive open credit from our suppliers and trade counterparties;
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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;
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the occurrence of a natural disaster, catastrophe, terrorist attack (including eco-terrorist attacks) or other event, including attacks on our electronic and computer systems;
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failure to implement or capitalize, or delays in implementing or capitalizing, on expansion projects, whether due to permitting delays, permitting withdrawals or other factors;
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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;
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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 our historical operations;
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the currency exchange rate of the Canadian dollar;
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continued creditworthiness of, and performance by, our counterparties, including financial institutions and trading companies with which we do business;
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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;
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non-utilization of our assets and facilities;
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increased costs, or lack of availability, of insurance;
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weather interference with business operations or project construction, including the impact of extreme weather events or conditions;
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the availability of, and our ability to consummate, acquisition or combination opportunities;
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the effectiveness of our risk management activities;
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shortages or cost increases of supplies, materials or labor;
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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 our units at the time of vesting under our long-term incentive plans;
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risks related to the development and operation of our assets, including our ability to satisfy our contractual obligations to our customers;
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factors affecting demand for natural gas and natural gas storage services and rates;
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general economic, market or business conditions and the amplification of other risks caused by volatile financial markets, capital constraints and pervasive liquidity concerns; and
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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)
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PAGP will hold an annual meeting for the election of eligible PAGP GP directors beginning in 2018. Through our ownership of Class C shares of PAGP, our common unitholders have the right to vote, pro rata with the holders of Class A and Class B shares of PAGP, for the election of eligible PAGP GP directors. 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)
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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 Executive Officers of our General Partner and Corporate Governance” for further information regarding governance of the Plains Entities.
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(2)
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Represents the number of Class A units of AAP (“AAP units”) for which the outstanding Class B units of AAP (referred to herein as the “AAP Management Units”) will be exchangeable, assuming the conversion of all such units at a rate of approximately 0.941 AAP units for each AAP Management Unit.
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(3)
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Assumes conversion of all outstanding AAP Management Units into AAP units.
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(4)
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Each Class C share represents a non-economic limited partner interest in PAGP and carries with it the right to vote, pro rata with the holders of Class A and Class B shares of PAGP, for the election of eligible PAGP GP directors.
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(5)
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Amount does not include 792,074 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.
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(6)
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The Partnership holds direct and indirect ownership interests in consolidated operating subsidiaries including, but not limited to, Plains Marketing, L.P., Plains Pipeline, L.P. and Plains Midstream Canada ULC (“PMC”).
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(7)
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The Partnership 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”).
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optimizing our existing assets and realizing cost efficiencies through operational improvements;
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using our transportation, terminalling, storage, processing and fractionation assets in conjunction with our 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
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selectively pursuing strategic and accretive acquisitions that complement our existing asset base and distribution capabilities.
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Many of our assets are strategically located and operationally flexible.
The majority of our 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 our Facilities segment assets. The majority of our Facilities segment assets are located at major trading locations and premium markets that serve as gateways to major North American refinery and distribution markets where we have strong business relationships. In addition, our assets include pipeline, rail, barge, truck and storage assets, which provide our customers and us
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We possess specialized crude oil and NGL market knowledge.
We believe our business relationships with participants in various phases of the crude oil and NGL distribution chain, from producers to refiners, as well as our own industry expertise (including our knowledge of North American crude oil and NGL flows), provide us with an extensive understanding of the North American physical crude oil and NGL markets.
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Our 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 our Supply and Logistics segment in combination with our risk management strategies provides us 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, we may be able to realize incremental margins that meaningfully exceed such base levels.
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We have the evaluation, integration and engineering skill sets and the financial flexibility to continue to pursue acquisition and expansion opportunities.
Since 1998, we have completed and integrated over 90 acquisitions with an aggregate purchase price of approximately $13.2 billion, including our February 2017 acquisition of the Alpha Crude Connector gathering system. Since 1998, we have also implemented expansion capital projects totaling approximately $11.4 billion. In addition, considering our investment grade credit rating, liquidity and capital structure, we believe we have the financial resources and strength necessary to finance future strategic expansion and acquisition opportunities. As of
December 31, 2016
, we had approximately
$2.4 billion
of liquidity available, including cash and cash equivalents and availability under our committed credit facilities, subject to continued covenant compliance.
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•
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We have an experienced management team whose interests are aligned with those of our unitholders.
Our executive management team has an average of 31 years of industry experience, and an average of 19 years with us or our predecessors and affiliates. In addition, through their ownership of common units, grants of phantom units and interests in our general partner, including interests in PAGP, AAP units and AAP Management Units, our management team has a vested interest in our 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.);
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an average total debt-to-total capitalization ratio of approximately 60% or less; and
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an average adjusted EBITDA-to-interest coverage multiple of approximately 3.3x or better.
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Acquisition
(1)
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Date
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Description
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Approximate Purchase Price
(2)
(in millions) |
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Alpha Crude Connector Gathering System
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Feb-2017
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Recently constructed gathering system located in the Northern Delaware Basin
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$
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1,215
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(3)
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Spectra Energy Partners Western Canada NGL Assets
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Aug-2016
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Integrated system of NGL assets located in Western Canada
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$
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204
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(4)
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50% Interest in BridgeTex Pipeline Company, LLC (“BridgeTex”)
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Nov-2014
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BridgeTex owns a crude oil pipeline that extends from Colorado City, Texas to East Houston
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$
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1,088
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(5)
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US Development Group Crude Oil Rail Terminals
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Dec-2012
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Four operating crude oil rail terminals and one terminal under development
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$
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503
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BP Canada Energy Company
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Apr-2012
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NGL assets located in Canada and the upper-Midwest United States
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$
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1,683
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(6)
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(1)
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Excludes our 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, we issued approximately 14.7 million PAA common units with a value of approximately $760 million.
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(2)
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As applicable, the approximate purchase price includes total cash paid and debt assumed, including amounts for working capital and inventory.
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(3)
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Purchase price subject to working capital and other adjustments. See Note 6 to our Consolidated Financial Statements for additional information regarding this acquisition.
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(4)
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Approximate purchase price of $180 million, net of cash, inventory and other working capital acquired.
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(5)
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Approximate purchase price of $1.075 billion, net of working capital acquired. We account for our 50% interest in BridgeTex under the equity method of accounting.
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(6)
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Purchase price includes approximately $17 million of imputed interest. A prepayment of $50 million was made during 2011. Approximate purchase price of $1.192 billion, net of working capital, linefill and long-term inventory acquired.
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Basin/Region
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Project
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2017 Plan
Amount (1) ($ in millions) |
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Description
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Projected
In-Service Date |
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Permian
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Permian Basin Area Gathering System Projects
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$
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120
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Multiple projects to increase and expand our pipeline infrastructure in the Delaware Basin, including planned interconnects associated with the recently acquired Alpha Crude Connector gathering system
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Q1 2017 - 2018
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Central / Mid-Continent
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Diamond Pipeline
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300
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50% interest in approximately 440 miles of new crude oil pipeline; 200,000 Bbls/d capacity from Cushing, OK to Valero’s refinery in Memphis, TN
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Q4 2017
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Cushing Terminal Expansions
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30
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Addition of approximately 2.1 million barrels of storage capacity and additional
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Q2 2017 - Q4 2017
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Canada
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Fort Saskatchewan Facility Projects
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90
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Multi-phase project, remaining Phase I project includes conversion of service of approximately 3 million barrels of existing caverns
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Q1 2017 - 2018
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Remaining Phase II projects include (i) adding a merox sweetening unit that will increase our ability to handle a variety of feed streams providing more flexibility and flow assurance, (ii) development of two new ethane caverns with 1.6 million barrels of capacity and a utility cavern and (iii) the addition of 2.7 million barrels of brine capacity
Phase III includes a six-spot rail rack expansion for condensate service and adding butane service to four existing propane spots
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Other
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Other Projects
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260
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Q1 2017 - 2018+
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Total Projected Expansion Capital Expenditures
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$
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800
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(1)
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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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Annual Liquids Production
(1)
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∆ from
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∆ from
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∆ from
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2004
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2013
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2014
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2015
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2016
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2004-2013
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2013-2015
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2015-2016
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(in millions of barrels per day)
(2)
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Production (Supply)
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OPEC
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35.0
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37.6
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37.5
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38.7
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39.6
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2.6
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1.1
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0.9
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Non-OPEC
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48.4
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53.4
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55.9
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57.5
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56.8
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5.0
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4.1
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(0.6
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)
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Total
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83.4
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91.0
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93.4
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96.1
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96.4
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7.6
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5.2
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0.3
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||||||||
Total Consumption (Demand)
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83.0
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91.4
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92.6
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94.1
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95.6
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8.4
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2.7
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1.4
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||||||||
Global Supply / Demand Balance
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0.4
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(0.5
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)
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0.8
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2.0
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0.9
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(0.9
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)
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2.5
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(1.1
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)
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(1)
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Amounts are derived from the EIA’s Short-Term Energy Outlook.
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(2)
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Amounts may not recalculate due to rounding.
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Actual
(1)
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Projected
(1)
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|||||
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2016
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2017
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2018
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(in millions of barrels per day)
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Supply
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Domestic Crude Oil Production
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8.9
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9.0
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9.3
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Net Imports - Crude Oil
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7.3
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6.9
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6.7
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Other - (Supply Adjustment/Stock Change)
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—
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0.3
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0.3
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Crude Oil Input to Domestic Refineries
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16.2
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16.2
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16.3
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Net Product Imports / (Exports)
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(2.6
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)
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(2.5
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)
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(2.6
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)
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Supply from Renewable Sources
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1.1
|
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1.1
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1.2
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Other - (NGL Production, Refinery Processing Gain)
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4.8
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5.0
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5.4
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Total Domestic Petroleum Consumption
|
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19.6
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|
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19.8
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20.2
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(1)
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Amounts may not recalculate due to rounding.
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•
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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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•
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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.
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•
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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.
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•
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Iso-butane.
Iso-butane is principally used by refiners to produce alkylates to enhance the octane content of motor gasoline.
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•
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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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•
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the absolute prices of NGL products and their prices relative to natural gas and crude oil;
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•
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drilling activity and wet natural gas production in developing liquids-rich production areas;
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•
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available processing, fractionation, storage and transportation capacity;
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•
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petro-chemical demand driven by the build-out or new builds of Ethylene Cracker capacity (ethane demand) and Propane Dehydrogenation facilities (propane demand);
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•
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increased export capacity for both ethane and propane;
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•
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diluent requirements for heavy Canadian oil;
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•
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regulatory changes in gasoline specifications affecting demand for butane;
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•
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seasonal demand from refiners;
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•
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seasonal weather related demand; and
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•
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inefficiencies caused by regional supply and demand imbalances.
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•
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19,200 miles of active crude oil and NGL pipelines and gathering systems;
|
•
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31 million barrels of active, above-ground tank capacity used primarily to facilitate pipeline throughput;
|
•
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810 trailers (primarily in Canada); and
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•
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120 transport and storage barges and 60 transport tugs through our interest in Settoon Towing.
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Region / Pipeline and Gathering Systems
(1)
|
|
System Miles
|
|
2016 Average Net
Barrels per Day (2) |
||
|
|
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|
(in thousands)
|
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United States Crude Oil Pipelines
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|
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||
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Permian Basin
|
|
|
|
|
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Basin / Mesa / Sunrise
|
|
770
|
|
|
992
|
|
BridgeTex
(3) (4)
|
|
408
|
|
|
108
|
|
Cactus
|
|
297
|
|
|
125
|
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Permian Basin Area Systems
|
|
2,796
|
|
|
921
|
|
Permian Basin Subtotal
|
|
4,271
|
|
|
2,146
|
|
|
|
|
|
|
||
South Texas/Eagle Ford
|
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|
|
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Eagle Ford Area Systems
(4)
|
|
660
|
|
|
284
|
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South Texas/Eagle Ford Subtotal
|
|
660
|
|
|
284
|
|
|
|
|
|
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||
Western
|
|
|
|
|
||
All American
(5)
|
|
138
|
|
|
—
|
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Line 63 / Line 2000
|
|
382
|
|
|
104
|
|
Other
|
|
121
|
|
|
84
|
|
Western Subtotal
|
|
641
|
|
|
188
|
|
|
|
|
|
|
||
Rocky Mountain
|
|
|
|
|
||
Bakken Area Systems
(4)
|
|
991
|
|
|
146
|
|
Cheyenne
(4)
|
|
87
|
|
|
10
|
|
Saddlehorn
(3) (4)
|
|
538
|
|
|
6
|
|
Salt Lake City Area Systems
(4)
|
|
977
|
|
|
178
|
|
White Cliffs
(3) (4)
|
|
1,054
|
|
|
42
|
|
Other
|
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1,225
|
|
|
67
|
|
Rocky Mountain Subtotal
|
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4,872
|
|
|
449
|
|
|
|
|
|
|
Region / Pipeline and Gathering Systems
(1)
|
|
System Miles
|
|
2016 Average Net
Barrels per Day (2) |
||
|
|
|
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(in thousands)
|
||
Gulf Coast
|
|
|
|
|
||
Capline
(3)
|
|
631
|
|
|
194
|
|
Pascagoula
|
|
41
|
|
|
143
|
|
Other
|
|
506
|
|
|
160
|
|
Gulf Coast Subtotal
|
|
1,178
|
|
|
497
|
|
|
|
|
|
|
||
Central
|
|
|
|
|
||
Mid-Continent Area Systems
(4)
|
|
2,696
|
|
|
325
|
|
Other
|
|
217
|
|
|
69
|
|
Central Subtotal
|
|
2,913
|
|
|
394
|
|
|
|
|
|
|
||
United States Crude Oil Pipelines Total
|
|
14,535
|
|
|
3,958
|
|
|
|
|
|
|
||
Canada Crude Oil Pipelines
|
|
|
|
|
||
Manito
|
|
445
|
|
|
42
|
|
Rainbow
|
|
830
|
|
|
91
|
|
Rangeland
|
|
1,076
|
|
|
52
|
|
South Saskatchewan
|
|
342
|
|
|
60
|
|
Other
|
|
201
|
|
|
136
|
|
Canada Crude Oil Pipelines Total
|
|
2,894
|
|
|
381
|
|
|
|
|
|
|
||
Crude Oil Pipelines Total
|
|
17,429
|
|
|
4,339
|
|
|
|
|
|
|
||
Canada NGL Pipelines
|
|
|
|
|
||
Co-Ed
|
|
595
|
|
|
61
|
|
PPTC
|
|
593
|
|
|
5
|
|
Other
|
|
548
|
|
|
118
|
|
Canada NGL Pipelines Total
|
|
1,736
|
|
|
184
|
|
|
|
|
|
|
||
Grand Total
|
|
19,165
|
|
|
4,523
|
|
|
(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.
|
•
|
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;
|
•
|
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.
|
Crude Oil and Refined Products Storage Facilities
|
|
Total Capacity
(MMBbls) |
|
Cushing
|
|
23
|
|
LA Basin
|
|
8
|
|
Martinez and Richmond
|
|
5
|
|
Mobile and Ten Mile
|
|
5
|
|
Patoka
|
|
6
|
|
St. James
|
|
13
|
|
Yorktown
(1)
|
|
5
|
|
Other
(2)
|
|
15
|
|
|
|
80
|
|
NGL Storage Facilities
|
|
Total Capacity
(MMBbls) |
|
Bumstead
|
|
3
|
|
Empress Area
|
|
5
|
|
Fort Saskatchewan
|
|
8
|
|
Sarnia Area
|
|
10
|
|
Other
|
|
6
|
|
|
|
32
|
|
Natural Gas Storage Facilities
|
|
Total Capacity
(Bcf) |
|
Salt-caverns and Depleted Reservoir
|
|
97
|
|
Natural Gas Processing Facilities
(3)
|
|
Ownership Interest
|
|
Total Gas
Inlet Volume (Bcf/d) |
|
Net Gas
Processing Capacity (Bcf/d) |
||
United States Gulf Coast Area
|
|
100%
|
|
0.1
|
|
|
0.3
|
|
Canada
|
|
50-100%
|
|
1.9
|
|
|
7.1
|
|
|
|
|
|
2.0
|
|
|
7.4
|
|
Condensate Stabilization Facility
|
|
Total Capacity
(Bbls/d) |
|
Gardendale
|
|
120,000
|
|
NGL Fractionation and Isomerization Facilities
|
|
Ownership Interest
|
|
Total
Spec Product (4) (Bbls/d) |
|
Net
Capacity (Bbls/d) |
||
Empress
|
|
100%
|
|
6,300
|
|
|
28,300
|
|
Fort Saskatchewan
|
|
21-100%
|
|
28,300
|
|
|
67,800
|
|
Sarnia
|
|
62-84%
|
|
62,300
|
|
|
90,000
|
|
Shafter
|
|
100%
|
|
9,300
|
|
|
15,000
|
|
Other
|
|
82-100%
|
|
9,100
|
|
|
25,000
|
|
|
|
|
|
115,300
|
|
|
226,100
|
|
Rail Facilities
|
|
Ownership Interest
|
|
Loading
Capacity (Bbls/d) |
|
Unloading
Capacity (Bbls/d) |
||
Crude Oil Rail Facilities
|
|
100%
|
|
380,000
|
|
|
350,000
|
|
|
|
Ownership Interest
|
|
Number of
Rack Spots |
|
Number of
Storage Spots |
||
NGL Rail Facilities
(5)
|
|
50-100%
|
|
335
|
|
|
1,515
|
|
|
(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.
|
•
|
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.
|
|
Volumes
(MBbls/d) |
|
Crude oil lease gathering purchases
|
894
|
|
NGL sales
|
259
|
|
Waterborne cargos
|
7
|
|
Supply and Logistics activities total
|
1,160
|
|
•
|
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.
|
•
|
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.
|
•
|
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;
|
•
|
We may face opposition to our planned growth projects from environmental groups, landowners, local groups and other advocates, including lawsuits or other actions designed to disrupt or delay our planned projects;
|
•
|
We may not be able to obtain, or we may be significantly delayed in obtaining, all of the rights of way or other real property interests we need to complete such projects, or the costs we incur in order to obtain such rights of way or other interests may be greater than we anticipated;
|
•
|
Despite the fact that we 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;
|
•
|
We may construct pipelines, facilities or other assets in anticipation of market demand that dissipates or market growth that never materializes;
|
•
|
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 we budgeted and the time it takes to complete construction of these projects and place them into commercial service could be significantly longer than planned; and
|
•
|
The completion or success of our projects may depend on the completion or success of third-party facilities over which we have no control.
|
•
|
performance from the acquired businesses or assets that is below the forecasts we used in evaluating the acquisition;
|
•
|
a significant increase in our 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 we are 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 our acquisition;
|
•
|
risks associated with operating in lines of business that are distinct and separate from our historical operations;
|
•
|
customer or key employee loss from the acquired businesses; and
|
•
|
the diversion of management’s attention from other business concerns.
|
•
|
a significant portion of our cash flow will be dedicated to the payment of principal and interest on our indebtedness and may not be available for other purposes, including the payment of distributions on our units and capital expenditures;
|
•
|
credit rating agencies may view our debt level negatively;
|
•
|
covenants contained in our existing debt arrangements will require us to continue to meet financial tests that may adversely affect our flexibility in planning for and reacting to changes in our business;
|
•
|
our ability to obtain additional financing for working capital, capital expenditures, acquisitions and general partnership purposes may be limited;
|
•
|
we may be at a competitive disadvantage relative to similar companies that have less debt; and
|
•
|
we may be more vulnerable to adverse economic and industry conditions as a result of our significant debt level.
|
•
|
a failure on the part of our storage facilities to perform as we expect them to, whether due to malfunction of equipment or facilities or realization of other operational risks;
|
•
|
the operating pressure of our storage facilities (affected in varying degree, depending on the type of storage cavern, by total volume of working and base gas, and temperature);
|
•
|
a variety of commercial decisions we make from time to time in connection with the management and operation of our storage facilities. Examples include, without limitation, decisions with respect to matters such as (i) the aggregate amount of commitments we are willing to make with respect to wheeling, injection, and withdrawal services, which could exceed our 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 we conduct opportunistic leaching activities at our facilities in connection with the expansion of existing salt caverns, which can impact the amount of storage capacity we have available to satisfy our customers’ requests, (iv) the timing and aggregate volume of any base gas park and/or loan transactions we consummate, which can directly affect the operating pressure of our storage facilities and (v) the amount of compression capacity and other gas handling equipment that we install at our 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.
|
•
|
generally, if a person acquires 20% or more of any class of units then outstanding other than from our general partner or its affiliates, the units owned by such person cannot be voted on any matter, except that such shares constituting up to 19.9% of the total shares outstanding may be voted in the election of PAGP GP directors; and
|
•
|
limitations upon the ability of unitholders to call meetings or to acquire information about our operations, as well as other limitations upon the unitholders’ ability to influence the manner or direction of management.
|
•
|
an existing unitholder’s proportionate ownership interest in the Partnership will decrease;
|
•
|
the amount of cash available for distribution on each unit may decrease;
|
•
|
the ratio of taxable income to distributions may increase;
|
•
|
the relative voting strength of each previously outstanding unit may be diminished; and
|
•
|
the market price of the common units may decline.
|
•
|
under our partnership agreement, we reimburse the general partner for the costs of managing and for operating the partnership;
|
•
|
the amount of cash expenditures, borrowings and reserves in any quarter may affect available cash to pay quarterly distributions to unitholders;
|
•
|
the general partner tries to avoid being liable for partnership obligations. The general partner is permitted to protect its assets in this manner by our partnership agreement. Under our partnership agreement the general partner would not breach its fiduciary duty by avoiding liability for partnership obligations even if we can obtain more favorable terms without limiting the general partner’s liability; under our partnership agreement, the general partner may pay its affiliates for any services rendered on terms fair and reasonable to us. The general partner may also enter into additional contracts with any of its affiliates on behalf of us. Agreements or contracts between us and our general partner (and its affiliates) are not necessarily the result of arms length negotiations; and
|
•
|
the general partner would not breach our partnership agreement by exercising its call rights to purchase limited partnership interests or by assigning its call rights to one of its affiliates or to us.
|
•
|
to provide for the proper conduct of our business and the businesses of our operating partnerships (including reserves for future capital expenditures and for our anticipated future credit needs);
|
•
|
to provide funds for distributions to our unitholders and the general partner for any one or more of the next four calendar quarters; or
|
•
|
to comply with applicable law or any of our loan or other agreements.
|
|
(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.
|
•
|
provide for the proper conduct of our business;
|
•
|
comply with applicable law or any partnership debt instrument or other agreement; or
|
•
|
provide funds for distributions to unitholders and the general partner in respect of any one or more of the next four quarters.
|
|
Year Ended December 31,
|
||||||||||||||||||
|
2016
|
|
2015
|
|
2014
|
|
2013
|
|
2012
|
||||||||||
|
(in millions, except per unit data)
|
||||||||||||||||||
Statement of operations data:
|
|
|
|
|
|
|
|
|
|
||||||||||
Total revenues
|
$
|
20,182
|
|
|
$
|
23,152
|
|
|
$
|
43,464
|
|
|
$
|
42,249
|
|
|
$
|
37,797
|
|
Operating income
|
$
|
994
|
|
|
$
|
1,262
|
|
|
$
|
1,799
|
|
|
$
|
1,738
|
|
|
$
|
1,434
|
|
Net income
|
$
|
730
|
|
|
$
|
906
|
|
|
$
|
1,386
|
|
|
$
|
1,391
|
|
|
$
|
1,127
|
|
Net income attributable to PAA
|
$
|
726
|
|
|
$
|
903
|
|
|
$
|
1,384
|
|
|
$
|
1,361
|
|
|
$
|
1,094
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Per unit data:
|
|
|
|
|
|
|
|
|
|
||||||||||
Basic net income per common unit
|
$
|
0.43
|
|
|
$
|
0.78
|
|
|
$
|
2.39
|
|
|
$
|
2.82
|
|
|
$
|
2.41
|
|
Diluted net income per common unit
|
$
|
0.43
|
|
|
$
|
0.77
|
|
|
$
|
2.38
|
|
|
$
|
2.80
|
|
|
$
|
2.40
|
|
Declared distributions per common unit
(1)
|
$
|
2.65
|
|
|
$
|
2.76
|
|
|
$
|
2.55
|
|
|
$
|
2.33
|
|
|
$
|
2.11
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Balance sheet data (at end of period):
|
|
|
|
|
|
|
|
|
|
||||||||||
Property and equipment, net
|
$
|
13,872
|
|
|
$
|
13,474
|
|
|
$
|
12,272
|
|
|
$
|
10,819
|
|
|
$
|
9,643
|
|
Total assets
|
$
|
24,210
|
|
|
$
|
22,288
|
|
|
$
|
22,198
|
|
|
$
|
20,320
|
|
|
$
|
19,196
|
|
Long-term debt
|
$
|
10,124
|
|
|
$
|
10,375
|
|
|
$
|
8,704
|
|
|
$
|
6,675
|
|
|
$
|
6,281
|
|
Total debt
|
$
|
11,839
|
|
|
$
|
11,374
|
|
|
$
|
9,991
|
|
|
$
|
7,788
|
|
|
$
|
7,367
|
|
Partners’ capital
|
$
|
8,816
|
|
|
$
|
7,939
|
|
|
$
|
8,191
|
|
|
$
|
7,703
|
|
|
$
|
7,146
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Other data:
|
|
|
|
|
|
|
|
|
|
||||||||||
Net cash provided by operating activities
|
$
|
726
|
|
|
$
|
1,344
|
|
|
$
|
2,004
|
|
|
$
|
1,954
|
|
|
$
|
1,240
|
|
Net cash used in investing activities
|
$
|
(1,273
|
)
|
|
$
|
(2,530
|
)
|
|
$
|
(3,296
|
)
|
|
$
|
(1,653
|
)
|
|
$
|
(3,392
|
)
|
Net cash provided by/(used in) financing activities
|
$
|
563
|
|
|
$
|
814
|
|
|
$
|
1,657
|
|
|
$
|
(281
|
)
|
|
$
|
2,151
|
|
Capital expenditures:
|
|
|
|
|
|
|
|
|
|
||||||||||
Acquisition capital
|
$
|
289
|
|
|
$
|
105
|
|
|
$
|
1,099
|
|
|
$
|
19
|
|
|
$
|
2,286
|
|
Expansion capital
|
$
|
1,405
|
|
|
$
|
2,170
|
|
|
$
|
2,026
|
|
|
$
|
1,622
|
|
|
$
|
1,185
|
|
Maintenance capital
|
$
|
186
|
|
|
$
|
220
|
|
|
$
|
224
|
|
|
$
|
176
|
|
|
$
|
170
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Volumes
(2) (3)
|
|
|
|
|
|
|
|
|
|
||||||||||
Transportation segment (average daily volumes in thousands of barrels per day):
|
|
|
|
|
|
|
|
|
|
||||||||||
Tariff activities
|
4,523
|
|
|
4,340
|
|
|
3,952
|
|
|
3,595
|
|
|
3,373
|
|
|||||
Trucking
|
114
|
|
|
113
|
|
|
127
|
|
|
117
|
|
|
106
|
|
|||||
Transportation segment total volumes
|
4,637
|
|
|
4,453
|
|
|
4,079
|
|
|
3,712
|
|
|
3,479
|
|
|||||
|
|
|
|
|
|
|
|
|
|
||||||||||
Facilities segment:
|
|
|
|
|
|
|
|
|
|
||||||||||
Crude oil, refined products and NGL terminalling and storage (average monthly capacity in millions of barrels)
|
107
|
|
|
100
|
|
|
95
|
|
|
94
|
|
|
90
|
|
|||||
Rail load / unload volumes (average volumes in thousands of barrels per day)
|
83
|
|
|
210
|
|
|
231
|
|
|
221
|
|
|
—
|
|
|||||
Natural gas storage (average monthly working capacity in billions of cubic feet)
|
97
|
|
|
97
|
|
|
97
|
|
|
96
|
|
|
84
|
|
|||||
NGL fractionation (average volumes in thousands of barrels per day)
|
115
|
|
|
103
|
|
|
96
|
|
|
96
|
|
|
79
|
|
|||||
Facilities segment total volumes (average monthly volumes in millions of barrels)
|
129
|
|
|
126
|
|
|
121
|
|
|
120
|
|
|
106
|
|
|||||
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
||||||||||||||||||
|
2016
|
|
2015
|
|
2014
|
|
2013
|
|
2012
|
||||||||||
|
(in millions, except per unit data)
|
||||||||||||||||||
Supply and Logistics segment (average daily volumes in thousands of barrels per day):
|
|
|
|
|
|
|
|
|
|
||||||||||
Crude oil lease gathering purchases
|
894
|
|
|
943
|
|
|
949
|
|
|
859
|
|
|
818
|
|
|||||
NGL sales
|
259
|
|
|
223
|
|
|
208
|
|
|
215
|
|
|
182
|
|
|||||
Waterborne cargos
|
7
|
|
|
2
|
|
|
—
|
|
|
4
|
|
|
3
|
|
|||||
Supply and Logistics segment total volumes
|
1,160
|
|
|
1,168
|
|
|
1,157
|
|
|
1,078
|
|
|
1,003
|
|
|
(1)
|
Represents cash distributions declared and paid during the year presented. See
Note 11
to our Consolidated Financial Statements for further discussion regarding our distributions.
|
(2)
|
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.
|
(3)
|
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.
|
•
|
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
|
•
|
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;
|
•
|
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;
|
•
|
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.
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2016
|
|
2015
|
|
2014
|
||||||
Acquisition capital
(1)
|
|
$
|
289
|
|
|
$
|
105
|
|
|
$
|
1,099
|
|
Expansion capital
(2)
|
|
1,405
|
|
|
2,170
|
|
|
2,026
|
|
|||
Maintenance capital
(2)
|
|
186
|
|
|
220
|
|
|
224
|
|
|||
|
|
$
|
1,880
|
|
|
$
|
2,495
|
|
|
$
|
3,349
|
|
|
(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.
|
Acquisition
|
|
Effective
Date
|
|
Acquisition
Price
|
|
Operating Segment
|
||
Western Canada NGL Assets
|
|
August 2016
|
|
$
|
204
|
|
|
Transportation and Facilities
|
Other
|
|
Various
|
|
85
|
|
|
Transportation
|
|
2016 Total
|
|
|
|
$
|
289
|
|
|
|
|
|
|
|
|
|
|
||
2015 Total
|
|
Various
|
|
$
|
105
|
|
|
Transportation and Facilities
|
|
|
|
|
|
|
|
||
BridgeTex Acquisition (50% interest)
(1)
|
|
November 2014
|
|
$
|
1,088
|
|
|
Transportation
|
Other
|
|
Various
|
|
11
|
|
|
Facilities
|
|
2014 Total
|
|
|
|
$
|
1,099
|
|
|
|
|
(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.
|
Projects
|
|
2016
|
|
2015
|
|
2014
|
||||||
Red River Pipeline (Cushing to Longview)
(1)
|
|
$
|
306
|
|
|
$
|
143
|
|
|
$
|
—
|
|
Permian Basin Area Projects
(2)
|
|
200
|
|
|
470
|
|
|
378
|
|
|||
Fort Saskatchewan Facility Projects / NGL Line
(2)
|
|
200
|
|
|
272
|
|
|
142
|
|
|||
Saddlehorn Pipeline
(4)
|
|
108
|
|
|
103
|
|
|
—
|
|
|||
Diamond Pipeline
(2) (5)
|
|
104
|
|
|
6
|
|
|
29
|
|
|||
Cushing Terminal Expansions
(2)
|
|
62
|
|
|
39
|
|
|
13
|
|
|||
St. James Terminal Expansions
(2)
|
|
51
|
|
|
45
|
|
|
25
|
|
|||
Eagle Ford JV Projects
(2) (5)
|
|
29
|
|
|
93
|
|
|
117
|
|
|||
Cactus Pipeline
(2)
|
|
26
|
|
|
134
|
|
|
350
|
|
|||
Rail Terminal Projects
(3)
|
|
5
|
|
|
294
|
|
|
239
|
|
|||
Other Projects
|
|
314
|
|
|
571
|
|
|
733
|
|
|||
Total
|
|
$
|
1,405
|
|
|
$
|
2,170
|
|
|
$
|
2,026
|
|
|
(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
.”
|
(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.
|
•
|
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.
|
|
|
|
|
|
|
|
|
|
Favorable/(Unfavorable) Variance
|
||||||||||||||||||
|
|
Year Ended December 31,
|
|
|
2016-2015
|
|
2015-2014
|
||||||||||||||||||||
|
|
2016
|
|
2015
|
|
2014
|
|
|
$
|
|
%
|
|
$
|
|
%
|
||||||||||||
Transportation segment adjusted EBITDA
(1)
|
|
$
|
1,141
|
|
|
$
|
1,056
|
|
|
$
|
979
|
|
|
|
$
|
85
|
|
|
8
|
%
|
|
$
|
77
|
|
|
8
|
%
|
Facilities segment adjusted EBITDA
(1)
|
|
667
|
|
|
588
|
|
|
597
|
|
|
|
79
|
|
|
13
|
%
|
|
(9
|
)
|
|
(2
|
)%
|
|||||
Supply and Logistics segment adjusted EBITDA
(1)
|
|
359
|
|
|
568
|
|
|
651
|
|
|
|
(209
|
)
|
|
(37
|
)%
|
|
(83
|
)
|
|
(13
|
)%
|
|||||
Adjustments:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Depreciation and amortization of unconsolidated entities
|
|
(50
|
)
|
|
(45
|
)
|
|
(29
|
)
|
|
|
(5
|
)
|
|
(11
|
)%
|
|
(16
|
)
|
|
(55
|
)%
|
|||||
Selected items impacting comparability - segment adjusted EBITDA
|
|
(434
|
)
|
|
(290
|
)
|
|
93
|
|
|
|
(144
|
)
|
|
**
|
|
|
(383
|
)
|
|
**
|
|
|||||
Depreciation and amortization
|
|
(494
|
)
|
|
(432
|
)
|
|
(384
|
)
|
|
|
(62
|
)
|
|
(14
|
)%
|
|
(48
|
)
|
|
(13
|
)%
|
|||||
Interest expense, net
|
|
(467
|
)
|
|
(432
|
)
|
|
(348
|
)
|
|
|
(35
|
)
|
|
(8
|
)%
|
|
(84
|
)
|
|
(24
|
)%
|
|||||
Other income/(expense), net
|
|
33
|
|
|
(7
|
)
|
|
(2
|
)
|
|
|
40
|
|
|
**
|
|
|
(5
|
)
|
|
**
|
|
|||||
Income tax expense
|
|
(25
|
)
|
|
(100
|
)
|
|
(171
|
)
|
|
|
75
|
|
|
75
|
%
|
|
71
|
|
|
42
|
%
|
|||||
Net income
|
|
730
|
|
|
906
|
|
|
1,386
|
|
|
|
(176
|
)
|
|
(19
|
)%
|
|
(480
|
)
|
|
(35
|
)%
|
|||||
Net income attributable to noncontrolling interests
|
|
(4
|
)
|
|
(3
|
)
|
|
(2
|
)
|
|
|
(1
|
)
|
|
(33
|
)%
|
|
(1
|
)
|
|
(50
|
)%
|
|||||
Net income attributable to PAA
|
|
$
|
726
|
|
|
$
|
903
|
|
|
$
|
1,384
|
|
|
|
$
|
(177
|
)
|
|
(20
|
)%
|
|
$
|
(481
|
)
|
|
(35
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Basic net income per common unit
|
|
$
|
0.43
|
|
|
$
|
0.78
|
|
|
$
|
2.39
|
|
|
|
$
|
(0.35
|
)
|
|
(45
|
)%
|
|
$
|
(1.61
|
)
|
|
(67
|
)%
|
Diluted net income per common unit
|
|
$
|
0.43
|
|
|
$
|
0.77
|
|
|
$
|
2.38
|
|
|
|
$
|
(0.34
|
)
|
|
(44
|
)%
|
|
$
|
(1.61
|
)
|
|
(68
|
)%
|
Basic weighted average common units outstanding
|
|
464
|
|
|
394
|
|
|
367
|
|
|
|
70
|
|
|
18
|
%
|
|
27
|
|
|
7
|
%
|
|||||
Diluted weighted average common units outstanding
|
|
466
|
|
|
396
|
|
|
369
|
|
|
|
70
|
|
|
18
|
%
|
|
27
|
|
|
7
|
%
|
|
(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.
|
|
|
|
|
|
|
|
|
|
Favorable/(Unfavorable) Variance
|
||||||||||||||||||
|
|
Year Ended December 31,
|
|
|
2016-2015
|
|
2015-2014
|
||||||||||||||||||||
|
|
2016
|
|
2015
|
|
2014
|
|
|
$
|
|
%
|
|
$
|
|
%
|
||||||||||||
Net income
|
|
$
|
730
|
|
|
906
|
|
|
$
|
1,386
|
|
|
|
$
|
(176
|
)
|
|
(19
|
)%
|
|
$
|
(480
|
)
|
|
(35
|
)%
|
|
Add/(Subtract):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Interest expense, net
|
|
467
|
|
|
432
|
|
|
348
|
|
|
|
35
|
|
|
8
|
%
|
|
84
|
|
|
24
|
%
|
|||||
Income tax expense
|
|
25
|
|
|
100
|
|
|
171
|
|
|
|
(75
|
)
|
|
(75
|
)%
|
|
(71
|
)
|
|
(42
|
)%
|
|||||
Depreciation and amortization
|
|
494
|
|
|
432
|
|
|
384
|
|
|
|
62
|
|
|
14
|
%
|
|
48
|
|
|
13
|
%
|
|||||
Depreciation and amortization of unconsolidated entities
(1)
|
|
50
|
|
|
45
|
|
|
29
|
|
|
|
5
|
|
|
11
|
%
|
|
16
|
|
|
55
|
%
|
|||||
Selected Items Impacting Comparability - Adjusted EBITDA:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
(Gains)/losses from derivative activities net of inventory valuation adjustments
(2)
|
|
404
|
|
|
110
|
|
|
(243
|
)
|
|
|
294
|
|
|
267
|
%
|
|
353
|
|
|
145
|
%
|
|||||
Deficiencies under minimum volume commitments, net
(3)
|
|
46
|
|
|
—
|
|
|
—
|
|
|
|
46
|
|
|
N/A
|
|
|
—
|
|
|
N/A
|
|
|||||
Long-term inventory costing adjustments
(4)
|
|
(58
|
)
|
|
99
|
|
|
85
|
|
|
|
(157
|
)
|
|
(159
|
)%
|
|
14
|
|
|
16
|
%
|
|||||
Equity-indexed compensation expense
(5)
|
|
33
|
|
|
27
|
|
|
56
|
|
|
|
6
|
|
|
22
|
%
|
|
(29
|
)
|
|
(52
|
)%
|
|||||
Net (gain)/loss on foreign currency revaluation
(6)
|
|
9
|
|
|
(29
|
)
|
|
9
|
|
|
|
38
|
|
|
131
|
%
|
|
(38
|
)
|
|
(422
|
)%
|
|||||
Line 901 incident
(7)
|
|
—
|
|
|
83
|
|
|
—
|
|
|
|
(83
|
)
|
|
(100
|
)%
|
|
83
|
|
|
N/A
|
|
|||||
Selected Items Impacting Comparability - segment adjusted EBITDA
|
|
434
|
|
|
290
|
|
|
(93
|
)
|
|
|
144
|
|
|
**
|
|
|
383
|
|
|
**
|
|
|||||
Gains from derivative activities
(2)
|
|
(30
|
)
|
|
—
|
|
|
—
|
|
|
|
(30
|
)
|
|
N/A
|
|
|
—
|
|
|
N/A
|
|
|||||
Net (gain)/loss on foreign currency revaluation
(6)
|
|
(1
|
)
|
|
8
|
|
|
4
|
|
|
|
(9
|
)
|
|
(113
|
)%
|
|
4
|
|
|
100
|
%
|
|||||
Selected Items Impacting Comparability - Adjusted
EBITDA
(8)
|
|
403
|
|
|
298
|
|
|
(89
|
)
|
|
|
105
|
|
|
**
|
|
|
387
|
|
|
**
|
|
|||||
Adjusted EBITDA
(8)
|
|
$
|
2,169
|
|
|
$
|
2,213
|
|
|
$
|
2,229
|
|
|
|
$
|
(44
|
)
|
|
(2
|
)%
|
|
$
|
(16
|
)
|
|
(1
|
)%
|
Interest expense
(9)
|
|
(451
|
)
|
|
(417
|
)
|
|
(334
|
)
|
|
|
(34
|
)
|
|
(8
|
)%
|
|
(83
|
)
|
|
(25
|
)%
|
|||||
Maintenance capital
(10)
|
|
(186
|
)
|
|
(220
|
)
|
|
(224
|
)
|
|
|
34
|
|
|
15
|
%
|
|
4
|
|
|
2
|
%
|
|||||
Current income tax expense
|
|
(85
|
)
|
|
(84
|
)
|
|
(71
|
)
|
|
|
(1
|
)
|
|
(1
|
)%
|
|
(13
|
)
|
|
(18
|
)%
|
|||||
Adjusted equity earnings in unconsolidated entities, net of distributions
(11)
|
|
(29
|
)
|
|
(14
|
)
|
|
(32
|
)
|
|
|
(15
|
)
|
|
(107
|
)%
|
|
18
|
|
|
56
|
%
|
|||||
Distributions to noncontrolling interests
(12)
|
|
(4
|
)
|
|
(4
|
)
|
|
(3
|
)
|
|
|
—
|
|
|
—
|
%
|
|
(1
|
)
|
|
(33
|
)%
|
|||||
Implied DCF
(13)
|
|
$
|
1,414
|
|
|
$
|
1,474
|
|
|
$
|
1,565
|
|
|
|
$
|
(60
|
)
|
|
(4
|
)%
|
|
$
|
(91
|
)
|
|
(6
|
)%
|
Less: Distributions paid
(12)
|
|
(1,565
|
)
|
|
(1,714
|
)
|
|
(1,469
|
)
|
|
|
|
|
|
|
|
|
|
|||||||||
DCF Excess/(Shortage)
(14)
|
|
$
|
(151
|
)
|
|
$
|
(240
|
)
|
|
$
|
96
|
|
|
|
|
|
|
|
|
|
|
|
(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
|
(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 support the return on our capital expenditure necessary to construct the related asset. Some of these agreements include make-up rights if the minimum volume is not met. We record a receivable from the counterparty in the period that services are provided or when the transaction occurs, including amounts for deficiency obligations from counterparties associated with minimum volume commitments. If a counterparty has a make-up right associated with a deficiency, we defer the revenue attributable to the counterparty’s make-up right and subsequently recognize the revenue at the earlier of when the deficiency volume is delivered or shipped, when the make-up right expires or when it is determined that the counterparty’s ability to utilize the make-up right is remote. We include the impact of amounts billed to counterparties for their deficiency obligation, net of applicable amounts subsequently recognized into revenue, as a selected item impacting comparability. We believe the inclusion of the contractually committed revenues associated with that period is meaningful to investors as the related asset has been constructed, is standing ready to provide the committed service and the fixed operating costs are included in the current period results. Amounts for years prior to 2016 were not significant.
|
(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.
|
(9)
|
Excludes certain non-cash items impacting interest expense such as amortization of debt issuance costs and terminated interest rate swaps.
|
(10)
|
Maintenance capital expenditures are defined as 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.
|
(11)
|
Does not include the depreciation and amortization expense of unconsolidated entities, as such expenses are excluded in the calculation of Adjusted EBITDA.
|
(12)
|
Includes distributions that pertain to the current period’s net income and are paid in the subsequent period.
|
(13)
|
Including net costs recognized during the period related to the Line 901 incident that occurred in May 2015, Implied DCF would have been $1,391 million for the year ended December 31, 2015. See
Note 17
to our Consolidated Financial Statements for additional information regarding the Line 901 incident.
|
(14)
|
Excess DCF is retained to establish reserves for future distributions, capital expenditures and other partnership purposes. DCF shortages are funded from previously established reserves, cash on hand or from borrowings under our credit facilities or commercial paper program.
|
|
|
|
|
|
|
|
|
|
Favorable/(Unfavorable) Variance
|
||||||||||||||||||
Operating Results
(1)
(in millions, except per barrel data) |
|
Year Ended December 31,
|
|
|
2016-2015
|
|
2015-2014
|
||||||||||||||||||||
|
2016
|
|
2015
|
|
2014
|
|
|
$
|
|
%
|
|
$
|
|
%
|
|||||||||||||
Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Tariff activities
|
|
$
|
1,436
|
|
|
$
|
1,439
|
|
|
$
|
1,447
|
|
|
|
$
|
(3
|
)
|
|
—
|
%
|
|
$
|
(8
|
)
|
|
(1
|
)%
|
Trucking
|
|
148
|
|
|
155
|
|
|
208
|
|
|
|
(7
|
)
|
|
(5
|
)%
|
|
(53
|
)
|
|
(25
|
)%
|
|||||
Total transportation revenues
|
|
1,584
|
|
|
1,594
|
|
|
1,655
|
|
|
|
(10
|
)
|
|
(1
|
)%
|
|
(61
|
)
|
|
(4
|
)%
|
|||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Costs and expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Trucking costs
|
|
(94
|
)
|
|
(108
|
)
|
|
(151
|
)
|
|
|
14
|
|
|
13
|
%
|
|
43
|
|
|
28
|
%
|
|||||
Field operating costs
(2)
|
|
(537
|
)
|
|
(652
|
)
|
|
(560
|
)
|
|
|
115
|
|
|
18
|
%
|
|
(92
|
)
|
|
(16
|
)%
|
|||||
Equity-indexed compensation expense - field operating costs
|
|
(14
|
)
|
|
(5
|
)
|
|
(15
|
)
|
|
|
(9
|
)
|
|
(180
|
)%
|
|
10
|
|
|
67
|
%
|
|||||
Segment general and administrative expenses
(2) (3)
|
|
(88
|
)
|
|
(89
|
)
|
|
(83
|
)
|
|
|
1
|
|
|
1
|
%
|
|
(6
|
)
|
|
(7
|
)%
|
|||||
Equity-indexed compensation expense - general and administrative
|
|
(15
|
)
|
|
(6
|
)
|
|
(29
|
)
|
|
|
(9
|
)
|
|
(150
|
)%
|
|
23
|
|
|
79
|
%
|
|||||
Equity earnings in unconsolidated entities
|
|
195
|
|
|
183
|
|
|
108
|
|
|
|
12
|
|
|
7
|
%
|
|
75
|
|
|
69
|
%
|
|||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Adjustments
(4)
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Depreciation and amortization of unconsolidated entities
|
|
50
|
|
|
45
|
|
|
29
|
|
|
|
5
|
|
|
11
|
%
|
|
16
|
|
|
55
|
%
|
|||||
Deficiencies under minimum volume commitments, net
|
|
44
|
|
|
—
|
|
|
—
|
|
|
|
44
|
|
|
N/A
|
|
|
—
|
|
|
N/A
|
|
|||||
Line 901 incident
|
|
—
|
|
|
83
|
|
|
—
|
|
|
|
(83
|
)
|
|
(100
|
)%
|
|
83
|
|
|
N/A
|
|
|||||
Equity-indexed compensation expense
|
|
16
|
|
|
11
|
|
|
25
|
|
|
|
5
|
|
|
45
|
%
|
|
(14
|
)
|
|
(56
|
)%
|
|||||
Segment adjusted EBITDA
|
|
$
|
1,141
|
|
|
$
|
1,056
|
|
|
$
|
979
|
|
|
|
$
|
85
|
|
|
8
|
%
|
|
$
|
77
|
|
|
8
|
%
|
Maintenance capital
|
|
$
|
121
|
|
|
$
|
144
|
|
|
$
|
165
|
|
|
|
$
|
(23
|
)
|
|
(16
|
)%
|
|
$
|
(21
|
)
|
|
(13
|
)%
|
Segment adjusted EBITDA per barrel
|
|
$
|
0.67
|
|
|
$
|
0.65
|
|
|
$
|
0.66
|
|
|
|
$
|
0.02
|
|
|
3
|
%
|
|
$
|
(0.01
|
)
|
|
(2
|
)%
|
|
|
|
|
|
|
|
|
|
Favorable/(Unfavorable) Variance
|
|||||||||||||
Average Daily Volumes
(in thousands of barrels per day) (5) |
|
Year Ended December 31,
|
|
|
2016-2015
|
|
2015-2014
|
|||||||||||||||
|
2016
|
|
2015
|
|
2014
|
|
|
Volumes
|
|
%
|
|
Volumes
|
|
%
|
||||||||
Tariff activities volumes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
Crude oil pipelines (by region):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
Permian Basin
(6)
|
|
2,146
|
|
|
1,849
|
|
|
1,512
|
|
|
|
297
|
|
|
16
|
%
|
|
337
|
|
|
22
|
%
|
South Texas / Eagle Ford
(6)
|
|
284
|
|
|
306
|
|
|
227
|
|
|
|
(22
|
)
|
|
(7
|
)%
|
|
79
|
|
|
35
|
%
|
Western
|
|
188
|
|
|
215
|
|
|
260
|
|
|
|
(27
|
)
|
|
(13
|
)%
|
|
(45
|
)
|
|
(17
|
)%
|
Rocky Mountain
(6)
|
|
449
|
|
|
440
|
|
|
426
|
|
|
|
9
|
|
|
2
|
%
|
|
14
|
|
|
3
|
%
|
Gulf Coast
|
|
497
|
|
|
532
|
|
|
492
|
|
|
|
(35
|
)
|
|
(7
|
)%
|
|
40
|
|
|
8
|
%
|
Central
(6)
|
|
394
|
|
|
413
|
|
|
450
|
|
|
|
(19
|
)
|
|
(5
|
)%
|
|
(37
|
)
|
|
(8
|
)%
|
Canada
|
|
381
|
|
|
392
|
|
|
399
|
|
|
|
(11
|
)
|
|
(3
|
)%
|
|
(7
|
)
|
|
(2
|
)%
|
Crude oil pipelines
|
|
4,339
|
|
|
4,147
|
|
|
3,766
|
|
|
|
192
|
|
|
5
|
%
|
|
381
|
|
|
10
|
%
|
NGL pipelines
|
|
184
|
|
|
193
|
|
|
186
|
|
|
|
(9
|
)
|
|
(5
|
)%
|
|
7
|
|
|
4
|
%
|
Tariff activities total volumes
|
|
4,523
|
|
|
4,340
|
|
|
3,952
|
|
|
|
183
|
|
|
4
|
%
|
|
388
|
|
|
10
|
%
|
Trucking volumes
|
|
114
|
|
|
113
|
|
|
127
|
|
|
|
1
|
|
|
1
|
%
|
|
(14
|
)
|
|
(11
|
)%
|
Transportation segment total volumes
|
|
4,637
|
|
|
4,453
|
|
|
4,079
|
|
|
|
184
|
|
|
4
|
%
|
|
374
|
|
|
9
|
%
|
|
(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.
|
|
|
Favorable/(Unfavorable) Variance
2016-2015 |
|
|
Favorable/(Unfavorable) Variance
2015-2014 |
||||||||||||
(in millions)
|
|
Revenues
|
|
Equity Earnings
|
|
|
Revenues
|
|
Equity Earnings
|
||||||||
Tariff activities:
|
|
|
|
|
|
|
|
|
|
||||||||
Permian Basin region
|
|
$
|
98
|
|
|
$
|
7
|
|
|
|
$
|
75
|
|
|
$
|
52
|
|
South Texas / Eagle Ford region
|
|
(7
|
)
|
|
(1
|
)
|
|
|
12
|
|
|
19
|
|
||||
Western region
|
|
(6
|
)
|
|
—
|
|
|
|
(24
|
)
|
|
—
|
|
||||
Rocky Mountain region
|
|
(18
|
)
|
|
10
|
|
|
|
7
|
|
|
10
|
|
||||
Gulf Coast region
|
|
(19
|
)
|
|
—
|
|
|
|
10
|
|
|
—
|
|
||||
Central region
|
|
(23
|
)
|
|
2
|
|
|
|
(8
|
)
|
|
—
|
|
||||
Canada crude oil
|
|
(2
|
)
|
|
—
|
|
|
|
(16
|
)
|
|
—
|
|
||||
NGL
|
|
11
|
|
|
—
|
|
|
|
(2
|
)
|
|
—
|
|
||||
Other (including pipeline loss allowance revenue)
|
|
(37
|
)
|
|
(6
|
)
|
|
|
(62
|
)
|
|
(6
|
)
|
||||
Total variance
|
|
$
|
(3
|
)
|
|
$
|
12
|
|
|
|
$
|
(8
|
)
|
|
$
|
75
|
|
•
|
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
|
•
|
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.
|
|
|
Year Ended December 31,
|
|
|
Favorable/(Unfavorable) Variance
|
||||||||||||||||
Operating Segment
|
|
2016
|
|
2015
|
|
2014
|
|
|
2016-2015
|
|
2015-2014
|
||||||||||
Transportation
|
|
$
|
29
|
|
|
$
|
11
|
|
|
$
|
44
|
|
|
|
$
|
(18
|
)
|
|
$
|
33
|
|
Facilities
|
|
15
|
|
|
5
|
|
|
24
|
|
|
|
(10
|
)
|
|
19
|
|
|||||
Supply and Logistics
|
|
16
|
|
|
11
|
|
|
30
|
|
|
|
(5
|
)
|
|
19
|
|
|||||
|
|
$
|
60
|
|
|
$
|
27
|
|
|
$
|
98
|
|
|
|
$
|
(33
|
)
|
|
$
|
71
|
|
|
|
|
|
|
|
|
|
|
Favorable/(Unfavorable) Variance
|
||||||||||||||||||
Operating Results
(1)
(in millions, except per barrel data) |
|
Year Ended December 31,
|
|
|
2016-2015
|
|
2015-2014
|
||||||||||||||||||||
|
2016
|
|
2015
|
|
2014
|
|
|
$
|
|
%
|
|
$
|
|
%
|
|||||||||||||
Revenues
|
|
$
|
1,107
|
|
|
$
|
1,050
|
|
|
$
|
1,127
|
|
|
|
$
|
57
|
|
|
5
|
%
|
|
$
|
(77
|
)
|
|
(7
|
)%
|
Natural gas related storage costs
|
|
(26
|
)
|
|
(24
|
)
|
|
(55
|
)
|
|
|
(2
|
)
|
|
(8
|
)%
|
|
31
|
|
|
56
|
%
|
|||||
Field operating costs
(2)
|
|
(347
|
)
|
|
(377
|
)
|
|
(404
|
)
|
|
|
30
|
|
|
8
|
%
|
|
27
|
|
|
7
|
%
|
|||||
Equity-indexed compensation expense - field operating costs
|
|
(5
|
)
|
|
—
|
|
|
(4
|
)
|
|
|
(5
|
)
|
|
N/A
|
|
|
4
|
|
|
100
|
%
|
|||||
Segment general and administrative expenses
(2) (3)
|
|
(58
|
)
|
|
(65
|
)
|
|
(60
|
)
|
|
|
7
|
|
|
11
|
%
|
|
(5
|
)
|
|
(8
|
)%
|
|||||
Equity-indexed compensation expense - general and administrative
|
|
(10
|
)
|
|
(5
|
)
|
|
(20
|
)
|
|
|
(5
|
)
|
|
(100
|
)%
|
|
15
|
|
|
75
|
%
|
|||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Adjustments
(4)
|
|
6
|
|
|
9
|
|
|
13
|
|
|
|
(3
|
)
|
|
(33
|
)%
|
|
(4
|
)
|
|
(31
|
)%
|
|||||
Segment adjusted EBITDA
|
|
$
|
667
|
|
|
$
|
588
|
|
|
$
|
597
|
|
|
|
$
|
79
|
|
|
13
|
%
|
|
$
|
(9
|
)
|
|
(2
|
)%
|
Maintenance capital
|
|
$
|
55
|
|
|
$
|
68
|
|
|
$
|
52
|
|
|
|
$
|
(13
|
)
|
|
(19
|
)%
|
|
$
|
16
|
|
|
31
|
%
|
Segment adjusted EBITDA per barrel
|
|
$
|
0.43
|
|
|
$
|
0.39
|
|
|
$
|
0.41
|
|
|
|
$
|
0.04
|
|
|
10
|
%
|
|
$
|
(0.02
|
)
|
|
(5
|
)%
|
|
|
|
|
|
|
|
|
|
Favorable/(Unfavorable) Variance
|
|||||||||||||
|
|
Year Ended December 31,
|
|
|
2016-2015
|
|
2015-2014
|
|||||||||||||||
Volumes
(5)
|
|
2016
|
|
2015
|
|
2014
|
|
|
Volumes
|
|
%
|
|
Volumes
|
|
%
|
|||||||
Crude oil, refined products and NGL terminalling and storage (average monthly capacity in millions of barrels)
|
|
107
|
|
|
100
|
|
|
95
|
|
|
|
7
|
|
|
7
|
%
|
|
5
|
|
|
5
|
%
|
Rail load / unload volumes (average volumes in thousands of barrels per day)
|
|
83
|
|
|
210
|
|
|
231
|
|
|
|
(127
|
)
|
|
(60
|
)%
|
|
(21
|
)
|
|
(9
|
)%
|
Natural gas storage (average monthly working capacity in billions of cubic feet)
|
|
97
|
|
|
97
|
|
|
97
|
|
|
|
—
|
|
|
—
|
%
|
|
—
|
|
|
—
|
%
|
NGL fractionation (average volumes in thousands of barrels per day)
|
|
115
|
|
|
103
|
|
|
96
|
|
|
|
12
|
|
|
12
|
%
|
|
7
|
|
|
7
|
%
|
Facilities segment total volumes (average monthly volumes in millions of barrels)
(6)
|
|
129
|
|
|
126
|
|
|
121
|
|
|
|
3
|
|
|
2
|
%
|
|
5
|
|
|
4
|
%
|
|
(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
|
•
|
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.
|
|
|
|
|
|
|
|
|
|
Favorable/(Unfavorable) Variance
|
||||||||||||||||||
Operating Results
(1)
(in millions, except per barrel data) |
|
Year Ended December 31,
|
|
|
2016-2015
|
|
2015-2014
|
||||||||||||||||||||
|
2016
|
|
2015
|
|
2014
|
|
|
$
|
|
%
|
|
$
|
|
%
|
|||||||||||||
Revenues
|
|
$
|
19,018
|
|
|
$
|
21,945
|
|
|
$
|
42,150
|
|
|
|
$
|
(2,927
|
)
|
|
(13
|
)%
|
|
$
|
(20,205
|
)
|
|
(48
|
)%
|
Purchases and related costs
|
|
(18,627
|
)
|
|
(21,018
|
)
|
|
(40,752
|
)
|
|
|
2,391
|
|
|
11
|
%
|
|
19,734
|
|
|
48
|
%
|
|||||
Field operating costs
(2)
|
|
(291
|
)
|
|
(433
|
)
|
|
(481
|
)
|
|
|
142
|
|
|
33
|
%
|
|
48
|
|
|
10
|
%
|
|||||
Equity-indexed compensation expense - field operating costs
|
|
(1
|
)
|
|
—
|
|
|
(2
|
)
|
|
|
(1
|
)
|
|
N/A
|
|
|
2
|
|
|
100
|
%
|
|||||
Segment general and administrative expenses
(2) (3)
|
|
(93
|
)
|
|
(102
|
)
|
|
(105
|
)
|
|
|
9
|
|
|
9
|
%
|
|
3
|
|
|
3
|
%
|
|||||
Equity-indexed compensation expense - general and administrative
|
|
(15
|
)
|
|
(11
|
)
|
|
(28
|
)
|
|
|
(4
|
)
|
|
(36
|
)%
|
|
17
|
|
|
61
|
%
|
|||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Adjustments
(4)
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
(Gains)/losses from derivative activities net of inventory valuation adjustments
|
|
406
|
|
|
106
|
|
|
(243
|
)
|
|
|
300
|
|
|
283
|
%
|
|
349
|
|
|
144
|
%
|
|||||
Long-term inventory costing adjustments
|
|
(58
|
)
|
|
99
|
|
|
85
|
|
|
|
(157
|
)
|
|
(159
|
)%
|
|
14
|
|
|
16
|
%
|
|||||
Net (gain)/loss on foreign currency revaluation
|
|
10
|
|
|
(29
|
)
|
|
9
|
|
|
|
39
|
|
|
134
|
%
|
|
(38
|
)
|
|
(422
|
)%
|
|||||
Equity-indexed compensation expense
|
|
10
|
|
|
11
|
|
|
18
|
|
|
|
(1
|
)
|
|
(9
|
)%
|
|
(7
|
)
|
|
(39
|
)%
|
|||||
Segment adjusted EBITDA
|
|
$
|
359
|
|
|
$
|
568
|
|
|
$
|
651
|
|
|
|
$
|
(209
|
)
|
|
(37
|
)%
|
|
$
|
(83
|
)
|
|
(13
|
)%
|
Maintenance capital
|
|
$
|
10
|
|
|
$
|
8
|
|
|
$
|
7
|
|
|
|
$
|
2
|
|
|
25
|
%
|
|
$
|
1
|
|
|
14
|
%
|
Segment adjusted EBITDA per barrel
|
|
$
|
0.85
|
|
|
$
|
1.33
|
|
|
$
|
1.54
|
|
|
|
$
|
(0.48
|
)
|
|
(36
|
)%
|
|
$
|
(0.21
|
)
|
|
(14
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
|
|
|
|
|
|
|
|
|
Favorable (Unfavorable) Variance
|
||||||||||||||||||
Average Daily Volumes
(in thousands of barrels per day) |
|
Year Ended December 31,
|
|
|
2016-2015
|
|
2015-2014
|
||||||||||||||||||||
|
2016
|
|
2015
|
|
2014
|
|
|
Volume
|
|
%
|
|
Volume
|
|
%
|
|||||||||||||
Crude oil lease gathering purchases
|
|
894
|
|
|
943
|
|
|
949
|
|
|
|
(49
|
)
|
|
(5
|
)%
|
|
(6
|
)
|
|
(1
|
)%
|
|||||
NGL sales
|
|
259
|
|
|
223
|
|
|
208
|
|
|
|
36
|
|
|
16
|
%
|
|
15
|
|
|
7
|
%
|
|||||
Waterborne cargos
|
|
7
|
|
|
2
|
|
|
—
|
|
|
|
5
|
|
|
250
|
%
|
|
2
|
|
|
N/A
|
|
|||||
Supply and Logistics segment total volumes
|
|
1,160
|
|
|
1,168
|
|
|
1,157
|
|
|
|
(8
|
)
|
|
(1
|
)%
|
|
11
|
|
|
1
|
%
|
|
(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.
|
|
|
NYMEX WTI
Crude Oil Price |
||||||
During the Year Ended December 31,
|
|
Low
|
|
High
|
||||
2016
|
|
$
|
26
|
|
|
$
|
54
|
|
2015
|
|
$
|
35
|
|
|
$
|
61
|
|
2014
|
|
$
|
53
|
|
|
$
|
107
|
|
•
|
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-to-market gains and losses from a prior period), gains and losses on certain derivatives that are related to investing activities (such as the purchase of linefill) and inventory valuation adjustments, as applicable. See Note 12 to our Consolidated Financial Statements for a comprehensive discussion regarding our derivatives and risk management activities.
|
•
|
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
|
•
|
interest capitalized on capital projects.
|
|
|
|
|
Average
LIBOR
|
|
Weighted Average
Interest Rate
(1)
|
||||
Interest expense for the year ended December 31, 2014
|
|
$
|
348
|
|
|
0.1
|
%
|
|
4.5
|
%
|
Impact of issuance of senior notes
|
|
88
|
|
|
|
|
|
|||
Impact of retirement of senior notes
|
|
(9
|
)
|
|
|
|
|
|||
Impact of capitalized interest
|
|
(9
|
)
|
|
|
|
|
|||
Other
|
|
14
|
|
|
|
|
|
|||
Interest expense for the year ended December 31, 2015
|
|
$
|
432
|
|
|
0.2
|
%
|
|
4.5
|
%
|
Impact of issuance of senior notes
|
|
34
|
|
|
|
|
|
|||
Impact of retirement of senior notes
|
|
(19
|
)
|
|
|
|
|
|||
Impact of borrowings under credit facilities and commercial paper program
|
|
12
|
|
|
|
|
|
|||
Impact of capitalized interest
|
|
10
|
|
|
|
|
|
|||
Other
|
|
(2
|
)
|
|
|
|
|
|||
Interest expense for the year ended December 31, 2016
|
|
$
|
467
|
|
|
0.5
|
%
|
|
4.5
|
%
|
|
(1)
|
Excludes commitment and other fees.
|
|
As of
December 31, 2016
|
||
Availability under senior unsecured revolving credit facility
(1) (2)
|
$
|
1,580
|
|
Availability under senior secured hedged inventory facility
(1) (2)
|
597
|
|
|
Availability under senior unsecured 364-day revolving credit facility
|
1,000
|
|
|
Amounts outstanding under commercial paper program
|
(810
|
)
|
|
Subtotal
|
2,367
|
|
|
Cash and cash equivalents
|
47
|
|
|
Total
|
$
|
2,414
|
|
|
(1)
|
Represents availability prior to giving effect to amounts outstanding under our commercial paper program, which reduce available capacity under the facilities.
|
(2)
|
Available capacity under the senior unsecured revolving credit facility and the senior secured hedged inventory facility was reduced by outstanding letters of credit of $20 million and $53 million, respectively.
|
Year
|
|
Type of Offering
|
|
Units Issued
|
|
Net Proceeds
(1) (2)
|
|
|||
2016 Total
|
|
Continuous Offering Program
|
|
26,278,288
|
|
|
$
|
805
|
|
(3)
|
|
|
|
|
|
|
|
|
|||
2015
|
|
Continuous Offering Program
|
|
1,133,904
|
|
|
$
|
59
|
|
(3)
|
2015
|
|
Underwritten Offering
|
|
21,000,000
|
|
|
1,062
|
|
(4)
|
|
2015 Total
|
|
|
|
22,133,904
|
|
|
$
|
1,121
|
|
|
|
|
|
|
|
|
|
|
|||
2014 Total
|
|
Continuous Offering Program
|
|
15,375,810
|
|
|
$
|
866
|
|
(3)
|
|
(1)
|
Amounts are net of costs associated with the offerings.
|
(2)
|
For periods prior to the closing of the Simplification Transactions, amounts include our general partner’s proportionate capital contributions of
$9 million
,
$22 million
and
$18 million
during
2016
,
2015
and
2014
, respectively.
|
(3)
|
We pay commissions to our sales agents in connection with common unit issuances under our Continuous Offering Program. We 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.
|
(4)
|
A portion of the net proceeds from such offering was used to repay borrowings under our commercial paper program and the remaining net proceeds were used for general partnership purposes, including expenditures for our 2015 capital program.
|
Year
|
|
Description
|
|
Maturity
|
|
Face Value
|
|
Gross
Proceeds
(1)
|
|
Net
Proceeds
(2)
|
||||||
2016
|
|
4.50% Senior Notes issued at 99.716% of face value
(3)
|
|
December 2026
|
|
$
|
750
|
|
|
$
|
748
|
|
|
$
|
741
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
2015
|
|
4.65% Senior Notes issued at 99.846% of face value
(3)
|
|
October 2025
|
|
$
|
1,000
|
|
|
$
|
998
|
|
|
$
|
990
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
2014
|
|
2.60% Senior Notes issued at 99.813% of face value
(4)
|
|
December 2019
|
|
$
|
500
|
|
|
$
|
499
|
|
|
$
|
495
|
|
2014
|
|
4.90% Senior Notes issued at 99.876% of face value
(4)
|
|
February 2045
|
|
$
|
650
|
|
|
$
|
649
|
|
|
$
|
643
|
|
2014
|
|
3.60% Senior Notes issued at 99.842% of face value
(3)
|
|
November 2024
|
|
$
|
750
|
|
|
$
|
749
|
|
|
$
|
743
|
|
2014
|
|
4.70% Senior Notes issued at 99.734% of face value
(3)
|
|
June 2044
|
|
$
|
700
|
|
|
$
|
698
|
|
|
$
|
691
|
|
|
(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)
|
We used the net proceeds from this offering to repay outstanding borrowings under our credit facilities or commercial paper program and for general partnership purposes.
|
(4)
|
We used the net proceeds from this offering to repay outstanding borrowings under our 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.
|
Projects
|
|
2017
|
Diamond Pipeline
|
|
$300
|
Permian Basin Area Systems
(1)
|
|
120
|
Fort Saskatchewan Facility Projects
|
|
90
|
Cushing Terminal Expansions
|
|
30
|
Other Projects
|
|
260
|
Total Projected 2017 Expansion Capital Expenditures
|
|
$800
|
|
(1)
|
Includes projected capital projects associated with our recently acquired Alpha Crude Connector gathering system.
|
|
|
2017
|
|
2018
|
|
2019
|
|
2020
|
|
2021
|
|
2022 and
Thereafter |
|
Total
|
||||||||||||||
Long-term debt, including current maturities and related interest payments
(1)
|
|
$
|
1,128
|
|
|
$
|
1,054
|
|
|
$
|
1,270
|
|
|
$
|
870
|
|
|
$
|
940
|
|
|
$
|
11,054
|
|
|
$
|
16,316
|
|
Leases and rights-of-way easements
(2)
|
|
195
|
|
|
165
|
|
|
140
|
|
|
118
|
|
|
97
|
|
|
404
|
|
|
1,119
|
|
|||||||
Other obligations
(3)
|
|
662
|
|
|
223
|
|
|
163
|
|
|
143
|
|
|
139
|
|
|
465
|
|
|
1,795
|
|
|||||||
Subtotal
|
|
1,985
|
|
|
1,442
|
|
|
1,573
|
|
|
1,131
|
|
|
1,176
|
|
|
11,923
|
|
|
19,230
|
|
|||||||
Crude oil, natural gas, NGL and other purchases
(4)
|
|
5,068
|
|
|
2,626
|
|
|
2,120
|
|
|
1,492
|
|
|
1,283
|
|
|
4,377
|
|
|
16,966
|
|
|||||||
Total
|
|
$
|
7,053
|
|
|
$
|
4,068
|
|
|
$
|
3,693
|
|
|
$
|
2,623
|
|
|
$
|
2,459
|
|
|
$
|
16,300
|
|
|
$
|
36,196
|
|
|
(1)
|
Includes debt service payments, interest payments due on senior notes, the commitment fee on assumed available capacity under our credit facilities, and long-term borrowings under our commercial paper program. Although there may be short-term borrowings under our credit facilities and commercial paper program, we historically repay and borrow at varying amounts. As such, we have included only the maximum commitment fee (as if no short-term borrowings were outstanding on the credit facilities or 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.
|
Entity
|
|
Type of Operation
|
|
Our
Ownership Interest |
|
Total Entity
Assets |
|
Total Cash
and Restricted Cash |
|
Total Entity
Debt |
|||||||
Settoon Towing, LLC (“Settoon”)
(1)
|
|
Barge Transportation Services
|
|
50
|
%
|
|
$
|
318
|
|
|
$
|
—
|
|
|
$
|
201
|
|
BridgeTex Pipeline Company, LLC
|
|
Crude Oil Pipeline
|
|
50
|
%
|
|
$
|
920
|
|
|
$
|
31
|
|
|
$
|
—
|
|
Caddo Pipeline LLC
|
|
Crude Oil Pipeline
|
|
50
|
%
|
|
$
|
125
|
|
|
$
|
2
|
|
|
$
|
—
|
|
Cheyenne Pipeline LLC
|
|
Crude Oil Pipeline
|
|
50
|
%
|
|
$
|
60
|
|
|
$
|
4
|
|
|
$
|
—
|
|
Diamond Pipeline LLC
|
|
Crude Oil Pipeline
|
|
50
|
%
|
|
$
|
300
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Eagle Ford Pipeline LLC
|
|
Crude Oil Pipeline
|
|
50
|
%
|
|
$
|
776
|
|
|
$
|
17
|
|
|
$
|
—
|
|
Eagle Ford Terminals Corpus Christi LLC
|
|
Crude Oil Terminal and Dock
|
|
50
|
%
|
|
$
|
105
|
|
|
$
|
7
|
|
|
$
|
—
|
|
Frontier Aspen LLC
|
|
Crude Oil Pipeline
|
|
50
|
%
|
|
$
|
27
|
|
|
$
|
5
|
|
|
$
|
—
|
|
STACK Pipeline LLC
|
|
Crude Oil Pipeline
|
|
50
|
%
|
|
$
|
34
|
|
|
$
|
6
|
|
|
$
|
—
|
|
Saddlehorn Pipeline Company, LLC
|
|
Crude Oil Pipeline
|
|
40
|
%
|
|
$
|
587
|
|
|
$
|
53
|
|
|
$
|
—
|
|
White Cliffs Pipeline, LLC
|
|
Crude Oil Pipeline
|
|
36
|
%
|
|
$
|
568
|
|
|
$
|
5
|
|
|
$
|
—
|
|
Butte Pipe Line Company
|
|
Crude Oil Pipeline
|
|
22
|
%
|
|
$
|
41
|
|
|
$
|
5
|
|
|
$
|
—
|
|
|
(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
|
•
|
NGL and other
|
|
Fair Value
|
|
Effect of 10%
Price Increase
|
|
Effect of 10%
Price Decrease
|
||||||
Crude oil
|
$
|
(111
|
)
|
|
$
|
(96
|
)
|
|
$
|
97
|
|
Natural gas
|
8
|
|
|
$
|
11
|
|
|
$
|
(11
|
)
|
|
NGL and other
|
(185
|
)
|
|
$
|
(68
|
)
|
|
$
|
68
|
|
|
Total fair value
|
$
|
(288
|
)
|
|
|
|
|
Name
|
Class
|
Expiration of Initial Term
|
Officer Directors:
|
|
|
Greg L. Armstrong
|
N/A
|
N/A
|
Harry N. Pefanis
|
N/A
|
N/A
|
Willie Chiang
|
N/A
|
N/A
|
|
|
|
Designated Directors:
|
|
|
John T. Raymond
|
I
|
2020
|
Robert V. Sinnott
|
II
|
2019
|
Bernard (Ben) Figlock
|
III
|
2018
|
|
|
|
Independent Directors:
|
|
|
Everardo Goyanes
|
I
|
2020
|
J. Taft Symonds
|
I
|
2020
|
Victor Burk
|
II
|
2019
|
Gary R. Petersen
|
II
|
2019
|
Bobby S. Shackouls
|
III
|
2018
|
Christopher M. Temple
|
III
|
2018
|
•
|
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.
|
|
Everardo Goyanes,
Chairman
|
|
Victor Burk
|
|
J. Taft Symonds
|
|
|
Name
|
|
Age (as of
12/31/16)
|
|
Position
(1)
|
Greg L. Armstrong*
(2)
|
|
58
|
|
Chairman of the Board, Chief Executive Officer and Director
|
Harry N. Pefanis*
|
|
59
|
|
President and Chief Operating Officer and Director
|
Wilfred (Willie) C. Chiang*
|
|
56
|
|
Executive Vice President and Chief Operating Officer (U.S.) and Director
|
Mark J. Gorman
|
|
62
|
|
Executive Vice President
|
Richard K. McGee*
|
|
55
|
|
Executive Vice President, General Counsel and Secretary
|
Daniel J. Nerbonne*
|
|
59
|
|
Executive Vice President—Operations and Engineering
|
Al Swanson*
|
|
52
|
|
Executive Vice President and Chief Financial Officer
|
John P. vonBerg*
|
|
62
|
|
Executive Vice President—Commercial Activities
|
Samuel N. Brown
|
|
60
|
|
Senior Vice President
|
Lawrence J. Dreyfuss
|
|
62
|
|
Senior Vice President, General Counsel—Commercial & Litigation and Assistant Secretary
|
John Keffer
|
|
57
|
|
Senior Vice President
|
Alfred A. Lindseth
|
|
47
|
|
Senior Vice President—Technology, Process & Risk Management
|
Phil Smith
|
|
58
|
|
Senior Vice President—Operations
|
Jason Balasch
|
|
48
|
|
President, Plains Midstream Canada
|
Kevin L. Cantrell
|
|
56
|
|
Vice President—Internal Audit
|
Brad Deets
|
|
43
|
|
Senior Vice President, NGL Commercial and Facilities, Plains Midstream Canada
|
Steve Falgoust
|
|
53
|
|
Vice President—Asset Integrity
|
James Ferrell
|
|
45
|
|
Vice President—Supply Chain Management
|
Bill Forward
|
|
50
|
|
Vice President, Finance, Plains Midstream Canada
|
James B. Fryfogle
|
|
65
|
|
Vice President—Bulk Supply and Logistics
|
Jeremy L. Goebel
|
|
39
|
|
Vice President—Acquisitions and Strategic Planning
|
Dean Gore
|
|
58
|
|
Vice President—Environmental and Regulatory Compliance
|
Chris Herbold*
|
|
44
|
|
Vice President—Accounting and Chief Accounting Officer
|
Barry Holtzman
|
|
57
|
|
Vice President—Safety, Security and Training
|
Keith Jalbert
|
|
51
|
|
Vice President—Commercial Activities
|
Christopher M. Kean
|
|
52
|
|
Vice President, Engineering, Plains Midstream Canada
|
Sterling Koch
|
|
47
|
|
Vice President, Health, Safety, Environment & Regulatory, Plains Midstream Canada
|
Dwayne Koehn
|
|
43
|
|
Vice President—Engineering
|
Don Lacey
|
|
62
|
|
Vice President, Operations, Plains Midstream Canada
|
Mark Mazerolle
|
|
52
|
|
Vice President, Pipelines & Supply, Plains Midstream Canada
|
James H. Pinchback
|
|
51
|
|
Vice President—Pipeline Business Development
|
Michelle Podavin
|
|
43
|
|
Vice President—NGL Supply and Facilities, Plains Midstream Canada
|
George N. Polydoros
|
|
53
|
|
Vice President—Land and Office Services
|
Megan Prout
|
|
40
|
|
Vice President—Commercial Law and Litigation
|
Tyler Rimbey
|
|
50
|
|
Senior Vice President, Crude Commercial and Pipelines, Plains Midstream Canada
|
Name
|
|
Age (as of
12/31/16)
|
|
Position
(1)
|
James Roberts
|
|
50
|
|
Vice President—Lease Supply
|
Robert M. Sanford
|
|
67
|
|
Vice President—Lease Supply
|
David Schwarz
|
|
47
|
|
Vice President, Human Resources, Plains Midstream Canada
|
James Shelford
|
|
34
|
|
Vice President, LPG Commercial, Plains Midstream Canada
|
Scott Sill
|
|
54
|
|
Senior Vice President, Operations, Plains Midstream Canada
|
Sharon S. Spurlin
|
|
51
|
|
Vice President and Treasurer
|
Jim Tillis
|
|
49
|
|
Vice President—Human Resources
|
Walter van Zanten
|
|
60
|
|
Vice President—Tax
|
Sandi Wingert
|
|
46
|
|
Senior Vice President and Chief Financial Officer, Plains Midstream Canada
|
Victor Burk
|
|
67
|
|
Director and Member of Audit Committee
|
Bernard (Ben) Figlock
(2)
|
|
56
|
|
Director
|
Everardo Goyanes
|
|
72
|
|
Director and Member of Audit** Committee
|
Gary R. Petersen
|
|
70
|
|
Director and Member of Compensation and Governance Committees
|
John T. Raymond
(2)
|
|
46
|
|
Director and Member of Compensation Committee
|
Bobby Shackouls
|
|
66
|
|
Director and Member of Governance** Committee
|
Robert V. Sinnott
(2)
|
|
67
|
|
Director and Member of Compensation** Committee
|
J. Taft Symonds
|
|
77
|
|
Director and Member of Audit and Governance Committees
|
Christopher M. Temple
|
|
49
|
|
Director
|
|
*
|
Indicates an “executive officer” for purposes of Item 401(b) of Regulation S-K.
|
**
|
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.
|
(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 Unitholder Matters—Beneficial Ownership of General Partner Interest.”
|
|
Robert V. Sinnott,
Chairman
|
|
Gary R. Petersen
|
|
John T. Raymond
|
1.
|
Maintain a solid balance sheet, sound credit metrics and ample liquidity;
|
2.
|
Execute our 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 our assets and focus our organization to deliver the best results possible under whatever conditions we encounter in the near term.
|
•
|
Raising $2.4 billion of common and preferred equity on terms considered by us 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
|
•
|
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 $1.2 billion.
|
Name and Principal
Position
|
|
Year
|
|
Salary
($)
|
|
Bonus
($)
|
|
Stock
Awards
($)
(1)
|
|
All Other
Compensation
($)
(2)
|
|
Total
($)
|
|||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Greg L. Armstrong
|
|
2016
|
|
40,000
|
|
|
—
|
|
|
—
|
|
|
2,575
|
|
|
42,575
|
|
Chairman and Chief Executive
|
|
2015
|
|
375,000
|
|
|
—
|
|
|
—
|
|
|
17,340
|
|
|
392,340
|
|
Officer
|
|
2014
|
|
375,000
|
|
|
3,900,000
|
|
|
—
|
|
|
17,040
|
|
|
4,292,040
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Harry N. Pefanis
|
|
2016
|
|
300,000
|
|
|
—
|
|
|
—
|
|
|
17,340
|
|
|
317,340
|
|
President and Chief Operating
|
|
2015
|
|
300,000
|
|
|
—
|
|
|
—
|
|
|
17,340
|
|
|
317,340
|
|
Officer
|
|
2014
|
|
300,000
|
|
|
3,800,000
|
|
|
—
|
|
|
17,040
|
|
|
4,117,040
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Wilfred (Willie) C. Chiang
|
|
2016
|
|
250,000
|
|
|
—
|
|
|
2,542,650
|
|
|
17,340
|
|
|
2,809,990
|
|
Executive Vice President and Chief
|
|
2015
|
|
89,102
|
|
|
500,000
|
|
|
5,330,830
|
|
|
5,886
|
|
|
5,925,818
|
|
Operating Officer (U.S.)
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Al Swanson
|
|
2016
|
|
250,000
|
|
|
—
|
|
|
2,126,580
|
|
|
17,340
|
|
|
2,393,920
|
|
Executive Vice President and
|
|
2015
|
|
250,000
|
|
|
900,000
|
|
|
—
|
|
|
17,340
|
|
|
1,167,340
|
|
Chief Financial Officer
|
|
2014
|
|
250,000
|
|
|
1,650,000
|
|
|
—
|
|
|
17,040
|
|
|
1,917,040
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Richard McGee
|
|
2016
|
|
250,000
|
|
|
—
|
|
|
3,265,760
|
|
|
17,340
|
|
|
3,533,100
|
|
Executive Vice President, General Counsel and Secretary
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Daniel J. Nerbonne
|
|
2016
|
|
232,292
|
|
|
—
|
|
|
2,122,694
|
|
|
25,638
|
|
|
2,380,624
|
|
Executive Vice President - Operations and Engineering
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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 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. See Note 16 to our Consolidated Financial Statements for further discussion regarding the calculation of grant date fair values.
|
(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 $8,400.
|
Name
|
|
Grant
Date
|
|
All Other Stock Awards:
Number Of Shares Of Stock or Units (#)
|
|
Grant Date
Fair Value Of
Stock and Option
Awards ($)
(4)
|
|||
|
|
|
|
|
|
|
|||
Al Swanson
|
|
8/25/16
|
|
138,000
|
|
(1)
|
$
|
2,126,580
|
|
Wilfred (Willie) C. Chiang
|
|
8/25/16
|
|
165,000
|
|
(1)
|
$
|
2,542,650
|
|
Richard McGee
|
|
8/25/16
|
|
138,000
|
|
(1)
|
$
|
2,126,580
|
|
|
|
9/15/16
|
|
61,174
|
|
(2)
|
$
|
1,139,180
|
|
Dan Nerbonne
|
|
8/25/16
|
|
95,000
|
|
(1)
|
$
|
1,463,944
|
|
|
|
8/25/16
|
|
25,000
|
|
(3)
|
$
|
658,750
|
|
|
(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 $2,803,217 for Mr. Nerbonne.
|
|
|
Unit Awards
|
||||||||||
Name
|
|
Number of
Shares or
Units of Stock
That Have
Not
Vested (#)
|
|
Market
Value of
Shares or
Units of
Stock That
Have Not
Vested ($)
(1)
|
|
Equity
Incentive Plan
Awards:
Number of
Unearned
Shares, Units
or Other
Rights That
Have Not
Vested (#)
|
|
Equity
Incentive Plan
Awards:
Market or
Payout Value
of Unearned
Shares, Units
or Other
Rights That
Have Not
Vested ($)
(1)
|
||||
|
|
|
|
|
|
|
|
|
||||
Greg L. Armstrong
|
|
100,000
|
|
(2)
|
3,229,000
|
|
|
—
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
||||
Harry N. Pefanis
|
|
90,000
|
|
(2)
|
2,906,100
|
|
|
—
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
||||
Wilfred (Willie) C. Chiang
|
|
—
|
|
|
—
|
|
|
375,521
|
|
(3)
|
12,258,999
|
|
|
|
—
|
|
|
—
|
|
|
120,000
|
|
(7)
|
3,874,800
|
|
|
|
110,000
|
|
(8)
|
3,551,900
|
|
|
55,000
|
|
(8)
|
1,775,950
|
|
|
|
|
|
|
|
|
|
|
||||
Al Swanson
|
|
66,667
|
|
(2)
|
2,152,677
|
|
|
—
|
|
|
—
|
|
|
|
92,000
|
|
(8)
|
2,970,680
|
|
|
46,000
|
|
(8)
|
1,485,340
|
|
|
|
|
|
|
|
|
|
|
||||
Richard McGee
|
|
60,000
|
|
(2)
|
1,937,400
|
|
|
—
|
|
|
—
|
|
|
|
195,755
|
|
(4)
|
6,390,449
|
|
|
—
|
|
|
—
|
|
|
|
183,520
|
|
(4)
|
5,991,074
|
|
|
61,174
|
|
(5)
|
1,997,048
|
|
|
|
92,000
|
|
(8)
|
2,970,680
|
|
|
46,000
|
|
(8)
|
1,485,340
|
|
|
|
|
|
|
|
|
|
|
||||
Dan Nerbonne
|
|
36,000
|
|
(2)
|
1,162,440
|
|
|
—
|
|
|
—
|
|
|
|
—
|
|
|
—
|
|
|
56,328
|
|
(6)
|
1,838,838
|
|
|
|
63,333
|
|
(8)
|
2,045,023
|
|
|
31,667
|
|
(8)
|
1,022,527
|
|
|
|
25,000
|
|
(9)
|
807,250
|
|
|
—
|
|
|
—
|
|
|
(1)
|
Market value of phantom units reported in these columns is calculated by multiplying the closing market price ($32.29) of our 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 our 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 we pay a quarterly distribution of at least $0.55 per common unit ($2.20 annualized) and generate 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), 25% will become earned on the first date subsequent to March 31, 2017 upon which we pay a quarterly distribution of at least $0.625 per common unit ($2.50 annualized, and 25% will become earned on the first date subsequent to March 31, 2017 on which we pay a quarterly distribution of at least $0.70 per common unit ($2.80 annualized). These AAP Management Units are subject to a call right in the event Mr. Chiang’s employment is terminated under certain circumstances prior to December 31, 2022. If Mr. Chiang remains employed after such date, his AAP Management Units will be deemed to have vested. Mr. Chiang’s employment agreement provides for the accelerated vesting of his AAP Management Units under certain circumstances prior to December 31, 2018. See “—Employment Contracts” and “—Potential Payments Upon Termination or Change-in-Control.”
|
(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 our 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 $2.50 per common unit. The phantom units also vest upon termination of employment under certain circumstances. See “—Employment Contracts” and “—Potential Payments Upon Termination or Change-in-Control.” Any phantom units that have not vested as of the August 2021 distribution date will be forfeited. Upon vesting, the phantom units are payable on a one-for-one basis in common units. The phantom units have associated DERs that are currently vested and payable in cash on each distribution payment date.
|
(8)
|
Represents phantom units granted in 2016 under our Long-Term Incentive Plan. For a description of the vesting terms of these awards, see “Compensation Discussion and Analysis—Application in 2016—Long-Term Incentive Awards”.
|
(9)
|
Represents phantom units granted to Mr. Nerbonne in 2016 under our Long-Term Incentive Plan. These phantom units, which include DERs payable in cash, will vest 100% on December 14, 2018.
|
|
|
Unit Awards
|
|
||||
Name
|
|
Number of Units
Acquired on
Vesting (#)
|
|
Value Realized on
Vesting ($)
|
|
||
|
|
|
|
|
|
||
Greg L. Armstrong
|
|
50,000
|
|
(1)
|
1,457,500
|
|
(3)
|
|
|
|
|
|
|
||
Harry N. Pefanis
|
|
45,000
|
|
(1)
|
1,311,750
|
|
(3)
|
|
|
|
|
|
|
||
Wilfred (Willie) C. Chiang
|
|
—
|
|
|
—
|
|
|
|
|
|
|
|
|
||
Al Swanson
|
|
33,333
|
|
(1)
|
966,657
|
|
(2)
|
|
|
|
|
|
|
||
Richard McGee
|
|
30,000
|
|
(1)
|
870,000
|
|
(2)
|
|
|
|
|
|
|
||
Dan Nerbonne
|
|
18,000
|
|
(1)
|
522,000
|
|
(2)
|
|
(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 our 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 ($29.15) of our common units on August 12, 2016 (the vesting date) by the number of units that vested.
|
|
|
By Reason of
Death
($)
|
|
By Reason of
Disability
($)
|
|
By Company
without
Cause
($)
|
|
By Executive
with Good
Reason
($)
|
|
In Connection with a
Change In Control
($)
|
|
|||||
Greg L. Armstrong
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Salary and Bonus
|
|
8,550,000
|
|
(1)
|
8,550,000
|
|
(1)
|
8,550,000
|
|
(1)
|
8,550,000
|
|
(1)
|
12,825,000
|
|
(2)
|
Equity Compensation
|
|
3,229,000
|
|
(3)
|
3,229,000
|
|
(3)
|
3,229,000
|
|
(4)
|
3,229,000
|
|
(4)
|
3,229,000
|
|
(5)
|
Health Benefits
|
|
N/A
|
|
|
36,844
|
|
(6)
|
36,844
|
|
(6)
|
36,844
|
|
(6)
|
36,844
|
|
(6)
|
Tax Gross-up
|
|
N/A
|
|
|
N/A
|
|
|
N/A
|
|
|
N/A
|
|
|
112,219
|
|
(7)
|
AAP Management Units
|
|
N/A
|
|
|
N/A
|
|
|
N/A
|
|
(8)
|
N/A
|
|
(8)
|
N/A
|
|
(9)
|
Total
|
|
11,779,000
|
|
|
11,815,844
|
|
|
11,815,844
|
|
|
11,815,844
|
|
|
16,203,063
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
By Reason of
Death
($)
|
|
By Reason of
Disability
($)
|
|
By Company
without
Cause
($)
|
|
By Executive
with Good
Reason
($)
|
|
In Connection with a
Change In Control
($)
|
|
|||||
Harry N. Pefanis
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Salary and Bonus
|
|
8,200,000
|
|
(1)
|
8,200,000
|
|
(1)
|
8,200,000
|
|
(1)
|
8,200,000
|
|
(1)
|
12,300,000
|
|
(2)
|
Equity Compensation
|
|
2,906,100
|
|
(3)
|
2,906,100
|
|
(3)
|
2,906,100
|
|
(4)
|
2,906,100
|
|
(4)
|
2,906,100
|
|
(5)
|
Health Benefits
|
|
N/A
|
|
|
57,286
|
|
(6)
|
57,286
|
|
(6)
|
57,286
|
|
(6)
|
57,286
|
|
(6)
|
Tax Gross-up
|
|
N/A
|
|
|
N/A
|
|
|
N/A
|
|
|
N/A
|
|
|
603,349
|
|
(7)
|
AAP Management Units
|
|
N/A
|
|
|
N/A
|
|
|
N/A
|
|
(8)
|
N/A
|
|
(8)
|
N/A
|
|
(9)
|
Total
|
|
11,106,100
|
|
|
11,163,386
|
|
|
11,163,386
|
|
|
11,163,386
|
|
|
15,866,735
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Wilfred (Willie) C. Chiang
(10)
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Equity Compensation
|
|
—
|
|
(3)
|
—
|
|
(3)
|
3,874,800
|
|
(4)
|
3,874,800
|
|
(4)
|
9,202,650
|
|
(5)
|
AAP Management Units
|
|
6,129,499
|
|
(11)
|
6,129,499
|
|
(11)
|
12,258,999
|
|
(8)
|
12,258,999
|
|
(8)
|
12,258,999
|
|
(9)
|
Total
|
|
6,129,499
|
|
|
6,129,499
|
|
|
16,133,799
|
|
|
16,133,799
|
|
|
21,461,649
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Al Swanson
(10)
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Equity Compensation
|
|
2,152,645
|
|
(3)
|
2,152,645
|
|
(3)
|
2,152,645
|
|
(4)
|
N/A
|
|
|
6,608,665
|
|
(5)
|
AAP Management Units
|
|
N/A
|
|
|
N/A
|
|
|
N/A
|
|
(8)
|
N/A
|
|
(8)
|
N/A
|
|
(9)
|
Total
|
|
2,152,645
|
|
|
2,152,645
|
|
|
2,152,645
|
|
|
—
|
|
|
6,608,665
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Richard McGee
(10)
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Equity Compensation
|
|
1,937,400
|
|
(3)
|
1,937,400
|
|
(3)
|
1,937,400
|
|
(4)
|
N/A
|
|
|
6,393,420
|
|
(5)
|
AAP Management Units
|
|
N/A
|
|
|
N/A
|
|
|
7,189,285
|
|
(8)
|
7,189,285
|
|
(8)
|
8,187,801
|
|
(9)
|
Total
|
|
1,937,400
|
|
|
1,937,400
|
|
|
9,126,685
|
|
|
7,189,285
|
|
|
14,581,221
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Dan Nerbonne
(10)
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Equity Compensation
|
|
1,162,440
|
|
(3)
|
1,162,440
|
|
(3)
|
1,162,440
|
|
(4)
|
N/A
|
|
|
5,037,240
|
|
(5)
|
AAP Management Units
|
|
N/A
|
|
|
N/A
|
|
|
—
|
|
(8)
|
—
|
|
(8)
|
459,709
|
|
(9)
|
Total
|
|
1,162,440
|
|
|
1,162,440
|
|
|
1,162,440
|
|
|
—
|
|
|
5,496,949
|
|
|
|
(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 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.
|
(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 our 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 following distribution date and (ii) the remaining unvested outstanding phantom units will vest on the distribution date on which the vesting criteria is met. The letters evidencing the 2016 phantom unit grants awarded to our Named Executive Officers provide that in the event of their death or disability (as defined below), the following terms shall apply: (a) if such death or disability takes place prior to the second anniversary of the date of the applicable grant (August 25, 2018), all of their then outstanding phantom units and associated DERs will be automatically forfeited as of such date, and (b) if such death or disability takes place on or after such second anniversary, all of their then outstanding phantom units will be deemed nonforfeitable and will vest on the next following distribution date (and any associated DERs shall not be forfeited but shall vest, be payable and expire according to the terms of the applicable phantom unit grant letter). For these purposes, “disability” means a physical or mental infirmity that impairs the ability substantially to perform duties for a period of eighteen (18) months or that the general partner otherwise determines constitutes a disability.
|
(4)
|
Pursuant to the 2013 phantom unit grants held by our 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 our 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) our 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 our 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 our 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 our 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).
|
(5)
|
The letters evidencing phantom unit grants awarded to our 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 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.
|
(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).
|
(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).
|
(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 ($34.68) of PAGP’s Class A shares at December 30, 2016 (the last trading day of the fiscal year).
|
Name
|
|
Fees
Earned
or Paid in
Cash ($)
(1)
|
|
Stock
Awards ($)
(2)
|
|
Total ($)
|
|||
Victor Burk
|
|
42,500
|
|
|
45,040
|
|
|
87,540
|
|
Ben Figlock
(3)
|
|
45,000
|
|
|
n/a
|
|
|
45,000
|
|
Everardo Goyanes
|
|
75,000
|
|
|
172,774
|
|
|
247,774
|
|
Gary R. Petersen
|
|
121,250
|
|
|
72,875
|
|
|
194,125
|
|
John T. Raymond
|
|
45,000
|
|
|
72,875
|
|
|
117,875
|
|
Bobby S. Shackouls
|
|
40,875
|
|
|
45,040
|
|
|
85,915
|
|
Robert V. Sinnott
|
|
47,000
|
|
|
72,875
|
|
|
119,875
|
|
J. Taft Symonds
|
|
138,250
|
|
|
145,750
|
|
|
284,000
|
|
Christopher M. Temple
|
|
155,000
|
|
|
145,750
|
|
|
300,750
|
|
|
(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 than the incremental audit committee awards), a cash payment of $89,600 was made to Oxy as directed by Mr. Figlock. Such cash payment was based on the unit value of Mr. Sinnott’s award on the previous year’s vesting date. In connection with the February 2016 vesting of PAGP director LTIP awards, Messrs. Burk and Shackouls each were granted 3,004 phantom PAGP Class A shares and Mr. Goyanes was granted 1,803 phantom PAGP Class A shares by virtue of the automatic re-grant feature of the vested awards. As of December 31, 2016, the number of outstanding PAA LTIPs held by our directors was as follows: Goyanes - 20,000; Petersen - 10,000; Raymond - 10,000; Sinnott - 10,000; Symonds - 20,000; and Temple - 20,000. As of December 31, 2016, the number of outstanding PAGP LTIPs held by our directors was as follows: Burk - 12,016; Goyanes - 7,210; and Shackouls - 12,016. These arrangements were modified in February 2017 (see below for a description of the modified arrangements).
|
(3)
|
Mr. Figlock’s compensation is assigned to Oxy.
|
Name of Beneficial
Owner and Address (in the case of Owners of more than 5%)
|
|
Common
Units
|
|
Percentage
of Common
Units
|
|
Preferred
Units
(1)
|
|
Percentage
of Preferred
Units
|
||||
EnCap Partners LLC
(2)
|
|
—
|
|
|
—
|
|
|
23,426,064
|
|
|
35.7
|
%
|
EMG Fund IV PAA Holdings, LLC
(3)
|
|
—
|
|
|
—
|
|
|
18,824,515
|
|
|
28.7
|
%
|
FR KA Plains Holdings LLC
(4)
|
|
—
|
|
|
—
|
|
|
11,713,032
|
|
|
17.8
|
%
|
Stonepeak Partners LLC
(5)
|
|
—
|
|
|
—
|
|
|
5,856,515
|
|
|
8.9
|
%
|
Plains AAP, L.P.
|
|
243,383,735
|
|
|
36.1
|
%
|
|
—
|
|
|
—
|
|
Richard A. Kayne/Kayne Anderson Capital Advisors, L.P.
(6)
|
|
13,361,597
|
|
|
2.0
|
%
|
|
5,856,500
|
|
|
8.9
|
%
|
Greg L. Armstrong
|
|
1,467,871
|
|
(7)
|
*
|
|
|
—
|
|
|
—
|
|
Harry N. Pefanis
|
|
847,532
|
|
(7)
|
*
|
|
|
—
|
|
|
—
|
|
Wilfred (Willie) C. Chiang
|
|
—
|
|
(7)
|
—
|
|
|
—
|
|
|
—
|
|
Al Swanson
|
|
100,998
|
|
(7)
|
*
|
|
|
—
|
|
|
—
|
|
Richard McGee
|
|
113,420
|
|
(7)
|
*
|
|
|
—
|
|
|
—
|
|
Daniel J. Nerbonne
|
|
—
|
|
(7)
|
—
|
|
|
—
|
|
|
—
|
|
Victor Burk
|
|
14,543
|
|
(7)
|
*
|
|
|
—
|
|
|
—
|
|
Ben Figlock
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Everardo Goyanes
|
|
88,400
|
|
(7)
|
*
|
|
|
—
|
|
|
—
|
|
Gary R. Petersen
(2)
|
|
49,450
|
|
(7)
|
*
|
|
|
23,426,064
|
|
|
35.7
|
%
|
John T. Raymond
(3)
|
|
1,599,616
|
|
(7)
|
*
|
|
|
18,824,515
|
|
|
28.7
|
%
|
Bobby Shackouls
|
|
19,418
|
|
|
*
|
|
|
—
|
|
|
—
|
|
Robert V. Sinnott
|
|
346,393
|
|
(7)(8)
|
*
|
|
|
—
|
|
|
—
|
|
J. Taft Symonds
|
|
104,050
|
|
(7)
|
*
|
|
|
—
|
|
|
—
|
|
Christopher M. Temple
|
|
31,250
|
|
(7)
|
*
|
|
|
—
|
|
|
—
|
|
All directors and executive officers as a group (18 persons)
|
|
5,212,489
|
|
(7)(9)
|
*
|
|
|
42,250,579
|
|
|
64.4
|
%
|
|
*
|
Less than 1%.
|
(1)
|
The Preferred Units will vote on an as-converted basis with the common units and will have certain other class voting rights with respect to any amendment to our partnership agreement that would adversely affect any rights, preferences or privileges of the Preferred Units. The Preferred Units are convertible, generally on a one-for-one basis and subject to customary anti-dilution adjustments, (i) by the holders after January 28, 2018, and (ii) by us after January 28, 2019.
|
(2)
|
The Preferred Units are owned by funds managed by EnCap Partners, LLC, whose address is 1100 Louisiana, Suite 4900, Houston, Texas 77002. Gary R. Petersen may be deemed to be the beneficial owner of the Preferred Units owned by these holders by virtue of being a member of EnCap Partners, LLC, the managing member of each holder’s general partner. Mr. Petersen disclaims beneficial ownership of the Preferred Units except to the extent of his pecuniary interest therein.
|
(3)
|
The address for this holder is 811 Main Street, Suite 4200, Houston, Texas 77002. John T. Raymond has sole voting and dispositive power over the Preferred Units and may be deemed to be the beneficial owner of the Preferred Units owned by the holder by virtue of being the sole member of the general partner of the holder’s manager. Mr. Raymond disclaims beneficial ownership of the Preferred Units except to the extent of his pecuniary interest therein.
|
(4)
|
The address for this holder is 600 Travis, Suite 6000, Houston, Texas 77002.
|
(5)
|
The Preferred Units are owned by a fund managed by Stonepeak Partners LLC, whose address is 717 Fifth Avenue, 25th Floor, New York, New York 10022.
|
(6)
|
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 9,918,015 common units and 5,856,500 Preferred Units. Mr. Kayne may be deemed to beneficially own such units. In addition, Mr. Kayne directly owns or has sole voting and dispositive power over 3,443,582 common units. Mr. Kayne disclaims beneficial ownership of any of our partner interests other than units held by him or interests attributable to him by virtue of his interests in the accounts that own our partner interests. The address for
|
(7)
|
Does not include unvested phantom units granted under our Long-Term Incentive Plans, none of which will vest within 60 days of the date hereof. See Item 11. “Executive Compensation—Outstanding Equity Awards at Fiscal Year-End” and “— Director Compensation.”
|
(8)
|
Pursuant to the PAGP GP LLC Agreement, Mr. Sinnott is designated as a member of the board of directors of PAGP GP by KAFU Holdings, L.P., which is controlled by Kayne Anderson Investment Management, Inc., of which he is President. Mr. Sinnott disclaims any deemed beneficial ownership of the interests owned by KAFU Holdings, L.P. or its affiliates, beyond his pecuniary interest therein, if any. Mr. Sinnott has a non-controlling ownership interest in KACALP, which is the general partner of KAFU Holdings, L.P. KACALP is entitled to a percentage of the profits earned by the funds invested in KAFU Holdings, L.P. The address for KAFU Holdings, L.P. is 1800 Avenue of the Stars, 3rd Floor, Los Angeles, California 90067.
|
(9)
|
As of February 15, 2017, no units were pledged by directors or Named Executive Officers.
|
Name of Owner and Address (in the case of Owners of more than 5%)
|
|
Percentage
Ownership of
Plains AAP, L.P.
Class A LP
Interest
|
|
Economic
Interest in
Plains
AAP, L.P.
(1)
|
||
Plains GP Holdings, L.P. and Plains All American GP LLC
333 Clay Street, Suite 1600 Houston, TX 77002 |
|
42.8
|
%
|
|
42.3
|
%
|
EMG Investment, LLC
811 Main, Suite 4200
Houston, TX 77002
|
|
18.9
|
%
|
|
18.7
|
%
|
KAFU Holdings, L.P. and Affiliates
1800 Avenue of the Stars, 3rd Floor
Los Angeles, CA 90067
|
|
11.2
|
%
|
|
11.0
|
%
|
Oxy Holding Company (Pipeline), Inc.
5 Greenway Plaza
Houston, TX 77046
|
|
12.4
|
%
|
|
12.3
|
%
|
Strome PAA, L.P. and Affiliate
|
|
2.8
|
%
|
|
2.8
|
%
|
Windy, L.L.C.
|
|
2.8
|
%
|
|
2.7
|
%
|
Lynx Holdings I, LLC
|
|
1.3
|
%
|
|
1.3
|
%
|
Various Individual Investors and Former PAA Management LP Investors
(2)(3)
|
|
7.8
|
%
|
|
7.7
|
%
|
AAP Management Unitholders
(4)
|
|
—
|
|
|
1.2
|
%
|
|
(1)
|
AAP owns approximately 243.4 million common units and a 100% member interest in PAA GP LLC, which owns our 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;
|
(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 PAGP Class B shares. Additionally, a portion of the resulting AAP units and PAGP Class B shares has been exchanged for PAGP 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 PAGP Class A shares (none of our outside directors own any AAP Management Units):
|
Name of Owner
|
|
AAP Management
Units
|
|
AAP Units*
|
|
PAGP Class A
Shares
|
|||
Greg L. Armstrong
|
|
—
|
|
|
5,757,268
|
|
|
450,625
|
|
Harry N. Pefanis
|
|
—
|
|
|
3,768,988
|
|
|
183,654
|
|
Wilfred (Willie) C. Chiang
|
|
375,521
|
|
|
—
|
|
|
75,104
|
|
Al Swanson
|
|
—
|
|
|
433,620
|
|
|
918,219
|
|
Richard McGee
|
|
440,449
|
|
|
14,739
|
|
|
—
|
|
Daniel J. Nerbonne
|
|
56,328
|
|
|
4,913
|
|
|
184,010
|
|
All executive officers as a group
|
|
1,019,115
|
|
|
11,113,323
|
|
|
3,739,871
|
|
Plan
Category
|
|
Number of Units
to
be Issued upon
Exercise/Vesting
of
Outstanding
Options,
Warrants and
Rights
(a)
|
|
Weighted Average
Exercise Price of
Outstanding
Options,
Warrants and
Rights
(b)
|
|
Number of Units
Remaining
Available
for Future
Issuance
under Equity
Compensation
Plans
(c)
|
|
||
Equity compensation plans approved by unitholders: 2013 Long Term Incentive Plan
|
|
4,095,569
|
|
(1)
|
N/A
|
(2)
|
7,502,103
|
|
(1)(3)
|
|
|
|
|
|
|
|
|
||
Equity compensation plans not approved by unitholders: PNG Successor LTIP
|
|
581,670
|
|
(4)
|
N/A
|
(2)
|
570,607
|
|
(3)(4)
|
|
(1)
|
The 2013 Long-Term Incentive Plan (the “2013 Plan”), which was approved by our unitholders in November 2013, consolidated three prior plans (the Plains All American GP LLC 1998 Long-Term Incentive Plan (the “1998 Plan”), the Plains All American GP LLC 2005 Long-Term Incentive Plan (the “2005 Plan”), and the PPX Successor Long-Term Incentive Plan (the “PPX Successor Plan”)). The 2013 Plan contemplates the issuance or delivery of up to 13,074,686 common units to satisfy awards under the plan, which amount is net of 4,774,932 common units previously issued under the prior plans. The number of units presented in column (a) assumes that all remaining grants will be satisfied by the issuance of new units upon vesting unless such grants are by their terms payable only in cash. In fact, a substantial number of phantom units that have vested were satisfied without the issuance of units. These phantom units were settled in cash or withheld for taxes. Any units not issued upon vesting will become “available for future issuance” under column (c).
|
(2)
|
Phantom unit awards under the 2013 Plan and PNG Successor Plan vest without payment by recipients.
|
(3)
|
In accordance with Item 201(d) of Regulation S-K, column (c) excludes the securities disclosed in column (a). However, as discussed in footnotes (1) and (4), any phantom units represented in column (a) that are not satisfied by the issuance of units become “available for future issuance.”
|
(4)
|
In December 2013, in connection with the PNG Merger, we adopted and assumed the PAA Natural Gas Storage, L.P. 2010 Long Term Incentive Plan (the “PNG Legacy Plan”), and all outstanding awards of PNG phantom units were converted into comparable awards of PAA phantom units by applying the merger exchange ratio of 0.445 PAA common units for each PNG common unit and rounding down for any fractions. The GP LLC board of directors amended and restated the PNG Legacy Plan, which is now known as the PNG Successor Long-Term Incentive Plan (the “PNG Successor Plan”). The PNG Successor Plan contemplates the issuance or delivery of up to 1,319,983 units to satisfy awards under the plan, which amount is net of 15,017 common units previously issued under the PNG Legacy Plan. The number of units presented in column (a) assumes that all outstanding grants will be satisfied by the issuance of new units upon vesting unless such LTIPs are by their terms payable only in cash. In fact, some portion of the phantom units may be settled in cash and some portion will be withheld for taxes. Any units not issued upon vesting will become “available for future issuance” under column (c).
|
•
|
the permanent elimination of our IDRs and the economic rights associated with our 2% general partner interest in exchange for the issuance by us 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 us 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 PAGP GP assumed oversight responsibility over both us and PAGP;
|
•
|
the provision for annual PAGP shareholder elections beginning in 2018 with certain directors with expiring terms in 2018, and the participation of our common unitholders and Series A preferred unitholders in such elections through our ownership of newly issued Class C shares in PAGP, which provide us, 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 our 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 our 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 our common units held by AAP. We 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 our common units held by AAP (an “AAP Unit Redemption”).
|
•
|
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).
|
|
Year Ended December 31,
|
||||||
|
2016
|
|
2015
|
||||
Audit fees
(1)
|
$
|
5.3
|
|
|
$
|
4.6
|
|
Audit-related fees
(2)
|
1.0
|
|
|
0.1
|
|
||
Tax fees
(3)
|
1.4
|
|
|
1.5
|
|
||
Total
|
$
|
7.7
|
|
|
$
|
6.2
|
|
|
(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 our unitholders and international tax planning work associated with the structure of our Canadian investment.
|
|
PLAINS ALL AMERICAN PIPELINE, L.P.
|
|
|
|
|
|
By:
|
PAA GP LLC,
|
|
|
its general partner
|
|
|
|
|
By:
|
Plains AAP, L.P.,
|
|
|
its sole member
|
|
|
|
|
By:
|
PLAINS ALL AMERICAN GP LLC,
|
|
|
its general partner
|
|
|
|
|
By:
|
/s/ Greg L. Armstrong
|
|
|
Greg L. Armstrong,
|
|
|
Chief Executive Officer of Plains All American GP LLC
|
|
|
(Principal Executive Officer)
|
|
|
|
February 23, 2017
|
|
|
|
|
|
|
By:
|
/s/ Al Swanson
|
|
|
Al Swanson,
|
|
|
Executive Vice President and Chief Financial Officer of Plains All American GP LLC
|
|
|
(Principal Financial Officer)
|
|
|
|
February 23, 2017
|
|
|
|
|
|
|
By:
|
/s/ Chris Herbold
|
|
|
Chris Herbold,
|
|
|
Vice President —Accounting and Chief Accounting Officer of Plains All American GP LLC
|
|
|
(Principal Accounting Officer)
|
February 23, 2017
|
|
|
Name
|
|
Title
|
|
Date
|
|
|
|
|
|
/s/ Greg L. Armstrong
|
|
Chairman of the Board and Director of PAA GP Holdings LLC and Chief Executive Officer of Plains All American GP LLC (Principal Executive Officer)
|
|
February 23, 2017
|
Greg L. Armstrong
|
|
|
|
|
|
|
|
|
|
/s/ Harry N. Pefanis
|
|
Director of PAA GP Holdings LLC and President and Chief Operating Officer of Plains All American GP LLC
|
|
February 23, 2017
|
Harry N. Pefanis
|
|
|
|
|
|
|
|
|
|
/s/ Willie Chiang
|
|
Director of PAA GP Holdings LLC and Executive Vice President and Chief Operating Officer (U.S.) of Plains All American GP LLC
|
|
February 23, 2017
|
Willie Chiang
|
|
|
|
|
|
|
|
|
|
/s/ Al Swanson
|
|
Executive Vice President and Chief Financial Officer of Plains All American GP LLC (Principal Financial Officer)
|
|
February 23, 2017
|
Al Swanson
|
|
|
|
|
|
|
|
|
|
/s/ Chris Herbold
|
|
Vice President—Accounting and Chief Accounting Officer of Plains All American GP LLC (Principal Accounting Officer)
|
|
February 23, 2017
|
Chris Herbold
|
|
|
|
|
|
|
|
|
|
/s/ Victor Burk
|
|
Director of PAA GP Holdings LLC
|
|
February 23, 2017
|
Victor Burk
|
|
|
|
|
|
|
|
|
|
/s/ Bernard Figlock
|
|
Director of PAA GP Holdings LLC
|
|
February 23, 2017
|
Bernard Figlock
|
|
|
|
|
|
|
|
|
|
/s/ Everardo Goyanes
|
|
Director of PAA GP Holdings LLC
|
|
February 23, 2017
|
Everardo Goyanes
|
|
|
|
|
|
|
|
|
|
/s/ Gary R. Petersen
|
|
Director of PAA GP Holdings LLC
|
|
February 23, 2017
|
Gary R. Petersen
|
|
|
|
|
|
|
|
|
|
/s/ John T. Raymond
|
|
Director of PAA GP Holdings LLC
|
|
February 23, 2017
|
John T. Raymond
|
|
|
|
|
|
|
|
|
|
/s/ Bobby S. Shackouls
|
|
Director of PAA GP Holdings LLC
|
|
February 23, 2017
|
Bobby S. Shackouls
|
|
|
|
|
|
|
|
|
|
/s/ Robert V. Sinnott
|
|
Director of PAA GP Holdings LLC
|
|
February 23, 2017
|
Robert V. Sinnott
|
|
|
|
|
|
|
|
|
|
/s/ J. Taft Symonds
|
|
Director of PAA GP Holdings LLC
|
|
February 23, 2017
|
J. Taft Symonds
|
|
|
|
|
|
|
|
|
|
/s/ Christopher M. Temple
|
|
Director of PAA GP Holdings LLC
|
|
February 23, 2017
|
Christopher M. Temple
|
|
|
|
|
|
Page
|
Consolidated Financial Statements
|
|
|
/s/ Greg L. Armstrong
|
|
Greg L. Armstrong
|
|
Chief Executive Officer of Plains All American GP LLC
|
|
(Principal Executive Officer)
|
|
|
|
/s/ Al Swanson
|
|
Al Swanson
|
|
Executive Vice President and Chief Financial Officer of Plains All American GP LLC
|
|
(Principal Financial Officer)
|
|
|
February 23, 2017
|
|
/s/ PricewaterhouseCoopers LLP
|
Houston, Texas
|
February 23, 2017
|
|
Year Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
REVENUES
|
|
|
|
|
|
||||||
Supply and Logistics segment revenues
|
$
|
19,004
|
|
|
$
|
21,927
|
|
|
$
|
42,114
|
|
Transportation segment revenues
|
632
|
|
|
697
|
|
|
774
|
|
|||
Facilities segment revenues
|
546
|
|
|
528
|
|
|
576
|
|
|||
Total revenues
|
20,182
|
|
|
23,152
|
|
|
43,464
|
|
|||
|
|
|
|
|
|
||||||
COSTS AND EXPENSES
|
|
|
|
|
|
||||||
Purchases and related costs
|
17,233
|
|
|
19,726
|
|
|
39,500
|
|
|||
Field operating costs
|
1,182
|
|
|
1,454
|
|
|
1,456
|
|
|||
General and administrative expenses
|
279
|
|
|
278
|
|
|
325
|
|
|||
Depreciation and amortization
|
494
|
|
|
432
|
|
|
384
|
|
|||
Total costs and expenses
|
19,188
|
|
|
21,890
|
|
|
41,665
|
|
|||
|
|
|
|
|
|
||||||
OPERATING INCOME
|
994
|
|
|
1,262
|
|
|
1,799
|
|
|||
|
|
|
|
|
|
||||||
OTHER INCOME/(EXPENSE)
|
|
|
|
|
|
||||||
Equity earnings in unconsolidated entities
|
195
|
|
|
183
|
|
|
108
|
|
|||
Interest expense (net of capitalized interest of $47, $57 and $48, respectively)
|
(467
|
)
|
|
(432
|
)
|
|
(348
|
)
|
|||
Other income/(expense), net
|
33
|
|
|
(7
|
)
|
|
(2
|
)
|
|||
|
|
|
|
|
|
||||||
INCOME BEFORE TAX
|
755
|
|
|
1,006
|
|
|
1,557
|
|
|||
Current income tax expense
|
(85
|
)
|
|
(84
|
)
|
|
(71
|
)
|
|||
Deferred income tax benefit/(expense)
|
60
|
|
|
(16
|
)
|
|
(100
|
)
|
|||
|
|
|
|
|
|
||||||
NET INCOME
|
730
|
|
|
906
|
|
|
1,386
|
|
|||
Net income attributable to noncontrolling interests
|
(4
|
)
|
|
(3
|
)
|
|
(2
|
)
|
|||
NET INCOME ATTRIBUTABLE TO PAA
|
$
|
726
|
|
|
$
|
903
|
|
|
$
|
1,384
|
|
|
|
|
|
|
|
||||||
NET INCOME PER COMMON UNIT (NOTE 3):
|
|
|
|
|
|
||||||
Net income attributable to common unitholders - Basic
|
$
|
200
|
|
|
$
|
305
|
|
|
$
|
878
|
|
Basic weighted average common units outstanding
|
464
|
|
|
394
|
|
|
367
|
|
|||
Basic net income per common unit
|
$
|
0.43
|
|
|
$
|
0.78
|
|
|
$
|
2.39
|
|
|
|
|
|
|
|
||||||
Net income attributable to common unitholders - Diluted
|
$
|
200
|
|
|
$
|
305
|
|
|
$
|
878
|
|
Diluted weighted average common units outstanding
|
466
|
|
|
396
|
|
|
369
|
|
|||
Diluted net income per common unit
|
$
|
0.43
|
|
|
$
|
0.77
|
|
|
$
|
2.38
|
|
|
Year Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
Net income
|
$
|
730
|
|
|
$
|
906
|
|
|
$
|
1,386
|
|
Other comprehensive income/(loss)
|
72
|
|
|
(614
|
)
|
|
(370
|
)
|
|||
Comprehensive income
|
802
|
|
|
292
|
|
|
1,016
|
|
|||
Comprehensive income attributable to noncontrolling interests
|
(4
|
)
|
|
(3
|
)
|
|
(2
|
)
|
|||
Comprehensive income attributable to PAA
|
$
|
798
|
|
|
$
|
289
|
|
|
$
|
1,014
|
|
|
Derivative
Instruments
|
|
Translation
Adjustments
|
|
Other
|
|
Total
|
||||||||
Balance at December 31, 2013
|
$
|
(77
|
)
|
|
$
|
(20
|
)
|
|
$
|
—
|
|
|
$
|
(97
|
)
|
|
|
|
|
|
|
|
|
||||||||
Reclassification adjustments
|
4
|
|
|
—
|
|
|
—
|
|
|
4
|
|
||||
Deferred loss on cash flow hedges, net of tax
|
(86
|
)
|
|
—
|
|
|
—
|
|
|
(86
|
)
|
||||
Currency translation adjustments
|
—
|
|
|
(288
|
)
|
|
—
|
|
|
(288
|
)
|
||||
2014 Activity
|
(82
|
)
|
|
(288
|
)
|
|
—
|
|
|
(370
|
)
|
||||
Balance at December 31, 2014
|
$
|
(159
|
)
|
|
$
|
(308
|
)
|
|
$
|
—
|
|
|
$
|
(467
|
)
|
|
|
|
|
|
|
|
|
||||||||
Reclassification adjustments
|
(45
|
)
|
|
—
|
|
|
—
|
|
|
(45
|
)
|
||||
Deferred gain on cash flow hedges
|
1
|
|
|
—
|
|
|
—
|
|
|
1
|
|
||||
Currency translation adjustments
|
—
|
|
|
(570
|
)
|
|
—
|
|
|
(570
|
)
|
||||
2015 Activity
|
(44
|
)
|
|
(570
|
)
|
|
—
|
|
|
(614
|
)
|
||||
Balance at December 31, 2015
|
$
|
(203
|
)
|
|
$
|
(878
|
)
|
|
$
|
—
|
|
|
$
|
(1,081
|
)
|
|
|
|
|
|
|
|
|
||||||||
Reclassification adjustments
|
8
|
|
|
—
|
|
|
—
|
|
|
8
|
|
||||
Deferred loss on cash flow hedges
|
(33
|
)
|
|
—
|
|
|
—
|
|
|
(33
|
)
|
||||
Currency translation adjustments
|
—
|
|
|
96
|
|
|
—
|
|
|
96
|
|
||||
Other
|
—
|
|
|
—
|
|
|
1
|
|
|
1
|
|
||||
2016 Activity
|
(25
|
)
|
|
96
|
|
|
1
|
|
|
72
|
|
||||
Balance at December 31, 2016
|
$
|
(228
|
)
|
|
$
|
(782
|
)
|
|
$
|
1
|
|
|
$
|
(1,009
|
)
|
|
Year Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
CASH FLOWS FROM OPERATING ACTIVITIES
|
|
|
|
|
|
||||||
Net income
|
$
|
730
|
|
|
$
|
906
|
|
|
$
|
1,386
|
|
Reconciliation of net income to net cash provided by operating activities:
|
|
|
|
|
|
||||||
Depreciation and amortization
|
494
|
|
|
432
|
|
|
384
|
|
|||
Equity-indexed compensation expense
|
60
|
|
|
27
|
|
|
98
|
|
|||
Inventory valuation adjustments
|
3
|
|
|
117
|
|
|
289
|
|
|||
Deferred income tax (benefit)/expense
|
(60
|
)
|
|
16
|
|
|
100
|
|
|||
Settlement of terminated interest rate hedging instruments
|
(29
|
)
|
|
(48
|
)
|
|
(7
|
)
|
|||
Change in fair value of Preferred Distribution Rate Reset Option (Note 12)
|
(30
|
)
|
|
—
|
|
|
—
|
|
|||
Equity earnings in unconsolidated entities
|
(195
|
)
|
|
(183
|
)
|
|
(108
|
)
|
|||
Distributions from unconsolidated entities
|
216
|
|
|
214
|
|
|
105
|
|
|||
Other
|
23
|
|
|
(21
|
)
|
|
24
|
|
|||
Changes in assets and liabilities, net of acquisitions:
|
|
|
|
|
|
||||||
Trade accounts receivable and other
|
(524
|
)
|
|
803
|
|
|
1,177
|
|
|||
Inventory
|
(463
|
)
|
|
(90
|
)
|
|
(129
|
)
|
|||
Accounts payable and other current liabilities
|
501
|
|
|
(829
|
)
|
|
(1,315
|
)
|
|||
Net cash provided by operating activities
|
726
|
|
|
1,344
|
|
|
2,004
|
|
|||
|
|
|
|
|
|
||||||
CASH FLOWS FROM INVESTING ACTIVITIES
|
|
|
|
|
|
||||||
Cash paid in connection with acquisitions, net of cash acquired (Note 6)
|
(282
|
)
|
|
(105
|
)
|
|
(1,098
|
)
|
|||
Investments in unconsolidated entities (Note 8)
|
(301
|
)
|
|
(253
|
)
|
|
(158
|
)
|
|||
Additions to property, equipment and other
|
(1,334
|
)
|
|
(2,079
|
)
|
|
(1,932
|
)
|
|||
Cash paid for purchases of linefill and base gas
|
(7
|
)
|
|
(133
|
)
|
|
(161
|
)
|
|||
Proceeds from sales of assets
|
654
|
|
|
5
|
|
|
28
|
|
|||
Other investing activities
|
(3
|
)
|
|
35
|
|
|
25
|
|
|||
Net cash used in investing activities
|
(1,273
|
)
|
|
(2,530
|
)
|
|
(3,296
|
)
|
|||
|
|
|
|
|
|
||||||
CASH FLOWS FROM FINANCING ACTIVITIES
|
|
|
|
|
|
||||||
Net borrowings/(repayments) under commercial paper program (Note 10)
|
(564
|
)
|
|
631
|
|
|
(366
|
)
|
|||
Net borrowings under senior secured hedged inventory facility (Note 10)
|
447
|
|
|
300
|
|
|
—
|
|
|||
Repayment under AAP senior secured revolving credit facility (Note 10)
|
(92
|
)
|
|
—
|
|
|
—
|
|
|||
Repayment of AAP term loan (Note 10)
|
(550
|
)
|
|
—
|
|
|
—
|
|
|||
Proceeds from the issuance of senior notes (Note 10)
|
748
|
|
|
998
|
|
|
2,595
|
|
|||
Repayments of senior notes (Note 10)
|
(175
|
)
|
|
(549
|
)
|
|
—
|
|
|||
Net proceeds from the sale of Series A preferred units (Note 11)
|
1,569
|
|
|
—
|
|
|
—
|
|
|||
Net proceeds from the sale of common units (Note 11)
|
796
|
|
|
1,099
|
|
|
848
|
|
|||
Contributions from general partner
|
42
|
|
|
23
|
|
|
18
|
|
|||
Distributions paid to common unitholders (Note 11)
|
(1,062
|
)
|
|
(1,081
|
)
|
|
(934
|
)
|
|||
Distributions paid to general partner (Note 11)
|
(565
|
)
|
|
(590
|
)
|
|
(473
|
)
|
|||
Other financing activities
|
(31
|
)
|
|
(17
|
)
|
|
(31
|
)
|
|||
Net cash provided by financing activities
|
563
|
|
|
814
|
|
|
1,657
|
|
|||
|
|
|
|
|
|
||||||
Effect of translation adjustment on cash
|
4
|
|
|
(4
|
)
|
|
(3
|
)
|
|||
|
|
|
|
|
|
||||||
Net increase/(decrease) in cash and cash equivalents
|
20
|
|
|
(376
|
)
|
|
362
|
|
|||
Cash and cash equivalents, beginning of period
|
27
|
|
|
403
|
|
|
41
|
|
|||
Cash and cash equivalents, end of period
|
$
|
47
|
|
|
$
|
27
|
|
|
$
|
403
|
|
|
|
|
|
|
|
||||||
Cash paid for:
|
|
|
|
|
|
||||||
Interest, net of amounts capitalized
|
$
|
450
|
|
|
$
|
396
|
|
|
$
|
334
|
|
Income taxes, net of amounts refunded
|
$
|
98
|
|
|
$
|
50
|
|
|
$
|
159
|
|
|
Limited Partners
|
|
General
Partner
|
|
Partners’ Capital Excluding Noncontrolling Interests
|
|
Noncontrolling
Interests
|
|
Total
Partners’
Capital
|
||||||||||||||
|
Series A Preferred Uniholders
|
|
Common Unitholders
|
|
|
|
|
||||||||||||||||
Balance at December 31, 2013
|
$
|
—
|
|
|
$
|
7,349
|
|
|
$
|
295
|
|
|
$
|
7,644
|
|
|
$
|
59
|
|
|
$
|
7,703
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Net income
|
—
|
|
|
884
|
|
|
500
|
|
|
1,384
|
|
|
2
|
|
|
1,386
|
|
||||||
Cash distributions to partners
|
—
|
|
|
(934
|
)
|
|
(473
|
)
|
|
(1,407
|
)
|
|
(3
|
)
|
|
(1,410
|
)
|
||||||
Sale of common units
|
—
|
|
|
848
|
|
|
18
|
|
|
866
|
|
|
—
|
|
|
866
|
|
||||||
Other comprehensive loss
|
—
|
|
|
(362
|
)
|
|
(8
|
)
|
|
(370
|
)
|
|
—
|
|
|
(370
|
)
|
||||||
Other
|
—
|
|
|
8
|
|
|
8
|
|
|
16
|
|
|
—
|
|
|
16
|
|
||||||
Balance at December 31, 2014
|
$
|
—
|
|
|
$
|
7,793
|
|
|
$
|
340
|
|
|
$
|
8,133
|
|
|
$
|
58
|
|
|
$
|
8,191
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Net income
|
—
|
|
|
314
|
|
|
589
|
|
|
903
|
|
|
3
|
|
|
906
|
|
||||||
Cash distributions to partners
|
—
|
|
|
(1,081
|
)
|
|
(590
|
)
|
|
(1,671
|
)
|
|
(3
|
)
|
|
(1,674
|
)
|
||||||
Sale of common units
|
—
|
|
|
1,099
|
|
|
22
|
|
|
1,121
|
|
|
—
|
|
|
1,121
|
|
||||||
Other comprehensive loss
|
—
|
|
|
(602
|
)
|
|
(12
|
)
|
|
(614
|
)
|
|
—
|
|
|
(614
|
)
|
||||||
Other
|
—
|
|
|
57
|
|
|
(48
|
)
|
|
9
|
|
|
—
|
|
|
9
|
|
||||||
Balance at December 31, 2015
|
$
|
—
|
|
|
$
|
7,580
|
|
|
$
|
301
|
|
|
$
|
7,881
|
|
|
$
|
58
|
|
|
$
|
7,939
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Net income
|
—
|
|
|
333
|
|
|
393
|
|
|
726
|
|
|
4
|
|
|
730
|
|
||||||
Cash distributions to partners
|
—
|
|
|
(1,062
|
)
|
|
(565
|
)
|
|
(1,627
|
)
|
|
(4
|
)
|
|
(1,631
|
)
|
||||||
Sale of Series A preferred units
|
1,509
|
|
|
—
|
|
|
33
|
|
|
1,542
|
|
|
—
|
|
|
1,542
|
|
||||||
Sale of common units
|
—
|
|
|
796
|
|
|
9
|
|
|
805
|
|
|
—
|
|
|
805
|
|
||||||
Other comprehensive income
|
—
|
|
|
72
|
|
|
—
|
|
|
72
|
|
|
—
|
|
|
72
|
|
||||||
Simplification Transactions (Note 1)
|
—
|
|
|
(471
|
)
|
|
(171
|
)
|
|
(642
|
)
|
|
—
|
|
|
(642
|
)
|
||||||
Other
|
(1
|
)
|
|
3
|
|
|
—
|
|
|
2
|
|
|
(1
|
)
|
|
1
|
|
||||||
Balance at December 31, 2016
|
$
|
1,508
|
|
|
$
|
7,251
|
|
|
$
|
—
|
|
|
$
|
8,759
|
|
|
$
|
57
|
|
|
$
|
8,816
|
|
•
|
the permanent elimination of our incentive distribution rights (“IDRs”) and the economic rights associated with our
2%
general partner interest in exchange for the issuance by us 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 us 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 PAGP GP assumed oversight responsibility over both us and PAGP;
|
•
|
the provision for annual PAGP shareholder elections beginning in 2018 with certain directors with expiring terms in 2018, and the participation of our common unitholders and Series A preferred unitholders in such elections through our ownership of newly issued Class C shares in PAGP, which provide us, 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 Class A units (“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 our 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, resulted in economic alignment between our 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
|
•
|
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 our common units held by AAP.
|
AOCI
|
=
|
Accumulated other comprehensive income/(loss)
|
Bcf
|
=
|
Billion cubic feet
|
Btu
|
=
|
British thermal unit
|
CAD
|
=
|
Canadian dollar
|
DERs
|
=
|
Distribution equivalent rights
|
EBITDA
|
=
|
Earnings before interest, taxes, depreciation and amortization
|
EPA
|
=
|
United States Environmental Protection Agency
|
FASB
|
=
|
Financial Accounting Standards Board
|
GAAP
|
=
|
Generally accepted accounting principles in the United States
|
ICE
|
=
|
Intercontinental Exchange
|
IPO
|
=
|
Initial public offering
|
LTIP
|
=
|
Long-term incentive plan
|
Mcf
|
=
|
Thousand cubic feet
|
MLP
|
=
|
Master limited partnership
|
NGL
|
=
|
Natural gas liquids, including ethane, propane and butane
|
NYMEX
|
=
|
New York Mercantile Exchange
|
Oxy
|
=
|
Occidental Petroleum Corporation or its subsidiaries
|
PLA
|
=
|
Pipeline loss allowance
|
USD
|
=
|
United States dollar
|
WTI
|
=
|
West Texas Intermediate
|
|
Year Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
Basic Net Income per Common Unit
|
|
|
|
|
|
||||||
Net income attributable to PAA
|
$
|
726
|
|
|
$
|
903
|
|
|
$
|
1,384
|
|
Distributions to Series A preferred units
(1)
|
(122
|
)
|
|
—
|
|
|
—
|
|
|||
Distributions to general partner
(1)
|
(412
|
)
|
|
(608
|
)
|
|
(502
|
)
|
|||
Distributions to participating securities
(1)
|
(4
|
)
|
|
(6
|
)
|
|
(6
|
)
|
|||
Undistributed loss allocated to general partner
(1)
|
14
|
|
|
16
|
|
|
2
|
|
|||
Other
|
(2
|
)
|
|
—
|
|
|
—
|
|
|||
Net income allocated to common unitholders in accordance with application of the two-class method
|
$
|
200
|
|
|
$
|
305
|
|
|
$
|
878
|
|
|
|
|
|
|
|
||||||
Basic weighted average common units outstanding
(2)
|
464
|
|
|
394
|
|
|
367
|
|
|||
|
|
|
|
|
|
||||||
Basic net income per common unit
|
$
|
0.43
|
|
|
$
|
0.78
|
|
|
$
|
2.39
|
|
|
|
|
|
|
|
||||||
Diluted Net Income per Common Unit
|
|
|
|
|
|
||||||
Net income attributable to PAA
|
$
|
726
|
|
|
$
|
903
|
|
|
$
|
1,384
|
|
Distributions to Series A preferred units
(1)
|
(122
|
)
|
|
—
|
|
|
—
|
|
|||
Distributions to general partner
(1)
|
(412
|
)
|
|
(608
|
)
|
|
(502
|
)
|
|||
Distributions to participating securities
(1)
|
(4
|
)
|
|
(6
|
)
|
|
(6
|
)
|
|||
Undistributed loss allocated to general partner
(1)
|
14
|
|
|
16
|
|
|
2
|
|
|||
Other
|
(2
|
)
|
|
—
|
|
|
—
|
|
|||
Net income allocated to common unitholders in accordance with application of the two-class method
|
$
|
200
|
|
|
$
|
305
|
|
|
$
|
878
|
|
|
|
|
|
|
|
||||||
Basic weighted average common units outstanding
(2)
|
464
|
|
|
394
|
|
|
367
|
|
|||
Effect of dilutive securities: Weighted average LTIP units
|
2
|
|
|
2
|
|
|
2
|
|
|||
Diluted weighted average common units outstanding
|
466
|
|
|
396
|
|
|
369
|
|
|||
|
|
|
|
|
|
||||||
Diluted net income per common unit
|
$
|
0.43
|
|
|
$
|
0.77
|
|
|
$
|
2.38
|
|
|
(1)
|
We calculate net income allocated to common unitholders based on the distributions pertaining to the current period’s net income. After adjusting for the appropriate period’s distributions, the remaining undistributed earnings or excess distributions over earnings (“undistributed loss”), if any, are allocated to the general partner, common unitholders and participating securities in accordance with the contractual terms of our partnership agreement in effect for the period and as further prescribed under the two-class method.
|
(2)
|
We have considered the common units issued in connection with the Simplification Transactions to be outstanding for the entire fourth quarter of 2016 in the calculation of weighted average common units outstanding to more closely reflect the ownership interests in us with rights to the distributions for the periods included in the calculation of net income allocated to common unitholders.
|
|
December 31, 2016
|
|
December 31, 2015
|
||||||||||||||||||||||
|
Volumes
|
|
Unit of
Measure
|
|
Carrying
Value
|
|
Price/
Unit
(1)
|
|
Volumes
|
|
Unit of
Measure
|
|
Carrying
Value
|
|
Price/
Unit
(1)
|
||||||||||
Inventory
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Crude oil
|
23,589
|
|
|
barrels
|
|
$
|
1,049
|
|
|
$
|
44.47
|
|
|
16,345
|
|
|
barrels
|
|
$
|
608
|
|
|
$
|
37.20
|
|
NGL
|
13,497
|
|
|
barrels
|
|
242
|
|
|
$
|
17.93
|
|
|
13,907
|
|
|
barrels
|
|
218
|
|
|
$
|
15.68
|
|
||
Natural gas
|
14,540
|
|
|
Mcf
|
|
32
|
|
|
$
|
2.20
|
|
|
22,080
|
|
|
Mcf
|
|
53
|
|
|
$
|
2.40
|
|
||
Other
|
N/A
|
|
|
|
|
20
|
|
|
N/A
|
|
|
N/A
|
|
|
|
|
37
|
|
|
N/A
|
|
||||
Inventory subtotal
|
|
|
|
|
1,343
|
|
|
|
|
|
|
|
|
916
|
|
|
|
||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Linefill and base gas
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Crude oil
|
12,273
|
|
|
barrels
|
|
710
|
|
|
$
|
57.85
|
|
|
12,298
|
|
|
barrels
|
|
713
|
|
|
$
|
57.98
|
|
||
NGL
|
1,660
|
|
|
barrels
|
|
45
|
|
|
$
|
27.11
|
|
|
1,348
|
|
|
barrels
|
|
44
|
|
|
$
|
32.64
|
|
||
Natural gas
|
30,812
|
|
|
Mcf
|
|
141
|
|
|
$
|
4.58
|
|
|
30,812
|
|
|
Mcf
|
|
141
|
|
|
$
|
4.58
|
|
||
Linefill and base gas subtotal
|
|
|
|
|
896
|
|
|
|
|
|
|
|
|
898
|
|
|
|
||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Long-term inventory
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Crude oil
|
3,279
|
|
|
barrels
|
|
163
|
|
|
$
|
49.71
|
|
|
3,417
|
|
|
barrels
|
|
106
|
|
|
$
|
31.02
|
|
||
NGL
|
1,418
|
|
|
barrels
|
|
30
|
|
|
$
|
21.16
|
|
|
1,652
|
|
|
barrels
|
|
23
|
|
|
$
|
13.92
|
|
||
Long-term inventory subtotal
|
|
|
|
|
193
|
|
|
|
|
|
|
|
|
129
|
|
|
|
||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Total
|
|
|
|
|
$
|
2,432
|
|
|
|
|
|
|
|
|
$
|
1,943
|
|
|
|
|
(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.
|
|
Estimated Useful
Lives (Years)
|
|
December 31,
|
||||||
|
|
2016
|
|
2015
|
|||||
Pipelines and related facilities
(1)
|
10 - 70
|
|
$
|
9,025
|
|
|
$
|
8,395
|
|
Storage, terminal and rail facilities
|
30 - 70
|
|
5,305
|
|
|
5,012
|
|
||
Trucking equipment and other
|
3 - 15
|
|
408
|
|
|
392
|
|
||
Construction in progress
|
—
|
|
826
|
|
|
1,217
|
|
||
Office property and equipment
|
2 - 50
|
|
222
|
|
|
196
|
|
||
Land and other
|
N/A
|
|
434
|
|
|
442
|
|
||
Property and equipment, gross
|
|
|
16,220
|
|
|
15,654
|
|
||
Accumulated depreciation
|
|
|
(2,348
|
)
|
|
(2,180
|
)
|
||
Property and equipment, net
|
|
|
$
|
13,872
|
|
|
$
|
13,474
|
|
|
(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.
|
|
Transportation
|
|
Facilities
|
|
Supply and Logistics
|
|
Total
|
||||||||
Balance at December 31, 2014
|
$
|
854
|
|
|
$
|
1,152
|
|
|
$
|
459
|
|
|
$
|
2,465
|
|
Acquisitions
|
3
|
|
|
8
|
|
|
—
|
|
|
11
|
|
||||
Foreign currency translation adjustments
|
(42
|
)
|
|
(19
|
)
|
|
(10
|
)
|
|
(71
|
)
|
||||
Other
|
—
|
|
|
(54
|
)
|
|
54
|
|
|
—
|
|
||||
Balance at December 31, 2015
|
$
|
815
|
|
|
$
|
1,087
|
|
|
$
|
503
|
|
|
$
|
2,405
|
|
Foreign currency translation adjustments
|
6
|
|
|
3
|
|
|
1
|
|
|
10
|
|
||||
Dispositions and reclassifications to assets held for sale
|
(15
|
)
|
|
(56
|
)
|
|
—
|
|
|
(71
|
)
|
||||
Balance at December 31, 2016
|
$
|
806
|
|
|
$
|
1,034
|
|
|
$
|
504
|
|
|
$
|
2,344
|
|
|
|
|
|
Ownership
Interest at December 31,
2016
|
|
December 31,
|
||||||
Entity
|
|
Type of Operation
|
|
|
2016
|
|
2015
|
|||||
BridgeTex Pipeline Company, LLC (“BridgeTex”)
|
|
Crude Oil Pipeline
|
|
50%
|
|
$
|
1,098
|
|
|
$
|
1,082
|
|
Butte Pipe Line Company
|
|
Crude Oil Pipeline
|
|
22%
|
|
11
|
|
|
9
|
|
||
Caddo Pipeline LLC
|
|
Crude Oil Pipeline
|
|
50%
|
|
65
|
|
|
28
|
|
||
Cheyenne Pipeline LLC (“Cheyenne”)
|
|
Crude Oil Pipeline
|
|
50%
|
|
30
|
|
|
—
|
|
||
Diamond Pipeline LLC (“Diamond”)
|
|
Crude Oil Pipeline
(1)
|
|
50%
|
|
143
|
|
|
38
|
|
||
Eagle Ford Pipeline LLC
|
|
Crude Oil Pipeline
|
|
50%
|
|
372
|
|
|
382
|
|
||
Eagle Ford Terminals Corpus Christi LLC (“Eagle Ford Terminals”)
|
|
Crude Oil Terminal and Dock
(1)
|
|
50%
|
|
53
|
|
|
29
|
|
||
Frontier Aspen LLC
|
|
Crude Oil Pipeline
|
|
50%
|
|
45
|
|
|
48
|
|
||
Saddlehorn Pipeline Company, LLC
|
|
Crude Oil Pipeline
|
|
40%
|
|
213
|
|
|
103
|
|
||
Settoon, Towing LLC
|
|
Barge Transportation Services
|
|
50%
|
|
87
|
|
|
84
|
|
||
STACK Pipeline LLC (“STACK”)
|
|
Crude Oil Pipeline
|
|
50%
|
|
14
|
|
|
—
|
|
||
White Cliffs Pipeline, LLC
|
|
Crude Oil Pipeline
|
|
36%
|
|
212
|
|
|
224
|
|
||
Total Investments in Unconsolidated Entities
|
|
|
|
|
|
$
|
2,343
|
|
|
$
|
2,027
|
|
|
(1)
|
Asset is currently under construction by the entity and has not yet been placed in service.
|
|
December 31,
|
||||||
|
2016
|
|
2015
|
||||
Current assets
|
$
|
303
|
|
|
$
|
365
|
|
Noncurrent assets
|
$
|
3,558
|
|
|
$
|
2,901
|
|
Current liabilities
|
$
|
241
|
|
|
$
|
231
|
|
Noncurrent liabilities
|
$
|
162
|
|
|
$
|
184
|
|
|
December 31,
|
||||||
|
2016
|
|
2015
|
||||
Intangible assets
(1)
|
$
|
603
|
|
|
$
|
610
|
|
Fair value of derivative instruments
|
1
|
|
|
9
|
|
||
Other
|
47
|
|
|
94
|
|
||
|
651
|
|
|
713
|
|
||
Accumulated amortization
|
(361
|
)
|
|
(327
|
)
|
||
|
$
|
290
|
|
|
$
|
386
|
|
|
(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.
|
|
|
|
December 31, 2016
|
|
December 31, 2015
|
||||||||||||||||||||
|
Estimated Useful
Lives (Years)
|
|
Cost
|
|
Accumulated
Amortization
|
|
Net
|
|
Cost
|
|
Accumulated
Amortization
|
|
Net
|
||||||||||||
Customer contracts and relationships
|
1 – 20
|
|
$
|
529
|
|
|
$
|
(330
|
)
|
|
$
|
199
|
|
|
$
|
537
|
|
|
$
|
(301
|
)
|
|
$
|
236
|
|
Property tax abatement
|
7 – 13
|
|
38
|
|
|
(26
|
)
|
|
12
|
|
|
38
|
|
|
(22
|
)
|
|
16
|
|
||||||
Other agreements
|
25 – 70
|
|
29
|
|
|
(5
|
)
|
|
24
|
|
|
28
|
|
|
(4
|
)
|
|
24
|
|
||||||
Emission reduction credits
(1)
|
N/A
|
|
7
|
|
|
—
|
|
|
7
|
|
|
7
|
|
|
—
|
|
|
7
|
|
||||||
|
|
|
$
|
603
|
|
|
$
|
(361
|
)
|
|
$
|
242
|
|
|
$
|
610
|
|
|
$
|
(327
|
)
|
|
$
|
283
|
|
|
(1)
|
Emission reduction credits, once surrendered in exchange for environmental permits, are finite-lived.
|
2017
|
$
|
42
|
|
2018
|
$
|
37
|
|
2019
|
$
|
34
|
|
2020
|
$
|
32
|
|
2021
|
$
|
30
|
|
|
December 31,
2016 |
|
December 31,
2015 |
||||
SHORT-TERM DEBT
|
|
|
|
||||
Commercial paper notes, bearing a weighted-average interest rate of 1.6% and 1.1%, respectively
(1)
|
$
|
563
|
|
|
$
|
696
|
|
Senior secured hedged inventory facility, bearing a weighted-average interest rate of 1.8% and 1.4%, respectively
(1)
|
750
|
|
|
300
|
|
||
Senior notes:
|
|
|
|
||||
6.13% senior notes due January 2017
|
400
|
|
|
—
|
|
||
Other
|
2
|
|
|
3
|
|
||
Total short-term debt
(2)
|
1,715
|
|
|
999
|
|
||
|
|
|
|
||||
LONG-TERM DEBT
|
|
|
|
||||
Senior notes:
|
|
|
|
||||
5.88% senior notes due August 2016
(3)
|
—
|
|
|
175
|
|
||
6.13% senior notes due January 2017
|
—
|
|
|
400
|
|
||
6.50% senior notes due May 2018
|
600
|
|
|
600
|
|
||
8.75% senior notes due May 2019
|
350
|
|
|
350
|
|
||
2.60% senior notes due December 2019
|
500
|
|
|
500
|
|
||
5.75% senior notes due January 2020
|
500
|
|
|
500
|
|
||
5.00% senior notes due February 2021
|
600
|
|
|
600
|
|
||
3.65% senior notes due June 2022
|
750
|
|
|
750
|
|
||
2.85% senior notes due January 2023
|
400
|
|
|
400
|
|
||
3.85% senior notes due October 2023
|
700
|
|
|
700
|
|
||
3.60% senior notes due November 2024
|
750
|
|
|
750
|
|
||
4.65% senior notes due October 2025
|
1,000
|
|
|
1,000
|
|
||
4.50% senior notes due December 2026
|
750
|
|
|
—
|
|
||
6.70% senior notes due May 2036
|
250
|
|
|
250
|
|
||
6.65% senior notes due January 2037
|
600
|
|
|
600
|
|
||
5.15% senior notes due June 2042
|
500
|
|
|
500
|
|
||
4.30% senior notes due January 2043
|
350
|
|
|
350
|
|
||
4.70% senior notes due June 2044
|
700
|
|
|
700
|
|
||
4.90% senior notes due February 2045
|
650
|
|
|
650
|
|
||
Unamortized discounts and debt issuance costs
|
(76
|
)
|
|
(77
|
)
|
||
Senior notes, net of unamortized discounts and debt issuance costs
|
9,874
|
|
|
9,698
|
|
||
Commercial paper notes, bearing a weighted-average interest rate of 1.6% and 1.1%, respectively
(3)
|
247
|
|
|
672
|
|
||
Other
|
3
|
|
|
5
|
|
||
Total long-term debt
|
10,124
|
|
|
10,375
|
|
||
Total debt
(4)
|
$
|
11,839
|
|
|
$
|
11,374
|
|
|
(1)
|
We classified these 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.
|
(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 our
$175 million
,
5.88%
senior notes due August 2016 as long-term based on our ability and intent to refinance such amounts on a long-term basis under our credit facilities.
|
(4)
|
Our 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. Our 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 our credit facilities and commercial paper program approximates fair value as interest rates reflect current market rates. The fair value estimates for our senior notes, credit facilities and commercial paper program are based upon observable market data and are classified in Level 2 of the fair value hierarchy.
|
Year
|
|
Description
|
|
Maturity
|
|
Face Value
|
|
Interest Payment Dates
|
||
2016
|
|
4.50% Senior Notes issued at 99.716% of face value
|
|
December 2026
|
|
$
|
750
|
|
|
June 15 and December 15
|
|
|
|
|
|
|
|
|
|
||
2015
|
|
4.65% Senior Notes issued at 99.846% of face value
|
|
October 2025
|
|
$
|
1,000
|
|
|
April 15 and October 15
|
|
|
|
|
|
|
|
|
|
||
2014
|
|
2.60% Senior Notes issued at 99.813% of face value
|
|
December 2019
|
|
$
|
500
|
|
|
June 15 and December 15
|
2014
|
|
4.90% Senior Notes issued at 99.876% of face value
|
|
February 2045
|
|
$
|
650
|
|
|
February 15 and August 15
|
2014
|
|
3.60% Senior Notes issued at 99.842% of face value
|
|
November 2024
|
|
$
|
750
|
|
|
May 1 and November 1
|
2014
|
|
4.70% Senior Notes issued at 99.734% of face value
|
|
June 2044
|
|
$
|
700
|
|
|
June 15 and December 15
|
Calendar Year
|
|
Payment
(in millions)
|
||
2017
|
|
$
|
247
|
|
2018
|
|
600
|
|
|
2019
|
|
850
|
|
|
2020
|
|
500
|
|
|
2021
|
|
600
|
|
|
Thereafter
|
|
7,403
|
|
•
|
grant liens on certain property;
|
•
|
incur indebtedness, including capital leases;
|
•
|
sell substantially all of our assets or enter into a merger or consolidation;
|
•
|
engage in certain transactions with affiliates; and
|
•
|
enter into certain burdensome agreements.
|
|
Limited Partners
|
||||
|
Preferred Units
|
|
Common Units
|
||
Outstanding at December 31, 2013
|
—
|
|
|
359,133,200
|
|
|
|
|
|
||
Sale of common units
|
—
|
|
|
15,375,810
|
|
Issuance of common units under LTIP
|
—
|
|
|
598,783
|
|
Outstanding at December 31, 2014
|
—
|
|
|
375,107,793
|
|
|
|
|
|
||
Sale of common units
|
—
|
|
|
22,133,904
|
|
Issuance of common units under LTIP
|
—
|
|
|
485,927
|
|
Outstanding at December 31, 2015
|
—
|
|
|
397,727,624
|
|
|
|
|
|
||
Sale of Series A preferred units
|
61,030,127
|
|
|
—
|
|
Issuance of Series A preferred units in connection with in-kind distributions
|
3,358,726
|
|
|
—
|
|
Sale of common units
|
—
|
|
|
26,278,288
|
|
Issuance of common units under LTIP
|
—
|
|
|
480,581
|
|
Issuance of common units in connection with Simplification Transactions
|
—
|
|
|
244,707,926
|
|
Outstanding at December 31, 2016
|
64,388,853
|
|
|
669,194,419
|
|
|
|
Distributions Paid
|
|
|
Distributions per
common unit
|
||||||||||||
Year
|
|
Common Unitholders
|
|
General Partner
(1)
|
|
Total
|
|
|
|||||||||
2016
|
|
$
|
1,062
|
|
|
$
|
565
|
|
|
$
|
1,627
|
|
|
|
$
|
2.65
|
|
2015
|
|
$
|
1,081
|
|
|
$
|
590
|
|
|
$
|
1,671
|
|
|
|
$
|
2.76
|
|
2014
|
|
$
|
934
|
|
|
$
|
473
|
|
|
$
|
1,407
|
|
|
|
$
|
2.55
|
|
|
(1)
|
During the years ended
December 31, 2016
,
2015
and
2014
, our general partner’s incentive distributions were reduced by approximately
$18 million
,
$22 million
and
$23 million
, respectively, which were agreed to in connection with certain acquisitions.
|
Year
|
|
Type of Offering
|
|
Units Issued
|
|
Net Proceeds
(1) (2)
|
|
|||
2016 Total
|
|
Continuous Offering Program
|
|
26,278,288
|
|
|
$
|
805
|
|
(3)
|
|
|
|
|
|
|
|
|
|||
2015
|
|
Continuous Offering Program
|
|
1,133,904
|
|
|
$
|
59
|
|
(3)
|
2015
|
|
Underwritten Offering
|
|
21,000,000
|
|
|
1,062
|
|
|
|
2015 Total
|
|
|
|
22,133,904
|
|
|
$
|
1,121
|
|
|
|
|
|
|
|
|
|
|
|||
2014 Total
|
|
Continuous Offering Program
|
|
15,375,810
|
|
|
$
|
866
|
|
(3)
|
|
(1)
|
Amounts are net of costs associated with the offerings.
|
(2)
|
For periods prior to the closing of the Simplification Transactions, amounts include our general partner’s proportionate capital contributions of
$9 million
,
$22 million
and
$18 million
during
2016
,
2015
and
2014
, respectively.
|
(3)
|
We pay commissions to our sales agents in connection with common unit issuances under our Continuous Offering Program. We paid
$8 million
,
$1 million
and
$9 million
of such commissions during
2016
,
2015
and
2014
, respectively.
|
•
|
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.
|
Hedged Transaction
|
|
Number and Types of
Derivatives Employed
|
|
Notional
Amount
|
|
Expected
Termination Date
|
|
Average Rate Locked
|
|
Accounting
Treatment
|
|||
Anticipated interest payments
|
|
8 forward starting swaps (30-year)
|
|
$
|
200
|
|
|
6/15/2017
|
|
3.14
|
%
|
|
Cash flow hedge
|
Anticipated interest payments
|
|
8 forward starting swaps (30-year)
|
|
$
|
200
|
|
|
6/15/2018
|
|
3.20
|
%
|
|
Cash flow hedge
|
Anticipated interest payments
|
|
8 forward starting swaps (30-year)
|
|
$
|
200
|
|
|
6/14/2019
|
|
2.83
|
%
|
|
Cash flow hedge
|
|
|
|
USD
|
|
CAD
|
|
Average Exchange Rate
USD to CAD
|
||||
Forward exchange contracts that exchange CAD for USD:
|
|
|
|
|
|
|
|
||||
|
2017
|
|
$
|
274
|
|
|
$
|
363
|
|
|
$1.00 - $1.33
|
|
|
|
|
|
|
|
|
||||
Forward exchange contracts that exchange USD for CAD:
|
|
|
|
|
|
|
|
||||
|
2017
|
|
$
|
492
|
|
|
$
|
652
|
|
|
$1.00 - $1.33
|
|
|
Year Ended December 31, 2016
|
|||||||||||
Location of Gain/(Loss)
|
|
Derivatives in
Hedging
Relationships
(1) (2)
|
|
Derivatives
Not Designated
as a Hedge
|
|
|
Total
|
||||||
Commodity Derivatives
|
|
|
|
|
|
|
|
||||||
|
|
|
|
|
|
|
|
||||||
Supply and Logistics segment revenues
|
|
$
|
2
|
|
|
$
|
(344
|
)
|
|
|
$
|
(342
|
)
|
|
|
|
|
|
|
|
|
||||||
Transportation segment revenues
|
|
—
|
|
|
5
|
|
|
|
5
|
|
|||
|
|
|
|
|
|
|
|
||||||
Interest Rate Derivatives
|
|
|
|
|
|
|
|
||||||
|
|
|
|
|
|
|
|
||||||
Interest expense, net
|
|
(14
|
)
|
|
—
|
|
|
|
(14
|
)
|
|||
|
|
|
|
|
|
|
|
||||||
Foreign Currency Derivatives
|
|
|
|
|
|
|
|
||||||
|
|
|
|
|
|
|
|
||||||
Supply and Logistics segment revenues
|
|
—
|
|
|
(3
|
)
|
|
|
(3
|
)
|
|||
|
|
|
|
|
|
|
|
||||||
Preferred Distribution Rate Reset Option
|
|
|
|
|
|
|
|
||||||
|
|
|
|
|
|
|
|
||||||
Other income/(expense), net
|
|
—
|
|
|
30
|
|
|
|
30
|
|
|||
|
|
|
|
|
|
|
|
||||||
Total Gain/(Loss) on Derivatives Recognized in Net Income
|
|
$
|
(12
|
)
|
|
$
|
(312
|
)
|
|
|
$
|
(324
|
)
|
|
|
Year Ended December 31, 2015
|
|||||||||||
Location of Gain/(Loss)
|
|
Derivatives in
Hedging
Relationships
(1) (2)
|
|
Derivatives
Not Designated
as a Hedge
|
|
|
Total
|
||||||
Commodity Derivatives
|
|
|
|
|
|
|
|
||||||
|
|
|
|
|
|
|
|
||||||
Supply and Logistics segment revenues
|
|
$
|
56
|
|
|
$
|
152
|
|
|
|
$
|
208
|
|
|
|
|
|
|
|
|
|
||||||
Transportation segment revenues
|
|
—
|
|
|
8
|
|
|
|
8
|
|
|||
|
|
|
|
|
|
|
|
||||||
Field operating costs
|
|
—
|
|
|
(18
|
)
|
|
|
(18
|
)
|
|||
|
|
|
|
|
|
|
|
||||||
Interest Rate Derivatives
|
|
|
|
|
|
|
|
||||||
|
|
|
|
|
|
|
|
||||||
Interest expense, net
|
|
(11
|
)
|
|
—
|
|
|
|
(11
|
)
|
|||
|
|
|
|
|
|
|
|
||||||
Foreign Currency Derivatives
|
|
|
|
|
|
|
|
||||||
|
|
|
|
|
|
|
|
||||||
Supply and Logistics segment revenues
|
|
—
|
|
|
(31
|
)
|
|
|
(31
|
)
|
|||
|
|
|
|
|
|
|
|
||||||
Total Gain/(Loss) on Derivatives Recognized in Net Income
|
|
$
|
45
|
|
|
$
|
111
|
|
|
|
$
|
156
|
|
|
|
Year Ended December 31, 2014
|
|||||||||||
Location of Gain/(Loss)
|
|
Derivatives in
Hedging
Relationships
(1) (2)
|
|
Derivatives
Not Designated
as a Hedge
|
|
|
Total
|
||||||
Commodity Derivatives
|
|
|
|
|
|
|
|
||||||
|
|
|
|
|
|
|
|
||||||
Supply and Logistics segment revenues
|
|
$
|
(1
|
)
|
|
$
|
206
|
|
|
|
$
|
205
|
|
|
|
|
|
|
|
|
|
||||||
Field operating costs
|
|
—
|
|
|
(21
|
)
|
|
|
(21
|
)
|
|||
|
|
|
|
|
|
|
|
||||||
Interest Rate Derivatives
|
|
|
|
|
|
|
|
||||||
|
|
|
|
|
|
|
|
||||||
Interest expense, net
|
|
(5
|
)
|
|
—
|
|
|
|
(5
|
)
|
|||
|
|
|
|
|
|
|
|
||||||
Foreign Currency Derivatives
|
|
|
|
|
|
|
|
||||||
|
|
|
|
|
|
|
|
||||||
Supply and Logistics segment revenues
|
|
—
|
|
|
(28
|
)
|
|
|
(28
|
)
|
|||
|
|
|
|
|
|
|
|
||||||
Other income/(expense), net
|
|
2
|
|
|
—
|
|
|
|
2
|
|
|||
|
|
|
|
|
|
|
|
||||||
Total Gain/(Loss) on Derivatives Recognized in Net Income
|
|
$
|
(4
|
)
|
|
$
|
157
|
|
|
|
$
|
153
|
|
|
(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.
|
|
Asset Derivatives
|
|
|
Liability Derivatives
|
||||||||
|
Balance Sheet
Location
|
|
Fair
Value
|
|
|
Balance Sheet
Location
|
|
Fair
Value
|
||||
Derivatives designated as hedging instruments:
|
|
|
|
|
|
|
|
|
||||
Commodity derivatives
|
|
|
$
|
—
|
|
|
|
Other current assets
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
||||
Interest rate derivatives
|
|
|
—
|
|
|
|
Other current liabilities
|
|
(23
|
)
|
||
|
|
|
|
|
|
Other long-term liabilities and deferred credits
|
|
(27
|
)
|
|||
Total derivatives designated as hedging instruments
|
|
|
$
|
—
|
|
|
|
|
|
$
|
(50
|
)
|
|
|
|
|
|
|
|
|
|
||||
Derivatives not designated as hedging instruments:
|
|
|
|
|
|
|
|
|
||||
Commodity derivatives
|
Other current assets
|
|
$
|
101
|
|
|
|
Other current assets
|
|
$
|
(344
|
)
|
|
Other long-term assets, net
|
|
2
|
|
|
|
Other long-term assets, net
|
|
(1
|
)
|
||
|
Other long-term liabilities and deferred credits
|
|
2
|
|
|
|
Other current liabilities
|
|
(14
|
)
|
||
|
|
|
|
|
|
Other long-term liabilities and deferred credits
|
|
(34
|
)
|
|||
|
|
|
|
|
|
|
|
|
||||
Foreign currency derivatives
|
Other current liabilities
|
|
3
|
|
|
|
Other current liabilities
|
|
(6
|
)
|
||
|
|
|
|
|
|
|
|
|
||||
Preferred Distribution Rate Reset Option
|
|
|
—
|
|
|
|
Other long-term liabilities and deferred credits
|
|
(32
|
)
|
||
Total derivatives not designated as hedging instruments
|
|
|
$
|
108
|
|
|
|
|
|
$
|
(431
|
)
|
|
|
|
|
|
|
|
|
|
||||
Total derivatives
|
|
|
$
|
108
|
|
|
|
|
|
$
|
(481
|
)
|
|
Asset Derivatives
|
|
|
Liability Derivatives
|
||||||||
|
Balance Sheet
Location
|
|
Fair
Value
|
|
|
Balance Sheet
Location
|
|
Fair
Value
|
||||
Derivatives designated as hedging instruments:
|
|
|
|
|
|
|
|
|
||||
Commodity derivatives
|
Other current assets
|
|
$
|
4
|
|
|
|
Other current assets
|
|
$
|
(2
|
)
|
|
|
|
|
|
|
|
|
|
||||
Interest rate derivatives
|
Other long-term assets, net
|
|
1
|
|
|
|
Other current liabilities
|
|
(17
|
)
|
||
|
|
|
|
|
|
Other long-term liabilities and deferred credits
|
|
(33
|
)
|
|||
Total derivatives designated as hedging instruments
|
|
|
$
|
5
|
|
|
|
|
|
$
|
(52
|
)
|
|
|
|
|
|
|
|
|
|
||||
Derivatives not designated as hedging instruments:
|
|
|
|
|
|
|
|
|
||||
Commodity derivatives
|
Other current assets
|
|
$
|
265
|
|
|
|
Other current assets
|
|
$
|
(35
|
)
|
|
Other long-term assets, net
|
|
10
|
|
|
|
Other long-term assets, net
|
|
(1
|
)
|
||
|
|
|
|
|
|
Other current liabilities
|
|
(13
|
)
|
|||
|
|
|
|
|
|
Other long-term liabilities and deferred credits
|
|
(1
|
)
|
|||
|
|
|
|
|
|
|
|
|
||||
Foreign currency derivatives
|
|
|
|
|
|
Other current liabilities
|
|
(8
|
)
|
|||
Total derivatives not designated as hedging instruments
|
|
|
$
|
275
|
|
|
|
|
|
$
|
(58
|
)
|
|
|
|
|
|
|
|
|
|
||||
Total derivatives
|
|
|
$
|
280
|
|
|
|
|
|
$
|
(110
|
)
|
|
|
December 31, 2016
|
|
December 31, 2015
|
||||
Initial margin
|
|
$
|
119
|
|
|
$
|
91
|
|
Variation margin posted/(returned)
|
|
291
|
|
|
(247
|
)
|
||
Net broker receivable/(payable)
|
|
$
|
410
|
|
|
$
|
(156
|
)
|
|
December 31, 2016
|
|
|
December 31, 2015
|
||||||||||||
|
Derivative
Asset Positions
|
|
Derivative
Liability Positions
|
|
|
Derivative
Asset Positions
|
|
Derivative
Liability Positions
|
||||||||
Netting Adjustments:
|
|
|
|
|
|
|
|
|
||||||||
Gross position - asset/(liability)
|
$
|
108
|
|
|
$
|
(481
|
)
|
|
|
$
|
280
|
|
|
$
|
(110
|
)
|
Netting adjustment
|
(350
|
)
|
|
350
|
|
|
|
(38
|
)
|
|
38
|
|
||||
Cash collateral paid/(received)
|
410
|
|
|
—
|
|
|
|
(156
|
)
|
|
—
|
|
||||
Net position - asset/(liability)
|
$
|
168
|
|
|
$
|
(131
|
)
|
|
|
$
|
86
|
|
|
$
|
(72
|
)
|
|
|
|
|
|
|
|
|
|
||||||||
Balance Sheet Location After Netting Adjustments:
|
|
|
|
|
|
|
|
|
||||||||
Other current assets
|
$
|
167
|
|
|
$
|
—
|
|
|
|
$
|
76
|
|
|
$
|
—
|
|
Other long-term assets, net
|
1
|
|
|
—
|
|
|
|
10
|
|
|
—
|
|
||||
Other current liabilities
|
—
|
|
|
(40
|
)
|
|
|
—
|
|
|
(38
|
)
|
||||
Other long-term liabilities and deferred credits
|
—
|
|
|
(91
|
)
|
|
|
—
|
|
|
(34
|
)
|
||||
|
$
|
168
|
|
|
$
|
(131
|
)
|
|
|
$
|
86
|
|
|
$
|
(72
|
)
|
|
Year Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
Commodity derivatives, net
|
$
|
—
|
|
|
$
|
33
|
|
|
$
|
15
|
|
Interest rate derivatives, net
|
(33
|
)
|
|
(32
|
)
|
|
(103
|
)
|
|||
Foreign currency derivatives, net
|
—
|
|
|
—
|
|
|
2
|
|
|||
Total
|
$
|
(33
|
)
|
|
$
|
1
|
|
|
$
|
(86
|
)
|
|
|
Fair Value as of December 31, 2016
|
|
|
Fair Value as of December 31, 2015
|
||||||||||||||||||||||||||||
Recurring Fair Value Measures
(1)
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
||||||||||||||||
Commodity derivatives
|
|
$
|
(113
|
)
|
|
$
|
(171
|
)
|
|
$
|
(4
|
)
|
|
$
|
(288
|
)
|
|
|
$
|
126
|
|
|
$
|
90
|
|
|
$
|
11
|
|
|
$
|
227
|
|
Interest rate derivatives
|
|
—
|
|
|
(50
|
)
|
|
—
|
|
|
(50
|
)
|
|
|
—
|
|
|
(49
|
)
|
|
—
|
|
|
(49
|
)
|
||||||||
Foreign currency derivatives
|
|
—
|
|
|
(3
|
)
|
|
—
|
|
|
(3
|
)
|
|
|
—
|
|
|
(8
|
)
|
|
—
|
|
|
(8
|
)
|
||||||||
Preferred Distribution Rate Reset Option
|
|
—
|
|
|
—
|
|
|
(32
|
)
|
|
(32
|
)
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||||
Total net derivative asset/(liability)
|
|
$
|
(113
|
)
|
|
$
|
(224
|
)
|
|
$
|
(36
|
)
|
|
$
|
(373
|
)
|
|
|
$
|
126
|
|
|
$
|
33
|
|
|
$
|
11
|
|
|
$
|
170
|
|
|
(1)
|
Derivative assets and liabilities are presented above on a net basis but do not include related cash margin deposits.
|
|
Year Ended December 31,
|
||||||
|
2016
|
|
2015
|
||||
Beginning Balance
|
$
|
11
|
|
|
$
|
15
|
|
Net gains for the period included in earnings
|
28
|
|
|
1
|
|
||
Settlements
|
(10
|
)
|
|
(14
|
)
|
||
Derivatives entered into during the period
|
(65
|
)
|
|
9
|
|
||
Ending Balance
|
$
|
(36
|
)
|
|
$
|
11
|
|
|
|
|
|
||||
Change in unrealized gains/(losses) included in earnings relating to Level 3 derivatives still held at the end of the period
|
$
|
(36
|
)
|
|
$
|
10
|
|
|
Year Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
Current income tax expense:
|
|
|
|
|
|
||||||
State income tax
|
$
|
2
|
|
|
$
|
1
|
|
|
$
|
1
|
|
Canadian federal and provincial income tax
|
83
|
|
|
83
|
|
|
70
|
|
|||
Total current income tax expense
|
$
|
85
|
|
|
$
|
84
|
|
|
$
|
71
|
|
|
|
|
|
|
|
||||||
Deferred income tax expense/(benefit):
|
|
|
|
|
|
||||||
Canadian federal and provincial income tax
|
$
|
(60
|
)
|
|
$
|
16
|
|
|
$
|
100
|
|
Total deferred income tax expense/(benefit)
|
$
|
(60
|
)
|
|
$
|
16
|
|
|
$
|
100
|
|
Total income tax expense
|
$
|
25
|
|
|
$
|
100
|
|
|
$
|
171
|
|
|
Year Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
Income before tax
|
$
|
755
|
|
|
$
|
1,006
|
|
|
$
|
1,557
|
|
Partnership earnings not subject to current Canadian tax
|
(723
|
)
|
|
(773
|
)
|
|
(976
|
)
|
|||
|
$
|
32
|
|
|
$
|
233
|
|
|
$
|
581
|
|
Canadian federal and provincial corporate tax rate
|
27
|
%
|
|
26
|
%
|
|
25
|
%
|
|||
Income tax at statutory rate
|
$
|
8
|
|
|
$
|
61
|
|
|
$
|
145
|
|
|
|
|
|
|
|
||||||
Canadian withholding tax
|
$
|
13
|
|
|
$
|
14
|
|
|
$
|
16
|
|
Canadian permanent differences and rate changes
|
2
|
|
|
24
|
|
|
9
|
|
|||
State income tax
|
2
|
|
|
1
|
|
|
1
|
|
|||
Total income tax expense
|
$
|
25
|
|
|
$
|
100
|
|
|
$
|
171
|
|
|
December 31,
|
||||||
|
2016
|
|
2015
|
||||
Deferred tax assets:
|
|
|
|
||||
Derivative instruments
|
$
|
49
|
|
|
$
|
—
|
|
Book accruals in excess of current tax deductions
|
24
|
|
|
20
|
|
||
Net operating losses
|
4
|
|
|
3
|
|
||
Total deferred tax assets
|
77
|
|
|
23
|
|
||
|
|
|
|
||||
Deferred tax liabilities:
|
|
|
|
||||
Derivative instruments
|
—
|
|
|
(30
|
)
|
||
Property and equipment in excess of tax values
|
(394
|
)
|
|
(312
|
)
|
||
Other
|
(41
|
)
|
|
(41
|
)
|
||
Total deferred tax liabilities
|
(435
|
)
|
|
(383
|
)
|
||
Net deferred tax liabilities
|
$
|
(358
|
)
|
|
$
|
(360
|
)
|
|
|
|
|
||||
Balance sheet classification of deferred tax assets/(liabilities):
|
|
|
|
||||
Other long-term assets, net
|
$
|
4
|
|
|
$
|
3
|
|
Other long-term liabilities and deferred credits
|
(362
|
)
|
|
(363
|
)
|
||
|
$
|
(358
|
)
|
|
$
|
(360
|
)
|
•
|
that, for all periods following the closing of the Simplification Transactions, we will pay all direct or indirect expenses of any of the PAGP Entities, other than income taxes (including, but 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). We paid
$4 million
of such expenses in 2016;
|
•
|
the ability of PAGP 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 our common units from us; and
|
•
|
the ability of PAGP to lend proceeds of any future indebtedness incurred by it to AAP, and AAP’s corresponding ability to lend such proceeds to us, in each case on substantially the same terms as incurred by PAGP.
|
|
Year Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
Revenues
|
$
|
655
|
|
|
$
|
866
|
|
|
$
|
1,212
|
|
|
|
|
|
|
|
||||||
Purchases and related costs
(1)
|
$
|
42
|
|
|
$
|
41
|
|
|
$
|
925
|
|
|
(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.
|
|
December 31,
|
||||||
|
2016
|
|
2015
|
||||
Trade accounts receivable and other receivables
|
$
|
789
|
|
|
$
|
405
|
|
|
|
|
|
||||
Accounts payable
|
$
|
836
|
|
|
$
|
363
|
|
PAA
LTIP Units
Outstanding
(1) (2)
|
|
PAA
Distribution
Required
(3)
|
|
Estimated Unit Vesting Date
|
|||||||||||||||||
|
|
2017
|
|
2018
|
|
2019
|
|
2020
|
|
Thereafter
|
|
Total
|
|||||||||
8.9
|
|
|
$2.20-$2.65
|
|
1.7
|
|
|
2.1
|
|
|
2.0
|
|
|
1.3
|
|
|
1.8
|
|
|
8.9
|
|
|
(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.
|
(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 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).
|
|
PAA Units
(1) (2)
|
|||||
|
Units
|
|
Weighted Average
Grant Date
Fair Value per Unit
|
|||
Outstanding at December 31, 2013
|
8.4
|
|
|
$
|
36.97
|
|
Granted
|
1.2
|
|
|
$
|
47.68
|
|
Vested
|
(1.9
|
)
|
|
$
|
25.49
|
|
Cancelled or forfeited
|
(0.4
|
)
|
|
$
|
40.14
|
|
Outstanding at December 31, 2014
|
7.3
|
|
|
$
|
41.45
|
|
Granted
|
2.1
|
|
|
$
|
28.76
|
|
Vested
|
(2.1
|
)
|
|
$
|
28.91
|
|
Cancelled or forfeited
|
(0.4
|
)
|
|
$
|
44.56
|
|
Outstanding at December 31, 2015
|
6.9
|
|
|
$
|
41.23
|
|
Granted
|
4.5
|
|
|
$
|
23.38
|
|
Vested
|
(1.9
|
)
|
|
$
|
45.91
|
|
Modified
(3)
|
—
|
|
|
$
|
(8.21
|
)
|
Cancelled or forfeited
|
(0.6
|
)
|
|
$
|
37.19
|
|
Outstanding at December 31, 2016
|
8.9
|
|
|
$
|
29.62
|
|
|
(1)
|
Amounts do not include AAP Management Units.
|
(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.
|
|
|
Outstanding
|
|
Outstanding
Units Earned
|
|
|
Grant Date
Fair Value of Outstanding
AAP Management Units
(1)
|
||||
Balance at December 31, 2014
|
|
18.4
|
|
|
17.9
|
|
|
|
$
|
64
|
|
Granted
|
|
0.6
|
|
|
—
|
|
|
|
24
|
|
|
Earned
|
|
N/A
|
|
|
0.3
|
|
|
|
N/A
|
|
|
Balance at December 31, 2015
|
|
19.0
|
|
|
18.2
|
|
|
|
$
|
88
|
|
Modified
(2)
|
|
—
|
|
|
—
|
|
|
|
(17
|
)
|
|
Converted
|
|
(15.6
|
)
|
|
(15.6
|
)
|
|
|
(36
|
)
|
|
Balance at December 31, 2016
|
|
3.4
|
|
|
2.6
|
|
|
|
$
|
35
|
|
|
(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.
|
|
Year Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
Equity-indexed compensation expense
|
$
|
60
|
|
|
$
|
27
|
|
|
$
|
98
|
|
LTIP unit-settled vestings
|
$
|
24
|
|
|
$
|
37
|
|
|
$
|
53
|
|
LTIP cash-settled vestings
|
$
|
28
|
|
|
$
|
66
|
|
|
$
|
53
|
|
DER cash payments
|
$
|
6
|
|
|
$
|
8
|
|
|
$
|
8
|
|
Year
|
|
Equity-Indexed
Compensation Plan Fair Value
Amortization
(1) (2)
|
||
2017
|
|
$
|
65
|
|
2018
|
|
42
|
|
|
2019
|
|
19
|
|
|
2020
|
|
7
|
|
|
2021
|
|
2
|
|
|
Total
|
|
$
|
135
|
|
|
(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.
|
|
2017
|
|
2018
|
|
2019
|
|
2020
|
|
2021
|
|
Thereafter
|
|
Total
|
||||||||||||||
Leases and rights-of-way easements
(1)
|
$
|
195
|
|
|
$
|
165
|
|
|
$
|
140
|
|
|
$
|
118
|
|
|
$
|
97
|
|
|
$
|
404
|
|
|
$
|
1,119
|
|
Other commitments
(2)
|
257
|
|
|
166
|
|
|
153
|
|
|
132
|
|
|
128
|
|
|
378
|
|
|
1,214
|
|
|||||||
Total
|
$
|
452
|
|
|
$
|
331
|
|
|
$
|
293
|
|
|
$
|
250
|
|
|
$
|
225
|
|
|
$
|
782
|
|
|
$
|
2,333
|
|
|
(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.
|
|
First
Quarter
|
|
Second
Quarter
|
|
Third
Quarter
|
|
Fourth
Quarter
|
|
Total
(1)
|
||||||||||
|
(in millions, except per unit data)
|
||||||||||||||||||
2016
|
|
|
|
|
|
|
|
|
|
||||||||||
Total revenues
|
$
|
4,111
|
|
|
$
|
4,950
|
|
|
$
|
5,170
|
|
|
$
|
5,952
|
|
|
$
|
20,182
|
|
Gross margin
(2)
|
$
|
349
|
|
|
$
|
219
|
|
|
$
|
419
|
|
|
$
|
286
|
|
|
$
|
1,273
|
|
Operating income
|
$
|
282
|
|
|
$
|
146
|
|
|
$
|
349
|
|
|
$
|
218
|
|
|
$
|
994
|
|
Net income
|
$
|
203
|
|
|
$
|
102
|
|
|
$
|
298
|
|
|
$
|
127
|
|
|
$
|
730
|
|
Net income attributable to PAA
|
$
|
202
|
|
|
$
|
101
|
|
|
$
|
297
|
|
|
$
|
126
|
|
|
$
|
726
|
|
Basic net income/(loss) per common unit
|
$
|
0.07
|
|
|
$
|
(0.20
|
)
|
|
$
|
0.40
|
|
|
$
|
0.14
|
|
|
$
|
0.43
|
|
Diluted net income/(loss) per common unit
|
$
|
0.07
|
|
|
$
|
(0.20
|
)
|
|
$
|
0.40
|
|
|
$
|
0.14
|
|
|
$
|
0.43
|
|
Cash distributions per common unit
(3)
|
$
|
0.70
|
|
|
$
|
0.70
|
|
|
$
|
0.70
|
|
|
$
|
0.55
|
|
|
$
|
2.65
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
2015
|
|
|
|
|
|
|
|
|
|
||||||||||
Total revenues
|
$
|
5,942
|
|
|
$
|
6,663
|
|
|
$
|
5,551
|
|
|
$
|
4,996
|
|
|
$
|
23,152
|
|
Gross margin
(2)
|
$
|
450
|
|
|
$
|
290
|
|
|
$
|
395
|
|
|
$
|
405
|
|
|
$
|
1,540
|
|
Operating income
|
$
|
372
|
|
|
$
|
211
|
|
|
$
|
335
|
|
|
$
|
344
|
|
|
$
|
1,262
|
|
Net income
|
$
|
284
|
|
|
$
|
124
|
|
|
$
|
250
|
|
|
$
|
248
|
|
|
$
|
906
|
|
Net income attributable to PAA
|
$
|
283
|
|
|
$
|
124
|
|
|
$
|
249
|
|
|
$
|
247
|
|
|
$
|
903
|
|
Basic net income/(loss) per common unit
|
$
|
0.36
|
|
|
$
|
(0.06
|
)
|
|
$
|
0.25
|
|
|
$
|
0.24
|
|
|
$
|
0.78
|
|
Diluted net income/(loss) per common unit
|
$
|
0.35
|
|
|
$
|
(0.06
|
)
|
|
$
|
0.24
|
|
|
$
|
0.24
|
|
|
$
|
0.77
|
|
Cash distributions per common unit
(3)
|
$
|
0.68
|
|
|
$
|
0.69
|
|
|
$
|
0.70
|
|
|
$
|
0.70
|
|
|
$
|
2.76
|
|
|
(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.
|
|
Transportation
|
|
Facilities
|
|
Supply and
Logistics
|
|
Intersegment
Adjustment
(1)
|
|
Total
|
||||||||||
Year Ended December 31, 2016
|
|
|
|
|
|
|
|
|
|
||||||||||
Revenues:
|
|
|
|
|
|
|
|
|
|
||||||||||
External customers
|
$
|
954
|
|
|
$
|
546
|
|
|
$
|
19,004
|
|
|
$
|
(322
|
)
|
|
$
|
20,182
|
|
Intersegment
(2)
|
630
|
|
|
561
|
|
|
14
|
|
|
322
|
|
|
1,527
|
|
|||||
Total revenues of reportable segments
|
$
|
1,584
|
|
|
$
|
1,107
|
|
|
$
|
19,018
|
|
|
$
|
—
|
|
|
$
|
21,709
|
|
Equity earnings in unconsolidated entities
|
$
|
195
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
|
$
|
195
|
|
|
Segment adjusted EBITDA
|
$
|
1,141
|
|
|
$
|
667
|
|
|
$
|
359
|
|
|
|
|
|
$
|
2,167
|
|
|
Capital expenditures
(3)
|
$
|
1,063
|
|
|
$
|
577
|
|
|
$
|
54
|
|
|
|
|
|
$
|
1,694
|
|
|
Maintenance capital
|
$
|
121
|
|
|
$
|
55
|
|
|
$
|
10
|
|
|
|
|
|
$
|
186
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
As of December 31, 2016
|
|
|
|
|
|
|
|
|
|
||||||||||
Total assets
|
$
|
10,917
|
|
|
$
|
7,556
|
|
|
$
|
5,737
|
|
|
|
|
|
$
|
24,210
|
|
|
Investments in unconsolidated entities
|
$
|
2,290
|
|
|
$
|
53
|
|
|
$
|
—
|
|
|
|
|
|
$
|
2,343
|
|
|
Transportation
|
|
Facilities
|
|
Supply and
Logistics
|
|
Intersegment
Adjustment
(1)
|
|
Total
|
||||||||||
Year Ended December 31, 2015
|
|
|
|
|
|
|
|
|
|
||||||||||
Revenues:
|
|
|
|
|
|
|
|
|
|
||||||||||
External customers
|
$
|
953
|
|
|
$
|
528
|
|
|
$
|
21,927
|
|
|
$
|
(256
|
)
|
|
$
|
23,152
|
|
Intersegment
(2)
|
641
|
|
|
522
|
|
|
18
|
|
|
256
|
|
|
1,437
|
|
|||||
Total revenues of reportable segments
|
$
|
1,594
|
|
|
$
|
1,050
|
|
|
$
|
21,945
|
|
|
$
|
—
|
|
|
$
|
24,589
|
|
Equity earnings in unconsolidated entities
|
$
|
183
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
|
$
|
183
|
|
|
Segment adjusted EBITDA
|
$
|
1,056
|
|
|
$
|
588
|
|
|
$
|
568
|
|
|
|
|
|
$
|
2,212
|
|
|
Capital expenditures
(3)
|
$
|
1,278
|
|
|
$
|
813
|
|
|
$
|
184
|
|
|
|
|
|
$
|
2,275
|
|
|
Maintenance capital
|
$
|
144
|
|
|
$
|
68
|
|
|
$
|
8
|
|
|
|
|
|
$
|
220
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
As of December 31, 2015
|
|
|
|
|
|
|
|
|
|
||||||||||
Total assets
|
$
|
10,345
|
|
|
$
|
7,330
|
|
|
$
|
4,613
|
|
|
|
|
|
$
|
22,288
|
|
|
Investments in unconsolidated entities
|
$
|
1,998
|
|
|
$
|
29
|
|
|
$
|
—
|
|
|
|
|
|
$
|
2,027
|
|
|
Transportation
|
|
Facilities
|
|
Supply and
Logistics
|
|
Intersegment
Adjustment
(1)
|
|
Total
|
||||||||||
Year Ended December 31, 2014
|
|
|
|
|
|
|
|
|
|
||||||||||
Revenues:
|
|
|
|
|
|
|
|
|
|
||||||||||
External customers
|
$
|
994
|
|
|
$
|
576
|
|
|
$
|
42,114
|
|
|
$
|
(220
|
)
|
|
$
|
43,464
|
|
Intersegment
(2)
|
661
|
|
|
551
|
|
|
36
|
|
|
220
|
|
|
1,468
|
|
|||||
Total revenues of reportable segments
|
$
|
1,655
|
|
|
$
|
1,127
|
|
|
$
|
42,150
|
|
|
$
|
—
|
|
|
$
|
44,932
|
|
Equity earnings in unconsolidated entities
|
$
|
108
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
|
$
|
108
|
|
|
Segment adjusted EBITDA
|
$
|
979
|
|
|
$
|
597
|
|
|
$
|
651
|
|
|
|
|
|
$
|
2,227
|
|
|
Capital expenditures
(3)
|
$
|
2,483
|
|
|
$
|
582
|
|
|
$
|
60
|
|
|
|
|
|
$
|
3,125
|
|
|
Maintenance capital
|
$
|
165
|
|
|
$
|
52
|
|
|
$
|
7
|
|
|
|
|
|
$
|
224
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
As of December 31, 2014
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Total assets
|
$
|
9,579
|
|
|
$
|
6,843
|
|
|
$
|
5,776
|
|
|
|
|
|
$
|
22,198
|
|
|
Investments in unconsolidated entities
|
$
|
1,735
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
|
$
|
1,735
|
|
|
(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.
|
|
Year Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
Segment adjusted EBITDA
|
$
|
2,167
|
|
|
$
|
2,212
|
|
|
$
|
2,227
|
|
Adjustments
(1)
:
|
|
|
|
|
|
||||||
Depreciation and amortization of unconsolidated entities
(2)
|
(50
|
)
|
|
(45
|
)
|
|
(29
|
)
|
|||
Gains/(losses) from derivative activities net of inventory valuation adjustments
(3)
|
(404
|
)
|
|
(110
|
)
|
|
243
|
|
|||
Long-term inventory costing adjustments
(4)
|
58
|
|
|
(99
|
)
|
|
(85
|
)
|
|||
Deficiencies under minimum volume commitments, net
(5)
|
(46
|
)
|
|
—
|
|
|
—
|
|
|||
Equity-indexed compensation expense
(6)
|
(33
|
)
|
|
(27
|
)
|
|
(56
|
)
|
|||
Net gain/(loss) on foreign currency revaluation
(7)
|
(9
|
)
|
|
29
|
|
|
(9
|
)
|
|||
Line 901 incident
(8)
|
—
|
|
|
(83
|
)
|
|
—
|
|
|||
Depreciation and amortization
|
(494
|
)
|
|
(432
|
)
|
|
(384
|
)
|
|||
Interest expense, net
|
(467
|
)
|
|
(432
|
)
|
|
(348
|
)
|
|||
Other income/(expense), net
|
33
|
|
|
(7
|
)
|
|
(2
|
)
|
|||
Income before tax
|
755
|
|
|
1,006
|
|
|
1,557
|
|
|||
Income tax expense
|
(25
|
)
|
|
(100
|
)
|
|
(171
|
)
|
|||
Net income
|
730
|
|
|
906
|
|
|
1,386
|
|
|||
Net income attributable to noncontrolling interests
|
(4
|
)
|
|
(3
|
)
|
|
(2
|
)
|
|||
Net income attributable to PAA
|
$
|
726
|
|
|
$
|
903
|
|
|
$
|
1,384
|
|
|
(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 it is determined that the counterparty’s ability to utilize the make-up right is remote. We include the impact of amounts
|
(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.
|
|
Year Ended December 31,
|
||||||||||
Revenues
(1)
|
2016
|
|
2015
|
|
2014
|
||||||
United States
|
$
|
15,599
|
|
|
$
|
18,701
|
|
|
$
|
34,860
|
|
Canada
|
4,583
|
|
|
4,451
|
|
|
8,604
|
|
|||
|
$
|
20,182
|
|
|
$
|
23,152
|
|
|
$
|
43,464
|
|
|
(1)
|
Revenues are primarily attributed to each region based on where the services are provided or the product is shipped.
|
|
December 31,
|
||||||
Long-Lived Assets
(1)
|
2016
|
|
2015
|
||||
United States
|
$
|
16,041
|
|
|
$
|
15,942
|
|
Canada
|
3,895
|
|
|
3,368
|
|
||
|
$
|
19,936
|
|
|
$
|
19,310
|
|
|
(1)
|
Excludes long-term derivative assets.
|
2.1*
|
|
—
|
|
Share Purchase Agreement dated December 1, 2011 by and among Amoco Canada International Holdings B.V. and Plains Midstream Canada ULC (the schedules and exhibits have been omitted pursuant to Item 601(b)(2) of Regulation S-K) (incorporated by reference to Exhibit 2.1 to our Annual Report on Form 10-K for the year ended December 31, 2011).
|
|
|
|
|
|
2.2
|
|
—
|
|
Agreement and Plan of Merger dated as of October 21, 2013, by and among Plains All American Pipeline, L.P., PAA Acquisition Company LLC, PAA Natural Gas Storage, L.P. and PNGS GP LLC (incorporated by reference to Exhibit 2.1 to our Current Report on Form 8-K filed October 24, 2013).
|
|
|
|
|
|
2.3**
|
|
—
|
|
Simplification Agreement, dated as of July 11, 2016, by and among PAA GP Holdings LLC, Plains GP Holdings, L.P., Plains All American GP LLC, Plains AAP, L.P., PAA GP LLC and Plains All American Pipeline, L.P. (incorporated by reference to Exhibit 2.1 to our Current Report on Form 8-K filed July 14, 2016).
|
|
|
|
|
|
3.1
|
|
—
|
|
Sixth Amended and Restated Agreement of Limited Partnership of Plains All American Pipeline, L.P. dated as of November 15, 2016 (incorporated by reference to Exhibit 3.5 to our Current Report on Form 8-K filed November 21, 2016).
|
|
|
|
|
|
3.2
|
|
—
|
|
Third Amended and Restated Agreement of Limited Partnership of Plains Marketing, L.P. dated as of April 1, 2004 (incorporated by reference to Exhibit 3.2 to our Quarterly Report on Form 10-Q for the quarter ended March 31, 2004).
|
|
|
|
|
|
3.3
|
|
—
|
|
Amendment No. 1 dated December 31, 2010 to the Third Amended and Restated Agreement of Limited Partnership of Plains Marketing, L.P. (incorporated by reference to Exhibit 3.9 to our Annual Report on Form 10-K for the year ended December 31, 2010).
|
|
|
|
|
|
3.4
|
|
—
|
|
Amendment No. 2 dated January 1, 2011 to the Third Amended and Restated Agreement of Limited Partnership of Plains Marketing, L.P. (incorporated by reference to Exhibit 3.10 to our Annual Report on Form 10-K for the year ended December 31, 2010).
|
|
|
|
|
|
3.5
|
|
—
|
|
Amendment No. 3 dated June 30, 2011 to the Third Amended and Restated Agreement of Limited Partnership of Plains Marketing, L.P. (incorporated by reference to Exhibit 3.7 to our Annual Report on Form 10-K for the year ended December 31, 2013).
|
|
|
|
|
|
3.6
|
|
—
|
|
Amendment No. 4 dated January 1, 2013 to the Third Amended and Restated Agreement of Limited Partnership of Plains Marketing, L.P (incorporated by reference to Exhibit 3.8 to our Annual Report on Form 10-K for the year ended December 31, 2013).
|
|
|
|
|
|
3.7
|
|
—
|
|
Third Amended and Restated Agreement of Limited Partnership of Plains Pipeline, L.P. dated as of April 1, 2004 (incorporated by reference to Exhibit 3.3 to our Quarterly Report on Form 10-Q for the quarter ended March 31, 2004).
|
|
|
|
|
|
3.8
|
|
—
|
|
Amendment No. 1 dated January 1, 2013 to the Third Amended and Restated Agreement of Limited Partnership of Plains Pipeline, L.P. (incorporated by reference to Exhibit 3.10 to our Annual Report on Form 10-K for the year ended December 31, 2013).
|
|
|
|
|
|
3.9
|
|
—
|
|
Seventh Amended and Restated Limited Liability Company Agreement of Plains All American GP LLC dated November 15, 2016 (incorporated by reference to Exhibit 3.3 to our Current Report on Form 8-K filed November 21, 2016).
|
|
|
|
|
|
3.10
|
|
—
|
|
Eighth Amended and Restated Limited Partnership Agreement of Plains AAP, L.P. dated November 15, 2016 (incorporated by reference to Exhibit 3.4 to our Current Report on Form 8-K filed November 21, 2016).
|
|
|
|
|
|
3.11
|
|
—
|
|
Certificate of Incorporation of PAA Finance Corp. (f/k/a Pacific Energy Finance Corporation, successor-by-merger to PAA Finance Corp.) (incorporated by reference to Exhibit 3.10 to our Annual Report on Form 10-K for the year ended December 31, 2006).
|
|
|
|
|
|
3.12
|
|
—
|
|
Bylaws of PAA Finance Corp. (f/k/a Pacific Energy Finance Corporation, successor-by-merger to PAA Finance Corp.) (incorporated by reference to Exhibit 3.11 to our Annual Report on Form 10-K for the year ended December 31, 2006).
|
|
|
|
|
|
3.13
|
|
—
|
|
Limited Liability Company Agreement of PAA GP LLC dated December 28, 2007 (incorporated by reference to Exhibit 3.3 to our Current Report on Form 8-K filed January 4, 2008).
|
|
|
|
|
|
3.14
|
|
—
|
|
Certificate of Limited Partnership of Plains GP Holdings, L.P. (incorporated by reference to Exhibit 3.1 to
PAGP’s Registration Statement on Form S-1 (333-190227) filed July 29, 2013).
|
|
|
|
|
|
3.15
|
|
—
|
|
Second Amended and Restated Agreement of Limited Partnership of Plains GP Holdings, L.P. dated as of November 15, 2016 (incorporated by reference to Exhibit 3.2 to PAGP’s Current Report on Form 8-K filed November 21, 2016).
|
|
|
|
|
|
3.16
|
|
—
|
|
Certificate of Formation of PAA GP Holdings LLC (incorporated by reference to Exhibit 3.3 to PAGP’s Registration Statement on Form S-1 (333-190227) filed July 29, 2013).
|
|
|
|
|
|
3.17
|
|
—
|
|
Third Amended and Restated Limited Liability Company Agreement of PAA GP Holdings LLC dated as of February 16, 2017 (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K filed February 21, 2017).
|
|
|
|
|
|
4.1
|
|
—
|
|
Indenture dated September 25, 2002 among Plains All American Pipeline, L.P., PAA Finance Corp. and Wachovia Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to our Quarterly Report on Form 10-Q for the quarter ended September 30, 2002).
|
|
|
|
|
|
4.2
|
|
—
|
|
Sixth Supplemental Indenture (Series A and Series B 6.70% Senior Notes due 2036) dated May 12, 2006 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and Wachovia Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed May 12, 2006).
|
|
|
|
|
|
4.3
|
|
—
|
|
Ninth Supplemental Indenture (Series A and Series B 6.125% Senior Notes due 2017) dated October 30, 2006 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed October 30, 2006).
|
|
|
|
|
|
4.4
|
|
—
|
|
Tenth Supplemental Indenture (Series A and Series B 6.650% Senior Notes due 2037) dated October 30, 2006 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.2 to our Current Report on Form 8-K filed October 30, 2006).
|
|
|
|
|
|
4.5
|
|
—
|
|
Thirteenth Supplemental Indenture (Series A and Series B 6.50% Senior Notes due 2018) dated April 23, 2008 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed April 23, 2008).
|
|
|
|
|
|
4.6
|
|
—
|
|
Fifteenth Supplemental Indenture (8.75% Senior Notes due 2019) dated April 20, 2009 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed April 20, 2009).
|
|
|
|
|
|
4.7
|
|
—
|
|
Seventeenth Supplemental Indenture (5.75% Senior Notes due 2020) dated September 4, 2009 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed September 4, 2009).
|
|
|
|
|
|
4.8
|
|
—
|
|
Nineteenth Supplemental Indenture (5.00% Senior Notes due 2021) dated January 14, 2011 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed January 11, 2011).
|
|
|
|
|
|
4.9
|
|
—
|
|
Twentieth Supplemental Indenture (3.65% Senior Notes due 2022) dated March 22, 2012 among Plains All American Pipeline, L.P., PAA Finance Corp. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed March 26, 2012).
|
|
|
|
|
|
4.10
|
|
—
|
|
Twenty-First Supplemental Indenture (5.15% Senior Notes due 2042) dated March 22, 2012 among Plains All American Pipeline, L.P., PAA Finance Corp. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.3 to our Current Report on Form 8-K filed March 26, 2012).
|
|
|
|
|
|
4.11
|
|
—
|
|
Twenty-Second Supplemental Indenture (2.85% Senior Notes due 2023) dated December 10, 2012, by and among Plains All American Pipeline, L.P., PAA Finance Corp. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed December 12, 2012).
|
|
|
|
|
|
4.12
|
|
—
|
|
Twenty-Third Supplemental Indenture (4.30% Senior Notes due 2043) dated December 10, 2012, by and among Plains All American Pipeline, L.P., PAA Finance Corp. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.3 to our Current Report on Form 8-K filed December 12, 2012).
|
|
|
|
|
|
4.13
|
|
—
|
|
Twenty-Fourth Supplemental Indenture (3.85% Senior Notes due 2023) dated August 15, 2013, by and among Plains All American Pipeline, L.P., PAA Finance Corp. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed August 15, 2013).
|
|
|
|
|
|
4.14
|
|
—
|
|
Twenty-Fifth Supplemental Indenture (4.70% Senior Notes due 2044) dated April 23, 2014, by and among Plains All American Pipeline, L.P., PAA Finance Corp. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed April 29, 2014).
|
|
|
|
|
|
4.15
|
|
—
|
|
Twenty-Sixth Supplemental Indenture (3.60% Senior Notes due 2024) dated September 9, 2014, by and among Plains All American Pipeline, L.P., PAA Finance Corp. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed September 11, 2014).
|
|
|
|
|
|
4.16
|
|
—
|
|
Twenty-Seventh Supplemental Indenture (2.60% Senior Notes due 2019) dated December 9, 2014, by and among Plains All American Pipeline, L.P., PAA Finance Corp. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed December 11, 2014).
|
|
|
|
|
|
4.17
|
|
—
|
|
Twenty-Eighth Supplemental Indenture (4.90% Senior Notes due 2045) dated December 9, 2014, by and among Plains All American Pipeline, L.P., PAA Finance Corp. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.3 to our Current Report on Form 8-K filed December 11, 2014).
|
|
|
|
|
|
4.18
|
|
—
|
|
Twenty-Ninth Supplemental Indenture (4.65% Senior Notes due 2025) dated August 24, 2015, by and among Plains All American Pipeline, L.P., PAA Finance Corp. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed August 26, 2015).
|
|
|
|
|
|
4.19
|
|
—
|
|
Thirtieth Supplemental Indenture (4.50% Senior Notes due 2026) dated November 22, 2016, by and among Plains All American Pipeline, L.P., PAA Finance Corp. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed November 29, 2016).
|
|
|
|
|
|
4.20
|
|
—
|
|
Registration Rights Agreement dated September 3, 2009 by and between Plains All American Pipeline, L.P. and Vulcan Gas Storage LLC (incorporated by reference to Exhibit 4.1 to our Registration Statement on Form S-3, File No. 333-162477).
|
|
|
|
|
|
4.21
|
|
—
|
|
Registration Rights Agreement, dated as of January 28, 2016 among Plains All American Pipeline, L.P. and the Purchasers named therein (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed February 2, 2016).
|
|
|
|
|
|
4.22
|
|
—
|
|
Registration Rights Agreement by and among Plains All American Pipeline, L.P. and the Holders defined therein, dated November 15, 2016 (incorporated by reference to Exhibit 10.4 to our Current Report on Form 8-K filed November 21, 2016).
|
|
|
|
|
|
10.1
|
|
—
|
|
Credit Agreement dated as of August 19, 2011 among Plains All American Pipeline, L.P., as Borrower; certain subsidiaries of Plains All American Pipeline, L.P. from time to time party thereto, as Designated Borrowers; Bank of America, N.A., as Administrative Agent; and the other Lenders party thereto (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed August 25, 2011).
|
|
|
|
|
|
10.2
|
|
—
|
|
First Amendment to Credit Agreement dated as of June 27, 2012, among Plains All American Pipeline, L.P. and Plains Midstream Canada ULC, as Borrowers; Bank of America, N.A., as Administrative Agent, Swing Line Lender and L/C Issuer; Wells Fargo Bank, National Association, as an L/C Issuer; and the other Lenders party thereto (incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K filed July 3, 2012).
|
|
|
|
|
|
10.3
|
|
—
|
|
Second Amendment to Credit Agreement dated as of August 16, 2013, among Plains All American Pipeline, L.P. and Plains Midstream Canada ULC, as Borrowers; Bank of America, N.A., as Administrative Agent, Swing Line Lender and L/C Issuer; Wells Fargo Bank, National Association, as an L/C Issuer; and the other Lenders party thereto (incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K filed August 20, 2013).
|
|
|
|
|
|
10.4
|
|
—
|
|
Third Amendment to Credit Agreement dated as of August 11, 2016, among Plains All American Pipeline, L.P. and Plains Midstream Canada ULC, as Borrowers; Bank of America, N.A., as Administrative Agent, Swing Line Lender and L/C Issuer; Wells Fargo Bank, National Association, as an L/C Issuer; and the other Lenders party thereto (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed August 17, 2016).
|
|
|
|
|
|
10.5
|
|
—
|
|
Contribution, Assignment and Amendment Agreement dated as of June 27, 2001, among Plains All American Pipeline, L.P., Plains Marketing, L.P., All American Pipeline, L.P., Plains AAP, L.P., Plains All American GP LLC and Plains Marketing GP Inc. (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed June 27, 2001).
|
|
|
|
|
|
10.6
|
|
—
|
|
Contribution, Assignment and Amendment Agreement dated as of June 8, 2001, among Plains All American Inc., Plains AAP, L.P. and Plains All American GP LLC (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed June 11, 2001).
|
|
|
|
|
|
10.7
|
|
—
|
|
Separation Agreement dated as of June 8, 2001 among Plains Resources Inc., Plains All American Inc., Plains All American GP LLC, Plains AAP, L.P. and Plains All American Pipeline, L.P. (incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K filed June 11, 2001).
|
|
|
|
|
|
10.8***
|
|
—
|
|
Pension and Employee Benefits Assumption and Transition Agreement dated as of June 8, 2001 among Plains Resources Inc., Plains All American Inc. and Plains All American GP LLC (incorporated by reference to Exhibit 10.3 to our Current Report on Form 8-K filed June 11, 2001).
|
|
|
|
|
|
10.9***
|
|
—
|
|
Plains All American GP LLC 2005 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed January 26, 2005).
|
|
|
|
|
|
10.10***
|
|
—
|
|
Plains All American GP LLC 1998 Long-Term Incentive Plan (incorporated by reference to Exhibit 99.1 to Registration Statement on Form S-8, File No. 333-74920) as amended June 27, 2003 (incorporated by reference to Exhibit 10.1 to our Quarterly Report on Form 10-Q for the quarter ended June 30, 2003).
|
|
|
|
|
|
10.11***
|
|
—
|
|
Amended and Restated Employment Agreement between Plains All American GP LLC and Greg L. Armstrong dated as of June 30, 2001 (incorporated by reference to Exhibit 10.1 to our Quarterly Report on Form 10-Q for the quarter ended September 30, 2001).
|
|
|
|
|
|
10.12***
|
|
—
|
|
Amended and Restated Employment Agreement between Plains All American GP LLC and Harry N. Pefanis dated as of June 30, 2001 (incorporated by reference to Exhibit 10.2 to our Quarterly Report on Form 10-Q for the quarter ended September 30, 2001).
|
|
|
|
|
|
10.13
|
|
—
|
|
Asset Purchase and Sale Agreement dated February 28, 2001 between Murphy Oil Company Ltd. and Plains Marketing Canada, L.P. (incorporated by reference to Exhibit 99.1 to our Current Report on Form 8-K filed May 10, 2001).
|
|
|
|
|
|
10.14
|
|
—
|
|
Transportation Agreement dated July 30, 1993, between All American Pipeline Company and Exxon Company, U.S.A. (incorporated by reference to Exhibit 10.9 to our Registration Statement on Form S-1 filed September 23, 1998, File No. 333-64107).
|
|
|
|
|
|
10.15
|
|
—
|
|
Transportation Agreement dated August 2, 1993, among All American Pipeline Company, Texaco Trading and Transportation Inc., Chevron U.S.A. and Sun Operating Limited Partnership (incorporated by reference to Exhibit 10.10 to our Registration Statement on Form S-1 filed September 23, 1998, File No. 333-64107).
|
|
|
|
|
|
10.16
|
|
—
|
|
Contribution, Conveyance and Assumption Agreement among Plains All American Pipeline, L.P. and certain other parties dated as of November 23, 1998 (incorporated by reference to Exhibit 10.3 to our Annual Report on Form 10-K for the year ended December 31, 1998).
|
|
|
|
|
|
10.17
|
|
—
|
|
First Amendment to Contribution, Conveyance and Assumption Agreement dated as of December 15, 1998 (incorporated by reference to Exhibit 10.13 to our Annual Report on Form 10-K for the year ended December 31, 1998).
|
|
|
|
|
|
10.18
|
|
—
|
|
Agreement for Purchase and Sale of Membership Interest in Scurlock Permian LLC between Marathon Ashland LLC and Plains Marketing, L.P. dated as of March 17, 1999 (incorporated by reference to Exhibit 10.16 to our Annual Report on Form 10-K for the year ended December 31, 1998).
|
|
|
|
|
|
10.19***
|
|
—
|
|
PMC (Nova Scotia) Company Bonus Program (incorporated by reference to Exhibit 10.20 to our Annual Report on Form 10-K for the year ended December 31, 2004).
|
|
|
|
|
|
10.20***
|
|
—
|
|
Quarterly Bonus Program Summary (incorporated by reference to Exhibit 10.21 to our Annual Report on Form 10-K for the year ended December 31, 2005).
|
|
|
|
|
|
10.21***
|
|
—
|
|
Form of LTIP Grant Letter (independent directors) (incorporated by reference to Exhibit 10.3 to our Current Report on Form 8-K filed February 23, 2005).
|
|
|
|
|
|
10.22***
|
|
—
|
|
Form of LTIP Grant Letter (designated directors) (incorporated by reference to Exhibit 10.4 to our Current Report on Form 8-K filed February 23, 2005).
|
|
|
|
|
|
10.23
|
|
—
|
|
Membership Interest Purchase Agreement by and between Sempra Energy Trading Corporation and PAA/Vulcan Gas Storage, LLC dated August 19, 2005 (incorporated by reference to Exhibit 1.2 to our Current Report on Form 8-K filed September 19, 2005).
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10.24***
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—
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Waiver Agreement dated as of December 23, 2010 between Plains All American GP LLC and Greg L. Armstrong (incorporated by reference to Exhibit 10.31 to our Annual Report on Form 10-K for the year ended December 31, 2010).
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10.25***
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—
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|
Waiver Agreement dated as of December 23, 2010 between Plains All American GP LLC and Harry N. Pefanis (incorporated by reference to Exhibit 10.32 to our Annual Report on Form 10-K for the year ended December 31, 2010).
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10.26***
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—
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Form of LTIP Grant Letter (audit committee members) (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed August 23, 2006).
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10.27***
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—
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Plains All American PPX Successor Long-Term Incentive Plan (incorporated by reference to Exhibit 10.45 to our Annual Report on Form 10-K for the year ended December 31, 2006).
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10.28***
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—
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Form of Plains AAP, L.P. Class B Restricted Units Agreement (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed January 4, 2008).
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10.29
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—
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Third Amended and Restated Credit Agreement dated as of August 19, 2011 by and among Plains Marketing, L.P., as Borrower, Plains All American Pipeline, L.P., as Guarantor, Bank of America, N.A., as Administrative Agent, and the other Lenders party thereto (incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K filed August 25, 2011).
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10.30
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—
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First Amendment to Third Amended and Restated Credit Agreement dated as of June 27, 2012, among Plains Marketing, L.P. and Plains Midstream Canada ULC, as Borrowers; Plains All American Pipeline, L.P., as Guarantor; Bank of America, N.A., as Administrative Agent, Swing Line Lender and L/C Issuer; and the other Lenders and L/C Issuers party thereto (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed July 3, 2012).
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10.31
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—
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Second Amendment to Third Amended and Restated Credit Agreement dated as of August 16, 2013, among Plains Marketing, L.P. and Plains Midstream Canada ULC, as Borrowers; Plains All American Pipeline, L.P., as Guarantor; Bank of America, N.A., as Administrative Agent, Swing Line Lender and L/C Issuer; Wells Fargo Bank, National Association, as an L/C Issuer; and the other Lenders and L/C Issuers party thereto (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed August 20, 2013).
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10.32
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—
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Third Amendment to Third Amended and Restated Credit Agreement dated as of August 11, 2016, among Plains Marketing, L.P. and Plains Midstream Canada ULC, as Borrowers; Plains All American Pipeline, L.P., as Guarantor; Bank of America, N.A., as Administrative Agent, Swing Line Lender and L/C Issuer; Wells Fargo Bank, National Association, as an L/C Issuer; and the other Lenders and L/C Issuers party thereto (incorporated by reference to Exhibit 10.3 to our Current Report on Form 8-K filed August 17, 2016).
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10.33
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—
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Contribution and Assumption Agreement dated December 28, 2007, by and between Plains AAP, L.P. and PAA GP LLC (incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K filed January 4, 2008).
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10.34***
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—
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First Amendment to Amended and Restated Employment Agreement dated December 4, 2008 between Plains All American GP LLC and Greg L. Armstrong (incorporated by reference to Exhibit 10.49 to our Annual Report on Form 10-K for the year ended December 31, 2008).
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10.35***
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—
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First Amendment to Amended and Restated Employment Agreement dated December 4, 2008 between Plains All American GP LLC and Harry N. Pefanis (incorporated by reference to Exhibit 10.50 to our Annual Report on Form 10-K for the year ended December 31, 2008).
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10.36***
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—
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First Amendment to Plains All American GP LLC 2005 Long-Term Incentive Plan dated December 4, 2008 (incorporated by reference to Exhibit 10.51 to our Annual Report on Form 10-K for the year ended December 31, 2008).
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10.37***
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—
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Second Amendment to Plains All American GP LLC 1998 Long-Term Incentive Plan dated December 4, 2008 (incorporated by reference to Exhibit 10.52 to our Annual Report on Form 10-K for the year ended December 31, 2008).
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10.38***
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—
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Form of Amendment to LTIP grant letters (executive officers) (incorporated by reference to Exhibit 10.53 to our Annual Report on Form 10-K for the year ended December 31, 2008).
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10.39***
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—
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Form of Amendment to LTIP grant letters (directors) (incorporated by reference to Exhibit 10.54 to our Annual Report on Form 10-K for the year ended December 31, 2008).
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10.40
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—
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Contribution Agreement dated as of April 29, 2010 by and among PAA Natural Gas Storage, L.P., PNGS GP LLC, Plains All American Pipeline, L.P., PAA Natural Gas Storage, LLC, PAA/Vulcan Gas Storage, LLC, Plains Marketing, L.P. and Plains Marketing GP Inc. (incorporated by reference to Exhibit 10.1 to PNG’s Current Report on Form 8-K filed May 4, 2010).
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10.41
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—
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Omnibus Agreement dated May 5, 2010 by and among Plains All American GP LLC, Plains All American Pipeline, L.P., PNGS GP LLC and PAA Natural Gas Storage, L.P. (incorporated by reference to Exhibit 10.1 to PNG’s Current Report on Form 8-K filed May 11, 2010).
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10.42***
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—
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Form of 2010 LTIP Grant Letters (incorporated by reference to Exhibit 10.58 to our Annual Report on Form 10-K for the year ended December 31, 2010).
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10.43***†
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—
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|
Director Compensation Summary
|
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10.44***
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—
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Waiver Agreement dated October 21, 2013 to the Amended and Restated Employment Agreement dated June 30, 2001 of Greg L. Armstrong (incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K filed October 25, 2013).
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10.45***
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—
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Waiver Agreement dated October 21, 2013 to the Amended and Restated Employment Agreement dated June 30, 2001 of Harry N. Pefanis (incorporated by reference to Exhibit 10.3 to our Current Report on Form 8-K filed October 25, 2013).
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10.46***
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—
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|
Form of Amendment to the Plains AAP, L.P. Class B Restricted Units Agreement, dated October 18, 2013 (incorporated by reference to Exhibit 10.4 to our Current Report on Form 8-K filed October 25, 2013).
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10.47***
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—
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|
Plains All American 2013 Long-Term Incentive Plan (incorporated by reference to Exhibit A to our Definitive Proxy Statement filed on October 3, 2013).
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10.48***
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|
—
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|
Plains All American PNG Successor Long-Term Incentive Plan (incorporated by reference to Exhibit 4.4 to our Registration Statement on Form S-8 (333-19319) filed December 31, 2013).
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10.49***
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—
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|
PAA Natural Gas Storage, L.P. 2010 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.2 to PNG’s Current Report on Form 8-K filed May 11, 2010).
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10.50***
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—
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|
Form of PAA LTIP Grant Letter for Officers (February 2013) (incorporated by reference to Exhibit 10.1 to our Quarterly Report on Form 10-Q for the quarter ended March 31, 2013).
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10.51
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|
—
|
|
364-Day Credit Agreement dated January 16, 2015 among Plains All American Pipeline, L.P., as Borrower; Bank of America, N.A., as Administrative Agent; Citibank, N.A., JPMorgan Chase Bank N.A. and Wells Fargo Bank, National Association, as Co-Syndication Agents; DNB Bank ASA, New York Branch and Mizuho Bank, Ltd., as Co-Documentation Agents; the other Lenders party thereto; and Merrill Lynch, Pierce, Fenner & Smith Incorporated, Citigroup Global Markets Inc., DNB Markets, Inc., J.P. Morgan Securities LLC, Mizuho Bank, Ltd. and Wells Fargo Securities, LLC, as Joint Lead Arrangers and Joint Bookrunners (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed January 20, 2015).
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10.52
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—
|
|
First Amendment to 364-Day Credit Agreement dated August 14, 2015 among Plains All American Pipeline, L.P., as Borrower; Bank of America, N.A., as Administrative Agent; Citibank, N.A., JPMorgan Chase Bank N.A. and Wells Fargo Bank, National Association, as Co-Syndication Agents; DNB Bank ASA, New York Branch and Mizuho Bank, Ltd., as Co-Documentation Agents; the other Lenders party thereto; and Merrill Lynch, Pierce, Fenner & Smith Incorporated, Citigroup Global Markets Inc., DNB Markets, Inc., J.P. Morgan Securities LLC, Mizuho Bank, Ltd. and Wells Fargo Securities, LLC, as Joint Lead Arrangers and Joint Bookrunners (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed August 14, 2015).
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|
|
|
10.53
|
|
—
|
|
Second Amendment to 364-Day Credit Agreement dated as of August 11, 2016 among Plains All American Pipeline, L.P., as Borrower; Bank of America, N.A., as Administrative Agent; Citibank, N.A., JPMorgan Chase Bank N.A. and Wells Fargo Bank, National Association, as Co-Syndication Agents; DNB Bank ASA, New York Branch and Mizuho Bank Ltd., as Co-Documentation Agents; the other Lenders party thereto; and Merrill Lynch, Pierce, Fenner & Smith Incorporated, Citigroup Global Markets Inc., DNB Markets, Inc., J.P. Morgan Securities LLC, Mizuho Bank, Ltd. and Wells Fargo Securities, LLC, as Joint Lead Arrangers and Join Bookrunners (incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K filed August 17, 2016).
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|
10.54***
|
|
—
|
|
Employment Agreement between Plains All American GP LLC and Willie Chiang dated July 10, 2015 (incorporated by reference to Exhibit 10.53 to our Annual Report on Form 10-K for the year ended December 31, 2015).
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|
|
10.55***
|
|
—
|
|
Amendment dated August 25, 2016 to LTIP Grant Letter dated August 24, 2015 (Willie Chiang) (incorporated by reference to Exhibit 10.7 to our Quarterly Report on Form 10-Q for the quarter ended September 30, 2016).
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|
10.56***
|
|
|
|
First Amendment to Plains AAP, L.P. Class B Restricted Units Agreement dated August 25, 2016 (Willie Chiang) (incorporated by reference to Exhibit 10.8 to our Quarterly Report on Form 10-Q for the quarter ended September 30, 2016).
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|
10.57***
|
|
—
|
|
Form of PAA LTIP Grant Letter for Officers (August 2016) (incorporated by reference to Exhibit 10.5 to our Quarterly Report on Form 10-Q for the quarter ended September 30, 2016).
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|
|
10.58***
|
|
—
|
|
Form of Amendment to Plains AAP, L.P. Class B Restricted Units Agreement dated August 25, 2016 (incorporated by reference to Exhibit 10.6 to our Quarterly Report on Form 10-Q for the quarter ended September 30, 2016).
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|
|
|
10.59
|
|
—
|
|
Omnibus Agreement by and among PAA GP Holdings LLC, Plains GP Holdings, L.P., Plains All American GP LLC, Plains AAP, L.P., PAA GP LLC, and Plains All American Pipeline, L.P., dated November 15, 2016 (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed November 21, 2016).
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|
|
10.60
|
|
—
|
|
Amended and Restated Administrative Agreement by and among PAA GP Holdings LLC, Plains GP Holdings, L.P., Plains All American GP LLC, Plains AAP, L.P., PAA GP LLC, and Plains All American Pipeline, L.P., dated November 15, 2016 (incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K filed November 21, 2016).
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12.1 †
|
|
—
|
|
Computation of Ratio of Earnings to Fixed Charges.
|
|
|
|
|
|
21.1 †
|
|
—
|
|
List of Subsidiaries of Plains All American Pipeline, L.P.
|
|
|
|
|
|
23.1 †
|
|
—
|
|
Consent of PricewaterhouseCoopers LLP.
|
|
|
|
|
|
31.1 †
|
|
—
|
|
Certification of Principal Executive Officer pursuant to Exchange Act Rules 13a-14(a) and 15d-14(a).
|
|
|
|
|
|
31.2 †
|
|
—
|
|
Certification of Principal Financial Officer pursuant to Exchange Act Rules 13a-14(a) and 15d-14(a).
|
|
|
|
|
|
32.1 ††
|
|
—
|
|
Certification of Principal Executive Officer pursuant to 18 U.S.C. 1350.
|
|
|
|
|
|
32.2 ††
|
|
—
|
|
Certification of Principal Financial Officer pursuant to 18 U.S.C. 1350.
|
|
|
|
|
|
101. INS†
|
|
—
|
|
XBRL Instance Document
|
|
|
|
|
|
101.SCH†
|
|
—
|
|
XBRL Taxonomy Extension Schema Document
|
|
|
|
|
|
101.CAL†
|
|
—
|
|
XBRL Taxonomy Extension Calculation Linkbase Document
|
|
|
|
|
|
101.DEF†
|
|
—
|
|
XBRL Taxonomy Extension Definition Linkbase Document
|
|
|
|
|
|
101.LAB†
|
|
—
|
|
XBRL Taxonomy Extension Label Linkbase Document
|
|
|
|
|
|
101.PRE†
|
|
—
|
|
XBRL Taxonomy Extension Presentation Linkbase Document
|
|
†
|
Filed herewith.
|
††
|
Furnished herewith.
|