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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

(Mark One)

For the fiscal year ended December 31, 20122014

or

Commission file number 1-14569

PLAINS ALL AMERICAN PIPELINE, L.P.

(Exact name of registrant as specified in its charter)

Registrant’s telephone number, including area code: (713) 646-4100

Securities registered pursuant to Section 12(b) of the Act:

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes x  No o

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o  No x

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes x  No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes x  No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No x

The aggregate market value of the Common Units held by non-affiliates of the registrant (treating all executive officers and directors of the registrant and holders of 10% or more of the Common Units outstanding, for this purpose, as if they may be affiliates of the registrant) was approximately $12.9$21.8 billion on June 30, 2012,2014, based on a closing price of $80.81$60.05 per Common Unit as reported on the New York Stock Exchange on such date.

As of February 20, 2013,18, 2015, there were 336,152,761376,241,697 Common Units outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

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FORWARD-LOOKING STATEMENTS

All statements included in this report, other than statements of historical fact, are forward-looking statements, including but not limited to statements incorporating the words “anticipate,” “believe,” “estimate,” “expect,” “plan,” “intend” and “forecast,” as well as similar expressions and statements regarding our business strategy, plans and objectives for future operations. The absence of such words, expressions or statements, however, does not mean that the statements are not forward-looking. Any such forward-looking statements reflect our current views with respect to future events, based on what we believe to be reasonable assumptions. Certain factors could cause actual results or outcomes to differ materially from the results or outcomes anticipated in the forward-looking statements. The most important of these factors include, but are not limited to:

·                  failure to implement or capitalize, or delays in implementing or capitalizing, on planned internal growth projects;

·declines in the volume of crude oil, refined product and NGL shipped, processed, purchased, stored, fractionated and/or gathered at or through the use of our facilities, whether due to declines in production from existing oil and gas reserves, 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;

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

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

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

·the effects of competition;

·the occurrence of a natural disaster, catastrophe, terrorist attack or other event, including attacks on our electronic and computer systems;

·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;

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

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

·maintenance of our credit rating and ability to receive open credit from our suppliers and trade counterparties;

·the currency exchange rate of the Canadian dollar;

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

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

·                  the occurrence of a natural disaster, catastrophe, terrorist attack or other event, including attacks on our electronic and computer systems;

·tightened capital markets or other factors that increase our cost of capital or limit our access to capital;

·maintenance of our credit rating and ability to receive open credit from our suppliers and trade counterparties;

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

·the effectiveness of our risk management activities;

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

·declines in the volume of crude oil, refined product and NGL shipped, processed, purchased, stored, fractionated and/or gathered at or through the use of our facilities, whether due to declines in production from existing oil and gas reserves, failure to or slowdown in the development of additional oil and gas reserves or other factors;

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

·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;

·our ability to obtain debt or equity financing on satisfactory terms to fund additional acquisitions, expansion projects, working capital requirements and the repayment or refinancing of indebtedness;

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

·                  non-utilization of our assets and facilities;

·the effects of competition;

·interruptions in service on third-party pipelines;

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

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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;

·                  the currency exchange rate of the Canadian dollar;

·weather interference with business operations or project construction;

·risks related to the development and operation of our facilities, including our ability to satisfy our contractual obligations to our customers at our facilities;

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

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

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

Other factors described herein, as well as factors that are unknown or unpredictable, could also have a material adverse effect on future results. Please read Item 1A.1A “Risk Factors.” Except as required by applicable securities laws, we do not intend to update these forward-looking statements and information.

PART I

Items 1 and 2.  Business and Properties

General

Plains All American Pipeline, L.P. is a Delaware limited partnership formed in 1998. Our operations are conducted directly and indirectly through our primary operating subsidiaries. As used in this Form 10-K and unless the context indicates otherwise, the terms “Partnership,” “Plains,” “PAA,” “we,” “us,” “our,” “ours” and similar terms refer to Plains All American Pipeline, L.P. and its subsidiaries.

We engage in the transportation, storage, terminallingown and marketing ofoperate midstream energy infrastructure and provide logistics services for crude oil, and refined products, as well as in the processing, transportation, fractionation, storage and marketing of natural gas liquids (“NGL”)., natural gas and refined products. The term NGL includes ethane and natural gasoline products as well as propane and butane, products which are also commonly referred to as liquefied petroleum gas (“LPG”).  When used such as propane and butane. We own an extensive network of pipeline transportation, terminalling, storage, and gathering assets in this Form 10-K,key crude oil and NGL refers to all NGL products including LPG. Through our general partner interestproducing basins and majority equity ownership positiontransportation corridors and at major market hubs in PAA Natural Gas Storage, L.P. (NYSE: PNG), we also ownthe United States and operate natural gas storage facilities.Canada. Our business activities are conducted through three operating segments: Transportation, Facilities and Supply and Logistics.

Organizational History

We were formed as a master limited partnership to acquire and operate the midstream crude oil businesses and assets of a predecessor entity and completed our initial public offering in 1998.  Our 2% general partner interest is held by PAA GP LLC, a Delaware limited liability company, whose sole member is Plains AAP, L.P., a Delaware limited partnership.partnership (“AAP”). AAP also owns all of our incentive distribution rights (“IDRs”). As of December 31, 2014, Plains GP Holdings, L.P. (“PAGP”), a Delaware limited partnership that completed its initial public offering in October 2013 and that has elected to be treated as a corporation for U.S. federal income tax purposes, owned a 34.1% limited partner interest in AAP (a 31.8% economic interest), and the remaining limited partner interests in AAP were held by the owners of our general partner entities immediately prior to PAGP’s initial public offering. Plains All American GP LLC, a Delaware limited liability company (“GP LLC”), is Plains AAP, L.P.’sAAP’s general partner. PAGP is the sole member of GP LLC, and PAA GP Holdings LLC is the general partner of PAGP. References to our “general partner,” as the context requires, include any or all of PAA GP LLC, Plains AAP L.P. and Plains All American GP LLC. Plains AAP, L.P. and Plains All American GP LLC are owned by 19 holders. The five largest of these holders and their affiliates own an aggregate interest of approximately 95%. See Item 12. “Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters—Beneficial Ownership of General Partner Interest.”

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Partnership Structure and Management

Our operations are conducted directly and indirectly through, and our operating assets are owned by, our subsidiaries. Plains All American GP LLC has ultimate responsibility for conducting our business and managing our operations.operations; however, PAGP effectively controls our business and affairs through the exercise of its rights as the sole and managing member of our general partner, including its right to appoint certain members to the board of directors of our general partner. See Item 10. “Directors and Executive Officers of our General Partner and Corporate Governance.” Our general partner does not receive a management fee or other compensation in connection with its management of our business, but it is reimbursed for substantially all direct and indirect expenses incurred on our behalf (other than expenses related to the Class B units of Plains AAP L.P.which are referred to herein as the “AAP Management Units”).

The charttwo charts below depictsshow the current structure and ownership of Plains All American Pipeline, L.P.PAA and certainits subsidiaries as of February 20, 2013.December 31, 2014 in both a summarized and more detailed format.  The first chart depicts PAA’s legal structure in summary format, while the second chart depicts a more comprehensive view of PAA’s legal structure, including ownership and economic interests and shares and units outstanding.

Summarized Partnership Structure

(as of December 31, 2014)

(1)                   Board appointment rights limited to non-management investors that own greater than 10% interest in AAP.

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(1)                                     Based on Form 4 filings for executive officers and directors and other information believed to be reliable for the remaining investors, this group, or affiliates of such investors, owns approximately 20.1 million limited partner units, representing approximately 6% of all outstanding units.

(2)Incentive Distribution Rights (“IDRs”). See Item 5. “Market for Registrant’s Common Units, Related Unitholder Matters and Issuer Purchases of Equity Securities” for discussion of our general partner’s incentive distribution rights.IDRs.

(3)(2)                                     The Partnership owns approximately 64% of the equity interest in PAA Natural Gas Storage, L.P. (NYSE: PNG), including a 2% general partner interest and 62% limited partner interest, as well as incentive distribution rights. The Partnership also

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·                  We possess specialized crude oil market knowledge.  We believe our business relationships with participants in various phases of the crude oil distribution chain, from crude oil producers to refiners, as well as our own industry expertise (including our knowledge of North American crude oil flows), provide us with an extensive understanding of the North American physical crude oil markets.

·                  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 balance that generally affords us the flexibility to maintain a base level of margin in a variety of market conditions (subject to the effects of seasonality). In certain circumstances, we are able to realize incremental margins during volatile market conditions.

·                  We have the evaluation, integration and engineering skill sets and the financial flexibility to continue to pursue acquisition and expansion opportunities. Over the past fifteen years,Since 1998, we have completed and integrated over 80 acquisitions with an aggregate purchase price of approximately $10.5$11.6 billion. We have also implemented internal expansion capital projects totaling approximately $4.2over $7.8 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, 2012,2014, we had approximately $2.4$2.6 billion of liquidity available, including cash and cash equivalents and availability under our committed credit facilities, subject to continued covenant compliance.

·                  We have an experienced management team whose interests are aligned with those of our unitholders. Our executive management team has an average of 2830 years industry experience, and an average of 1618 years with us or our predecessors and affiliates. In addition, through their ownership of common units, indirect interests in our general partner, grants of phantom units and the Class B units in Plains AAP L.P.,Management Units, our management team has a vested interest in our continued success.

Financial Strategy

Targeted Credit Profile

We believe that a major factor in our continued success is our ability to maintain a competitive cost of capital and access to the capital markets. In that regard, we intend to maintain a credit profile that we believe is consistent with investment grade credit ratings. We have targeted a general credit profile with the following attributes:

·an average long-term debt-to-total capitalization ratio of approximately 50%;

·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, equity-indexed compensation plan charges, gains and losses from derivative activities and other selected items that impact comparability.  See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Results of Operations — Non-GAAP Financial Measures” for a discussion of our selected items that impact comparability and our non-GAAP measures.);

·an average total debt-to-total capitalization ratio of approximately 60%; and

·an average adjusted EBITDA-to-interest coverage multiple of approximately 3.3x or better.

The first two of these four metrics include long-term debt as a critical measure.  We also incur short-term debt in connection with our supply and logistics activities that involve the simultaneous purchase and forward sale of crude oil, NGL and natural gas. The crude oil, NGL and natural gas purchased in these transactions are hedged.  We do not consider the working capital borrowings associated with these activities to be part of our long-term capital structure. These borrowings are self-liquidating as they are repaid with sales proceeds. We also incur short-term debt to fund New York Mercantile Exchange (“NYMEX”) and Intercontinental Exchange (“ICE”) margin requirements. In certain market conditions, these routine short-term debt levels may increase significantly above baseline levels.

To maintain our targeted credit profile and achieve growth through acquisitions and expansion capital, we intend to fund approximately 55% of the capital requirements associated with these activities with equity and cash flow in excess of distributions. From time to time, we may be outside the parameters of our targeted credit profile as, in certain cases, these capital expenditures and acquisitions may be financed initially using debt or there may be delays in realizing anticipated synergies from acquisitions or contributions from expansion capital projects to adjusted EBITDA.

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Acquisitions

The acquisition of midstream assets and businesses that are strategic and complementary to our existing operations constitutes an integral component of our business strategy and growth objectives. Such assets and businesses include crude oil, related assets, refined products assets,and NGL logistics assets, and natural gas storage assets as well asand other energy transportation-related assets that have characteristics and provide opportunities similar to theseour existing business lines and enable us to leverage our assets, knowledge and skill sets.

The following table summarizes acquisitions greater than $200 million that we have completed over the past five years (in millions). See Note 3 to our Consolidated Financial Statements for a full discussion regarding our acquisition activities.

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We typically do not announce a transaction until after we have executed a definitive acquisition agreement. However, in certain cases in order to protect our business interests or for other reasons, we may defer public announcement of an acquisitiona transaction until closing or a later date. Past experience has demonstrated that discussions and negotiations regarding a potential acquisitiontransaction can advance or terminate in a short period of time. Moreover, the closing of any transaction for which we have entered into a definitive acquisition agreement willmay be subject to customary and other closing conditions, which may not ultimately be satisfied or waived. Accordingly, we can give no assurance that our current or future acquisition or investment efforts will be successful. Although we expect the acquisitions and investments we make to be accretive in the long term, we can provide no assurance that our expectations will ultimately be realized. See Item 1A. “Risk Factors—Risks Related to Our Business—If we do not make acquisitions or if we make acquisitions that fail to perform as anticipated, our future growth may be limited” and “—Our acquisition strategy involves Acquisitions involve risks that may adversely affect our business.”

Expansion Capital Projects

Our extensive asset base and our relationships with customers provide us with opportunities for organic growth through the construction of additional assets that are complementary to, and expand or extend, our existing asset base. We believe that the diversity and balance of our expansion capital project portfolio (i.e., relatively large number of projects that are small to medium sized and spread across multiple geographic regions) reduces our overall exposure to cost overruns, timing delays and other adverse market developments with respect to a particular project or region. Our 2015 expansion capital plan is representative of the diversity and balance of our overall project portfolio. The following expansion capital projects are included in our 2015 capital plan as of February 2015:

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(1)Represents the portion of the total project cost expected to be incurred during the year. Potential variation to current capital costs estimates may result from (i) changes to project design, (ii) final cost of materials and labor and (iii) timing of incurrence of costs due to uncontrollable factors such as permits, regulatory approvals and weather.

Global Petroleum Market Overview

Crude oil and NGL are two primary components of the world petroleum market, and world economic growth is a major driver of such market. The challenging global economic climate of the last several years resulted in continued uncertainty in the petroleum market. Over the last six months of 2014, global production growth outpaced global consumption growth resulting in lower energy prices. Currently, the United States comprises less thanand Canada comprise 5% of the world’s population, generatesgenerate approximately 12%20% of the world’s petroleum production, and consumesconsume approximately 21%23% of the world’s petroleum production. The following table sets forthbelow depicts historical and projected world supplyproduction and demandconsumption of liquid fuels for petroleum products (including crude oilthe United States and NGL)Canada and the rest of the world and is derived from the Energy Information Administration’s (“EIA”) AnnualEIA Short-Term Energy Outlook, 2013 Early ReleaseJanuary 2015 (see EIA website at www.eia.doe.gov):

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During the 20-year period from 1985 through 2004,Since reaching a multi-year low in 2009, U.S. net refinery demand forinputs of crude oil have slowly increased approximately 29% from approximately 12.0 million barrels per day to approximately 15.5 million barrels per day.  U.S. refinery demand for crude oil remained effectively flat from 2005 through 2007 at around 15.2 million barrels per day. Largely as a resultlevel of a major economic slowdown and recession, from 2008 to 2012 total U.S. petroleum consumption declined and refinery demand decreased, averaging approximately 15.015.8 million barrels per day for the 12 monthstwelve month period ended November 2012.  Of this amount, approximately 6.4 million barrels per day were produced domestically. Accordingly,2014, which approximates the levels achieved during 2005 and 2006. Although domestic demand for petroleum products from end users has declined from peak levels in 2004-2007 and the 12 months ended November 2012, approximately 8.6 million barrels per dayincreased use of theethanol for blending in gasoline has further negatively impacted refinery demand for crude oil, usedthe attractive export market for refined products and access to discounted domestic crude oil has driven the increased refinery demand.  Domestic production growth has also led to lower use of imported crude oil by U.S. refineries, were imported. This level of crude oil imports represents a meaningful change in a multi-year trend where foreign imports of crude oil tripled over aan approximately 23-year period from approximately 3.2 million barrels per day in 1985 to approximately 10.1 million barrels per day from 2005-2007. Reduced domestic demand for petroleum products from end users and competitive challenges faced by certain U.S. refineries with limited access to domestic feedstocks as well as increased use of ethanol for blending in gasoline have been major factors contributing to the drop in refinery demand for crude oil, partially offset by rising refined products exports.  Since 2000, ethanol production has grown from approximately 100,000 barrels per day to approximately 940,000 barrels per day for the 12 months ended November 2012.  Growth in ethanol and other renewable fuel production is expected to continue primarily due to government mandates on production.1985-2007. The EIA is currently forecasting a continued gradual decline in foreign crude imports from current levels, which is attributable to increased domestic production and increased supply from other liquid products, including ethanol and biodiesel.

The table below shows the overall domestic petroleum consumption projected out to 2020through 2016 and is derived from recent information published by the EIA Short-Term Energy Outlook, January 2015 (see EIA website at www.eia.doe.gov). The amounts in the 2012 column are based on the twelve months from December 2011 to November 2012. We believe these trends will be subject to significant variation from time to time due to a number of factors, including the level of domestic production volumes and infrastructure limitations, which impact pricing, and geopolitical developments. Based on market and industry conditions throughout 2012 and conditions in early 2013, it appears domestic crude oil and NGL production levels could exceed the EIA’s forecast over the next several years.

(1)                                         Amounts may not recalculate due to rounding.

As illustrated in the table above, while expected to decline, imports of foreign crude oil and other petroleum products are still expected to play a major role in achieving a balanced U.S. market on an aggregate basis.  However, because of the substantial number of different grades and varieties of crude oil and their distinguishing physical and economic properties and the distinct configuration of each refinery’s process units, significant logistics infrastructure and services are required to balance the U.S. market on a region by region basis.

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Table of advances in horizontal drilling and fracturing technology over the last several years and their application to various large scale resource plays, certain historical trends are being influenced.  For example, PADD II production increased beginning in 2005 and as of late 2012 is approximately 1.1 million barrels per day, nearly two and a half times 2004’s level.  This increase is being driven mainly by increased production from the Bakken oil formation in North Dakota using advanced horizontal drilling and fracturing technology.

More recently, other parts of the U.S. have experienced increased production volumes from mature producing areas such as the Rockies, the Permian Basin in West Texas, as well as less developed, but quickly growing areas such as the Eagle Ford Shale in South Texas.  Actual and anticipated production increases in multiple areas combined with actual and expected increased imports from Canada has strained or is expected to strain existing transportation and terminalling infrastructure in multiple areas.  These developments are also resulting in changes to historical trends with respect to crude oil movements among regions of the U.S.  For example, the quantity of crude oil transported from the Gulf Coast area into PADD II has declined, but the overall change in crude oil flows has resulted in an increased demand for storage and terminalling services at Cushing, Oklahoma and Patoka, Illinois.

The quality of the increasing crude oil volumes, which are generally lighter (higher gravity) and sweeter (lower sulfur content) than previous production, is exacerbating the demands placed on existing infrastructure. Notably, this change in crude oil quality is in stark contrast to the sizeable, multi-year investments made by a number of U.S. refining companies in order to expand their capabilities to process heavier, sourer grades of crude oil. This divergence between readily available supplies of light sweet crude and increased refinery demand for heavy sour crude has caused differentials between crude oil grades and qualities to change relative to historical levels and become much more dynamic and volatile.  The combination of (i) a significant increase in North American production volumes, (ii) a change in crude oil qualities and related differentials and (iii) a high utilization of existing pipeline and terminal infrastructure have stimulated multiple industry initiatives to build new pipeline and terminal infrastructure, convert certain pipeline assets to alternative service or reverse flows and expand the use of trucks, rail and barges for the movement of crude oil.Contents

Overall, volatility in variousof multiple aspects of the crude oil market, including absolute price, market structure and grade and location differentials, has increased over time and we expect this volatility to persist.continue. Some factors that we believe are causing and will continue to cause volatility in the market include:

·                  the multi-year narrowingcontinued development of the gap between supply and demand in North America;American resource plays;

·                  fluctuations in international supply and demand related to the economic environment, geopolitical events and armed conflicts;

·                  regional supply and demand imbalances and changes in refinery capacity and specific capabilities;

·                  significant fluctuations in absolute price as well as grade and location differentials;

·                  political instability in critical producing nations; and

·                  policy decisions made by various governments around the world attempting to navigate energy challenges.

The complexity and volatility of the crude oil market creates opportunities to solve the logistical inefficiencies inherent in the business.

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Table of existing refining capacity, which could generate demand for midstream infrastructure in certain areas, including pipelines and terminals.Contents

NGL Market Overview

NGL primarily includes ethane, propane, normal butane, iso-butane, and natural gasoline, and areis derived from natural gas production and processing activities as well as crude oil refining processes.  LPG primarily includes propane butane, and natural gasoline,butane, which liquefy at moderate pressures thus making it easier to transport and store such products as compared to ethane.  As discussed above, NGL refers to all NGL products including LPG when used in this document.

NGL Demand. Individual NGL products have varying uses.  Described below are the five basic NGL components and their typical uses:

·                  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.

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

·                  Normal butane. Normal butane is principally used for motor gasoline blending and as fuel gas, either alone or in a mixture with propane, and feedstock for the manufacture of ethylene and butadiene, a key ingredient of synthetic rubber. Normal butane is also used as a feedstock for iso-butane production and as a diluent in the transportation of heavy crude oil and bitumen, particularly in Canada.

·                  Iso-butane. Iso-butane is principally used by refiners to produce alkylates to enhance the octane content of motor gasoline

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NGL Storage. NGL must be stored under pressure to maintain a liquid state. The lighter the product (e.g., ethane), the greater the pressure that must be maintained. Large volumes of NGL are stored in underground caverns constructed in salt or granite. Product is also stored in above ground tanks. Natural gasoline can be stored at relatively low pressures in tankage similar to that used to store motor gasoline. Propane and butane are stored at much higher pressures in steel spheres, cylinders, bullets, salt caverns or other configurations. Ethane is stored at very high pressures, typically in salt caverns. Storage is especially important for NGL as supply and demand can vary materially on a seasonal basis.

NGL Market Outlook.  The growth of shale based production in both traditional and new producing areas has resulted in a significant increase in NGL supplies from gas processing plants are increasing rapidly due to the increased drilling activity in unconventional resource plays, where producers are targeting “liquids rich” areas to capitalize on forecasted high NGL product prices (which historically have been correlated with crude oil prices).  Numerous industry and financial analysts project NGL supply volumes will continue to grow over the nextpast several years with some analysts projecting U.S. supply volumes to increase from 2012 levels over 30% by 2016.  A significant amountyears. This has driven extensive expansion and new development of this volume is expected to come from recently discovered, unconventional resource plays which do not havemidstream infrastructure in Canada, the NGL infrastructure to process the wet natural gas or transport, fractionate,Bakken, Marcellus/Utica, and store the NGL products.  Nor are these new supply areas near historical markets for the NGL purity products.  As a resultthroughout Texas.

The growth of these dynamics, substantial incremental infrastructure is likely to be developed throughout the NGL value chain over the next several years, and traditionalproduction in non-traditional producing regions has shifted regional basis relationships could change significantly.  Aand the creation of new logistics and infrastructure opportunities. Growing NGL production has meant expansion into new markets, through exports or increased petrochemical demand.  The continuation of a relatively low ratio of North American gas and NGL prices to world-wide crude oil prices will mean North American NGL can continue to be competitive on a world scale, either as feedstock for North American based manufacturing or export to overseas markets. In addition to substantially increased exports, a portion of the increased supply of NGL will likely be absorbed by the domestic petrochemical sector as low-cost feed stocks.  In addition, growingstocks, as the North American petrochemical industry has enjoyed a supply cost advantage on a world scale.

While a short term price drop may stunt production growth, the fundamentals of Canadian heavy crude oil is likelyan accessible resource base and improved midstream infrastructure should mean producers can continue to create demand for additional diluents, primarily natural gasolinedevelop the most economic new supply and butane. The remaining product not absorbed domestically will likely drive continued growth in the NGL export market.  Duebe ready to go back to rapid increases in NGL production, thegrowth as prices of NGL (particularly ethane and propane) have been pressured downward in certain locations. It is difficult to predict when such prices may rebound but this downward pressure on prices is one of the key drivers for the new infrastructure development referred to above.recover. The NGL market is, among other things, expected to be driven by:

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

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Following is a description of the activities and assets for each of our three business segments.

Transportation Segment

Our transportation segment operations generally consist of fee-based activities associated with transporting crude oil NGL and refined productsNGL on pipelines, gathering systems, trucks and barges. We generate revenue through a combination of tariffs, third-party leases of pipeline capacity agreements and other transportation fees. Our transportation segment also includes our equity earnings from our investments in Settoon Towing and the White Cliffs, Butte, Frontier and Eagle Ford, BridgeTex, Butte and Frontier pipeline systems, in which we own noncontrolling interests.interests ranging from 22% to 50%. We account for these investments under the equity method of accounting.

As of December 31, 2012,2014, we employed a variety of owned or, to a much lesser extent, leased long-term physical assets throughout the United States and Canada in this segment, including approximately:

·                  17,40017,800 miles of active crude oil NGL and refined productsNGL pipelines and gathering systems;

·                  2329 million barrels of active, above-ground tank capacity used primarily to facilitate pipeline throughput;

·                  582800 trailers (primarily in Canada); and

·                  104149 transport and storage barges and 5172 transport tugs through our interest in Settoon Towing.

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The following is a tabular presentation of our active crude oil NGL and refined productsNGL pipeline assets in the United States and Canada as of December 31, 2012,2014, grouped by geographic location:

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

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In 2013 and 2014, we announced several new projects to increase and expand our Permian Basin infrastructure over the next few years to support expected crude oil production growth. In January 2015, we placed into service 40 miles of pipeline with 100,000 barrels per day of pipeline capacity from Monahans to Crane, Texas to supply volumes to the Longhorn pipeline as well as our Cactus pipeline when it is placed into service in 2015. Our Cactus pipeline will be a new 310-mile crude oil pipeline extending from McCamey to Gardendale, Texas and is expected to initially provide approximately 250,000 barrels per day of additional takeaway capacity from the Permian Basin. Pumping equipment will be added in 2016, which will bring the total capacity of the pipeline to approximately 330,000 barrels per day. The remainder of our projects in the area are expected to be completed in stages throughout 2015 and 2016. See “—Expansion Capital Projects” for additional information.

South Texas/Eagle Ford Area

Eagle Ford Area Systems. We own a 100% interest in and are the operator of several gathering systems that feed into our Gardendale Station, and we also own a 50% interest in and are the operator of the Eagle Ford joint venture pipeline. These Eagle Ford Area Systems consist of 470 miles of pipeline that service increasing production in the Eagle Ford shale play of South Texas and include approximately 2 million barrels of operational storage capacity across the system. The system serves the Three Rivers and Corpus Christi, Texas refineries and other markets via marine terminal facilities at Corpus Christi, as well as the Houston market via Enterprise Products Partners L.P.’s (“Enterprise”) connection at Lyssy in Wilson County, Texas. For 2014, total average throughput on our Eagle Ford Area Systems was 227,000 barrels per day (attributable to our interest).

In 2013, we and Enterprise announced an expansion of the Eagle Ford joint venture pipeline. This project will increase the pipeline’s capacity to 470,000 barrels per day by constructing a new 20-inch pipeline between Gardendale (where it will connect to our Cactus pipeline) and Three Rivers, Texas. This expansion also includes the construction of an additional 2 million barrels of operational storage capacity across the system. Additionally, in 2014 we announced the construction of a 70 mile, 20-inch pipeline from Three Rivers to Corpus Christi, and the expansion of pumping capabilities at Three Rivers. Combined, these projects will loop the entire Eagle Ford joint venture pipeline from Gardendale to Corpus Christi, and increase the total system capacity to over 600,000 barrels per day. These expansions are supported by long term production commitments. These projects are expected to be completed in 2015. See “—Expansion Capital Projects” for additional information.

In 2014, Plains and Enterprise announced a project to construct a new condensate gathering system with approximately 55 miles of gathering and trunkline pipeline that will connect Karnes County and Live Oak County production areas to the Three Rivers, Texas terminal. Included in the gathering system will be over 500,000 barrels of operational storage at Three Rivers. This construction is expected to be completed in 2015. See “—Expansion Capital Projects” for additional information.

Western

All American Pipeline System.  We own a 100% interest inand operate the All American Pipelinepipeline system. The All American Pipelinepipeline system is a common carrier crude oil pipeline system that transports crude oil produced from two outer continental shelf, or OCS, fields offshore California via connecting pipelines to refinery markets in California. The system at Las Flores receives crude oil from ExxonMobil’s Santa Ynez field while the system at GaviotaLas Flores and receives crude oil from the Plains Exploration and Production Company-operatedFreeport-McMoRan-operated Point Arguello field.  These systems both terminatefield at Gaviota. The system terminates at our Emidio Station. Between Gaviota and our Emidio Station, the All American Pipelinepipeline interconnects with our San Joaquin Valley Gathering System, Line 2000 and Line 63, as well as other third party intrastate pipelines. The system is subject to tariff rates regulated by the FERC.

A portion of our transportation segment profit on Line 63 and Line 2000 is derived from the pipeline transportation business associated with the Santa Ynez and Point Arguello fields and fields located in the San Joaquin Valley. Volumes shipped from the OCS are inexpected to decline. See Item 1A. “Risk Factors” for discussion of the estimated impact of a decline in volumes.

Line 63.  We own a 100% interest inand operate the Line 63 system. The Line 63 system is an intrastate common carrier crude oil pipeline system that transports crude oil produced in the San Joaquin Valley and California OCS to refineries and terminal facilities in the Los Angeles Basin and in Bakersfield. The Line 63 system consists of a 144-mile trunk pipeline, (of which 102 miles is 14-inch pipe and 42 miles is 16-inch pipe), originating at our Kelley Pump Station in Kern County, California and terminating at our West Hynes Station in Long Beach, California. The trunk pipeline has a capacity of approximately 110,000 barrels per day. The Line 63 system includes 5five miles of distribution pipelines in the Los Angeles Basin, with a throughput capacity of approximately 144,000 barrels per day, and 148approximately 140 miles of gathering pipelines in the San Joaquin Valley, with aan average throughput capacity of approximately 72,000 barrels per day. We also have approximately 1 million barrels of storage capacity on this system. These storage assets are used primarily to facilitate the transportation of crude oil on the Line 63 system. For 2014, combined throughput on Line 63 totaled an average of 48,000 barrels per day.

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During the fourth quarter of 2009, a 71-mile segment of Line 63 was temporarily taken out of service to allow for certain repairs and realignments to be performed. Line 63 volumes are currently being redirected from the north end of this out-of-service segment to the parallel Line 2000. The product is then batched along Line 2000 until it is re-injected into the active portion of Line 63, which is south of the out-of-service segment, for subsequent delivery to customers. This temporary pipeline segment closure and redirection of product has not impacted our normal throughput levels on this line. In 2013, weWe have commenced a project to place this idle segment into service. Weservice, which we expect the project to be completed by July 2014. For 2012, combined throughputcomplete in 2015. In December 2014, we commenced receipts on Line 63 totaled an average of approximately 66,000 barrels per day.crude oil from our rail terminal at Bakersfield.

Line 2000.  We own and operate 100% of Line 2000, an intrastate common carrier crude oil pipeline that originates at our Emidio Pump Station (part of the All American Pipeline System)system) and transports crude oil produced in the San Joaquin Valley and California OCS to refineries and terminal facilities in the Los Angeles Basin. Line 2000 is aan approximately 130-mile, 20-inch trunk pipeline with a throughput capacity of approximately 130,000 barrels per day. During 2012,2014, throughput on Line 2000 (excluding Line 63 volumes) averaged approximately 62,00074,000 barrels per day.

Rocky Mountain

Bakken Area Systems. We own and operate the Baker, Trenton and Whitetailseveral gathering systems as well asand pipelines that service crude oil production in Eastern Montana and Western North Dakota, and we also own a 22% interest in the Robinson Lake andButte pipeline. These Bakken North pipelines. The gatheringArea systems consist of 9191,025 miles of pipelines and transported approximately 96,000pipeline, with total average throughput for 2014 of 149,000 barrels per day for 2012. The Robinson Lake pipeline was acquired in December 2010 and consists of 35 miles of 8-inch pipeline with throughput capacity of up to 60,000 barrels per day. For 2012, throughput on the Robinson Lake pipeline was approximately 34,000 barrels per day. During 2012, we completed construction of our Bakken North Pipeline System, a 80-mile, 12-inch crude oil pipeline with an initial design capacity of approximately 50,000 barrels that extends from Trenton, North Dakota to the southern end of our currently idle Wascana Pipeline. The Wascana Pipeline reversal is pending connection to a third-party pipeline, which is expected to occur during mid-2013.

Salt Lake City Area Systems.  We operate the Salt Lake City and Wahsatch pipeline systems, in which we own interests of between 75% and 100%.  These systems include interstate and intrastate common carrier crude oil pipeline systems that transport crude oil produced in Canada and the U.S. Rocky Mountain region and Canada to refiners in Salt Lake City, Utah and to other pipelines at Ft. Laramie, Wyoming. These pipeline systems consist of 693680 miles of pipelines and approximately 1one million barrels of storage capacity. These systems have a maximum throughput capacity of (i) approximately 20,000 barrels per day from Wamsutter, Wyoming to Ft. Laramie, Wyoming, (ii) approximately 49,000 barrels per day from Wamsutter, Wyoming to Wahsatch, Utah and (iii) approximately 120,000 barrels per day from Wahsatch, Utah to Salt Lake City, Utah.  For 2012,2014, throughput on the Salt Lake City and Wahsatch pipelinethese systems (excluding Frontier Pipeline) in total averaged approximately 140,000128,000 barrels per day.

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Central

Mid-Continent Area Systems. We own and operate pipeline systems that source crude oil from the Cleveland Sand, Granite Wash and Mississippian/Lime resource plays of Western and Central Oklahoma, Southwest Kansas and the eastern Texas Panhandle. These systems consist of approximately 2,0002,345 miles of pipeline with transportation and delivery into and out of our terminal facilities at Cushing. For 2012,2014, combined throughput on the Mid-Continent Area systems totaled an average of approximately 249,000348,000 barrels per day.

In January 2012,2014, we completed the conversionconstruction of ana 113-mile extension of our existing Oklahoma NGL pipeline into crude oil service. The pipeline extendsand associated gathering system to service increasing production from Medford,producing areas in Western Oklahoma and the Texas Panhandle. This new Western Oklahoma pipeline provides up to 75,000 barrels per day of new takeaway capacity from Reydon, Oklahoma to our terminal facility at Cushing. The pipeline provided an initial crude oil throughput capacity of 12,000 barrels per day and was expanded to 25,000 barrels per dayexisting Orion station in July 2012.Major County, Oklahoma.

In 2012, we began construction on a new 170-mileIncluded in the Mid-Continent Area systems is our Mississippian Lime pipeline, which was placed into service in August 2013 to service the increasing Mississippian Lime crude oil production in northernNorthern Oklahoma and Southern Kansas. This pipeline is designedKansas and to provide approximately 150,000 barrels per day (approximately 175,000 barrels per day in conjunction with the Medford-to-Cushing pipeline conversion) of crude oil transportation to our terminal facilities at Cushing. ThisDuring 2014, we completed two extensions of the Mississippian Lime pipeline. Throughput on the Mississippian Lime pipeline is expected to go into service by mid-2013.  In early 2013, we announcedaveraged 71,000 barrels per day during 2014.

We are currently developing the Diamond pipeline, a 55-mile extension of this20-inch, 440-mile long pipeline whichthat will provide up to 75,000200,000 barrels per day of crude oil throughput capacity from our Cushing, Oklahoma terminal to the Valero Memphis, Tennessee refinery. The Diamond pipeline project is underpinned by a long term shipper agreement with Valero and a related contract for storage and terminalling services at our Cushing terminal. We expect to complete the Diamond pipeline in 2017. Valero holds an option until January 2016 to become a partner in the Diamond pipeline and purchase a 50 percent interest.

Also under development is the Red River pipeline, which will be a 16-inch pipeline with a takeaway capacity of 150,000 barrels per day extending from Cushing, Oklahoma to Longview, Texas. The Red River pipeline is supported by a long-term commitment from an area producer. This extensionlong term shipper commitments and is expected to be brought into servicecompleted in the fourth quarter of 2013.2016. See “—Expansion Capital Projects” for additional information regarding our Mid-Continent area pipeline projects.

United States Refined Products Pipelines

We own and operate pipeline systems of approximately 900 miles that receive and deliver refined products throughout Wyoming, South Dakota, Colorado, New Mexico and Texas. Total average throughput on these systems during 2012 was approximately 116,000 barrels per day. In February 2013, we signed a definitive agreement to sell certain of these refined products pipeline systems and related assets.  We expect the transaction to close during the second quarter of 2013.  See Notes 3 and 6 to our Consolidated Financial Statements for further discussion regarding these assets.

Canada Pipelines

Crude Oil Pipelines

Manito.  We own a 100% interest in the Manito heavy oil system. This 555-mile561-mile system is comprised of the Manito pipeline, the North SaskSaskatchewan (“North Sask”) pipeline and the Bodo/Cactus Lake pipeline. Each system consists of a blended crude oil line and a parallel diluent line whichthat delivers condensate to upstream blending locations. The North Sask pipeline is 84 miles in length and originates near Turtleford, Saskatchewan and terminates in Dulwich, Saskatchewan. The Manito pipeline includes 334339 miles of pipeline, and the mainline segment originates at Dulwich and terminates at Kerrobert, Saskatchewan. The Bodo/Cactus Lake pipeline is 137138 miles long

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Rangeland System.  We own a 100% interest in the Rangeland system. The Rangeland system consists of a 670 mile, 8-inch to 16-inch mainline pipeline and 675563 miles of 3-inch to 8-inch gathering pipelines. The Rangeland system transports NGL mix, butane, condensate, light sweet crude oil and light sour crude oil either north to Edmonton, Alberta or south to the U.S./Canadian border near Cutbank, Montana, where it connects to our Western Corridor system. Total average throughput during 20122014 on the Rangeland system was approximately 62,00065,000 barrels per day.

South Saskatchewan. We own a 100% interest in the South Saskatchewan system. This system consists of a 160 mile, 16-inch mainline from Cantuar to Regina, Saskatchewan and 186 miles of 4-inch to 12-inch gathering pipelines from the Rapdan area to Cantuar. The South Saskatchewan system transports heavy crude oil from gathering areas in southern Saskatchewan to Enbridge’s mainline at Regina. Total average throughput during 2014 on the South Saskatchewan system was 63,000 barrels per day.

NGL Pipelines

Co-Ed NGL Pipeline System.  As part of the BP NGL acquisition completed during the first half of 2012, we became 100% ownersWe own and operators ofoperate the Co-Ed NGL Pipeline System.  The Co-Ed NGLpipeline system, which consists of approximately 813632 miles of 3-inch to 10-inch pipeline. This pipeline system gathers NGL from approximately 35 field gas processing plants located in the Cochrane, Alberta, to Edmonton, Alberta region, as well as gathersincluding all of the NGL produced at the Cochrane Straddle Plant. The Co-Ed NGL pipeline system has throughput capacity of approximately 72,000 barrels per day. During 2012,2014, throughput averaged approximately 44,00058,000 barrels per day.

We are currently extending and expanding our Co-Ed NGL pipeline system. The projects consist of a North Co-Ed extension and a West Co-Ed expansion, which we expect to be completed in 2016 and 2017, respectively. The North Co-Ed extension will provide approximately 20 miles of bi-directional 12-inch high vapor pressure (HVP) NGL pipeline from our existing Co-Ed pipeline to our Fort Saskatchewan facilities with takeaway capacity of up to 110,000 barrels per day. The West Co-Ed expansion will provide an 8-inch, 18 mile NGL line from our Buck Creek facility to our Co-Ed pipeline at Breton, Alberta.

Facilities Segment

Our facilities segment operations generally consist of fee-based activities associated with providing storage, terminalling and throughput services for crude oil, refined products, NGL and natural gas, as well as NGL fractionation and isomerization services and natural gas and condensate processing services. We generate revenue through a combination of month-to-month and multi-year leasesagreements and processing arrangements. Revenues generated in this segment primarily include (i) storage fees that are generated when we leasefrom storage capacity agreements, (ii) terminal throughput fees that are generated when we receive crude oil, refined products or NGL from one connecting source and redeliverdeliver the applicable product to another connecting carrier, (iii) loading and unloading fees at our rail terminals, (iv) hub servicefees from NGL fractionation and isomerization, (v) fees from natural gas and condensate processing services and (vi) fees associated with natural gas park and loan activities, interruptible storage services and wheeling and balancing services, (v) revenues from the sale of natural gas, (vi) fees from NGL fractionation and isomerization and (vii) fees from gas processing services.

As of December 31, 2012,2014, we owned, operated or employed a variety of long-term physical assets throughout the United States and Canada in this segment, including:

·                  approximately 7473 million barrels of crude oil and refined products storage capacity primarily at our terminalling and storage locations;

·                  approximately 2223 million barrels of NGL storage capacity;

·                  approximately 9397 Bcf of natural gas storage working capacity;

·                  approximately 1629 Bcf of owned base gas in storage facilities owned by us;gas;

·                  eleven11 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 80,000 barrels per day;

·                  seven fractionation plants located throughout Canada and the United States with an aggregate gross processing capacity of approximately 272,100221,800 barrels per day, and an isomerization and fractionation facility in California with an aggregate processing capacity of approximately 14,000 barrels per day;

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approximately 1,400 milesTable of active crude oil, NGL, natural gas and refined products pipelines that support our facilities assets; andContents

·                  2326 crude oil and NGL rail terminals located throughout the United States and Canada. See “Rail“-Major Facilities Assets - Rail Facilities” below for an overview of various terminals and “Supply and Logistics” regarding our use of railcars.railcars;

20·six major marine facilities in the United States with an aggregate load capacity of 91,500 barrels per hour, including vapor recovery rates, and an aggregate unload capacity of 160,500 barrels per hour; and