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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

Form 10-K

 

(Mark One)

 

x

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

 

For the fiscal year ended December 31, 2012

 

or

 

o

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

 

Commission file number 1-14569

 

PLAINS ALL AMERICAN PIPELINE, L.P.

(Exact name of registrant as specified in its charter)

 

Delaware

 

76-0582150

(State or other jurisdiction of

 

(I.R.S. Employer

incorporation or organization)

 

Identification No.)

 

333 Clay Street, Suite 1600, Houston, Texas

 

77002

(Address of principal executive offices)

 

(Zip Code)

 

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

 

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

 

 

Title of Each Class

 

Name of Each Exchange on Which Registered

 

 

Common Units

 

New York Stock Exchange

 

 

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):

 

Large Accelerated Filer x

 

Accelerated Filer o

 

 

 

Non-Accelerated Filer o

 

Smaller Reporting Company o

(Do not check if a smaller reporting company)

 

 

 

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 billion on June 30, 2012, based on a closing price of $80.81 per Common Unit as reported on the New York Stock Exchange on such date.

 

As of February 20, 2013, there were 336,152,761 Common Units outstanding.

 

DOCUMENTS INCORPORATED BY REFERENCE

NONE

 

 

 



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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

FORM 10-K—2012 ANNUAL REPORT

Table of Contents

 

 

 

Page

 

PART I

4

Items 1 and 2.

Business and Properties

4

Item 1A.

Risk Factors

41

Item 1B.

Unresolved Staff Comments

58

Item 3.

Legal Proceedings

58

Item 4.

Mine Safety Disclosures

59

 

PART II

60

Item 5.

Market for Registrant’s Common Units, Related Unitholder Matters and Issuer Purchases of Equity Securities

60

Item 6.

Selected Financial Data

61

Item 7.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

63

Item 7A.

Quantitative and Qualitative Disclosures About Market Risk

88

Item 8.

Financial Statements and Supplementary Data

90

Item 9.

Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

90

Item 9A.

Controls and Procedures

90

Item 9B.

Other Information

90

 

PART III

91

Item 10.

Directors and Executive Officers of Our General Partner and Corporate Governance

91

Item 11.

Executive Compensation

102

Item 12.

Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters

120

Item 13.

Certain Relationships and Related Transactions, and Director Independence

124

Item 14.

Principal Accountant Fees and Services

127

 

PART IV

128

Item 15.

Exhibits and Financial Statement Schedules

128

 

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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;

 

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

 

·                  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;

 

·                  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. “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, terminalling and marketing of crude oil and refined products, as well as in the processing, transportation, fractionation, storage and marketing of natural gas liquids (“NGL”).  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 in this Form 10-K, NGL refers to all NGL products including LPG. Through our general partner interest and majority equity ownership position in PAA Natural Gas Storage, L.P. (NYSE: PNG), we also own and operate natural gas storage facilities. 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. Plains All American GP LLC, a Delaware limited liability company, is Plains AAP, L.P.’s general partner. 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 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. 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.).

 

The chart below depicts the current structure and ownership of Plains All American Pipeline, L.P. and certain subsidiaries as of February 20, 2013.

 

GRAPHIC

 


(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.

 

(3)                                     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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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”).

 

(4)                                     The Partnership holds indirect equity interests in unconsolidated entities including Settoon Towing, LLC (“Settoon Towing”), White Cliffs Pipeline, LLC (“White Cliffs”), Butte Pipe Line Company (“Butte”), Frontier Pipeline Company (“Frontier”) and Eagle Ford Pipeline LLC (“Eagle Ford Pipeline”).

 

Business Strategy

 

Our principal business strategy is to provide competitive and efficient midstream transportation, terminalling, storage, processing, fractionation and supply and logistics services to our producer, refiner and other customers. Toward this end, we endeavor to address regional supply and demand imbalances for crude oil, NGL, natural gas and refined products in the United States and Canada by combining the strategic location and capabilities of our transportation, terminalling, storage, processing and fractionation assets with our extensive supply, logistics and distribution expertise.

 

We believe successful execution of this strategy will enable us to generate sustainable earnings and cash flow. We intend to manage and grow our business by:

 

·                  optimizing our existing assets and realizing cost efficiencies through operational improvements;

 

·                  using our transportation (including pipeline, rail, barge and truck), terminalling, storage, processing and fractionation assets in conjunction with our supply and logistics activities to capitalize on inefficient energy markets and to address physical market imbalances, mitigate inherent risks and increase margin;

 

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

 

·                  selectively pursuing strategic and accretive acquisitions that complement our existing asset base and distribution capabilities; and

 

·                  capitalizing on the anticipated long-term growth in demand for natural gas storage services in North America by owning and operating high-quality natural gas storage facilities and providing our current and future customers reliable, competitive and flexible natural gas storage and related services through our ownership interest in PNG.

 

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 45% to 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 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

 

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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 IntercontinentalExchange (“ICE”) margin requirements. In certain market conditions, these routine short-term debt levels may increase significantly above baseline levels.

 

In order for us to maintain our targeted credit profile and achieve growth through internal growth projects and acquisitions, we intend to fund 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 capital expansion projects to adjusted EBITDA.

 

Competitive Strengths

 

We believe that the following competitive strengths position us to successfully execute our principal business strategy:

 

·                  Many of our transportation segment and facilities segment 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 oil producing regions and transportation corridors and are connected, directly or indirectly, with our facilities segment assets 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. Our assets include pipeline, rail, barge and truck assets, which provide our customers and us with significant flexibility and optionality to satisfy demand and balance markets, particularly during a dynamic period of changing product flows.

 

·                  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, 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, we have completed and integrated over 80 acquisitions with an aggregate purchase price of approximately $10.5 billion. We have also implemented internal expansion capital projects totaling approximately $4.2 billion. In addition, we believe we have resources to finance future strategic expansion and acquisition opportunities. As of December 31, 2012, we had approximately $2.4 billion available 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 28 years industry experience, and an average of 16 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., our management team has a vested interest in our continued success.

 

Acquisitions

 

The acquisition of 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, NGL assets and natural gas storage assets, as well as other energy transportation-related assets that have characteristics and opportunities similar to these 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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Approximate

 

Acquisition

 

Date

 

Description

 

Purchase Price (1)

 

US Development Group Crude Oil Rail Terminals (“USD”)

 

Dec-2012

 

Four operating crude oil rail terminals and one terminal under development

 

$

503

 

BP Canada Energy Company (“BP NGL”)

 

Apr-2012

 

NGL assets located in Canada and the upper-Midwest United States (“BP NGL Acquisition”)

 

$

1,683

(2)

Western Refining, Inc. Pipeline and Storage Assets (“Western”)

 

Dec-2011

 

Multi-product storage facility in Virginia and crude oil pipeline in southeastern New Mexico

 

$

220

(3)

Velocity South Texas Gathering, LLC (“Velocity”)

 

Nov-2011

 

Crude oil and condensate gathering and transportation assets in South Texas (“Gardendale Gathering System”)

 

$

349

 

SG Resources Mississippi, LLC (“SG Resources”)

 

Feb-2011

 

Southern Pines Energy Center (“Southern Pines”) natural gas storage facility

 

$

765

(4)

Nexen Holdings U.S.A. Inc. Gathering and Transportation Assets (“Nexen”)

 

Dec-2010

 

Crude oil gathering business and transportation assets in North Dakota and Montana

 

$

229

(5)

PAA Natural Gas Storage, LLC (“PNGS”)

 

Sep-2009

 

Remaining 50% interest in PNGS

 

$

215

(6)

Rainbow Pipe Line Company, Ltd. (“Rainbow”)

 

May-2008

 

Crude oil gathering and transportation assets in Alberta, Canada

 

$

687

(7)

 


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

(2)                                     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.

(3)                                     Includes two transactions with Western.

(4)                                     Acquisition made by our subsidiary, PNG. Approximate purchase price of $750 million, net of cash and other working capital acquired.

(5)                                     Approximate purchase price of $170 million, net of cash, inventory and other working capital acquired.

(6)                                     In connection with the PNGS acquisition we consolidated and subsequently refinanced approximately $450 million of previously non-recourse joint venture debt.

(7)                                     Approximate purchase price of $544 million, net of linefill acquired.

 

Ongoing Acquisition Activities

 

Consistent with our business strategy, we are continuously engaged in discussions with potential sellers regarding the possible purchase of assets and operations that are strategic and complementary to our existing operations. In addition, we have in the past evaluated and pursued, and intend in the future to evaluate and pursue, other energy-related assets that have characteristics and opportunities similar to our existing business lines and enable us to leverage our assets, knowledge and skill sets. Such acquisition efforts may involve participation by us in processes that have been made public and involve a number of potential buyers, commonly referred to as “auction” processes, as well as situations in which we believe we are the only party or one of a limited number of potential buyers in negotiations with the potential seller. These acquisition efforts often involve assets which, if acquired, could have a material effect on our financial condition and results of operations.

 

We typically do not announce a transaction until after we have executed a definitive acquisition agreement. However, in certain cases in order to protect our business interests or for other reasons, we may defer public announcement of an acquisition until closing or a later date. Past experience has demonstrated that discussions and negotiations regarding a potential acquisition 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 will 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 efforts will be successful. Although we expect the acquisitions 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 risks that may adversely affect our business.”

 

Global Petroleum Market Overview

 

The United States comprises less than 5% of the world’s population, generates approximately 12% of the world’s petroleum production, and consumes approximately 21% of the world’s petroleum production. The following table sets forth projected world supply and demand for petroleum products (including crude oil and NGL) and is derived from the Energy Information Administration’s (“EIA”) Annual Energy Outlook 2013 Early Release (see EIA website at www.eia.doe.gov):

 

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Projected (2)

 

 

 

2012 (1)(2)

 

2013

 

2014

 

2015

 

2020

 

 

 

(In millions of barrels per day)

 

Supply

 

 

 

 

 

 

 

 

 

 

 

OECD (3)

 

 

 

 

 

 

 

 

 

 

 

U.S.

 

11.0

 

11.5

 

12.3

 

12.5

 

13.1

 

Other

 

11.5

 

11.6

 

11.4

 

11.2

 

11.0

 

Total OECD

 

22.5

 

23.1

 

23.7

 

23.7

 

24.0

 

Organization of the Petroleum Exporting Countries

 

36.5

 

35.5

 

35.8

 

36.7

 

39.8

 

Other

 

30.0

 

31.8

 

32.0

 

32.8

 

35.9

 

Total World Production (4)

 

89.0

 

90.5

 

91.4

 

93.2

 

99.7

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Projected (2)

 

 

 

2012 (1)(2)

 

2013

 

2014

 

2015

 

2020

 

 

 

(In millions of barrels per day)

 

Demand

 

 

 

 

 

 

 

 

 

 

 

OECD

 

 

 

 

 

 

 

 

 

 

 

U.S.

 

18.6

 

18.8

 

19.1

 

19.5

 

19.8

 

Other

 

27.4

 

26.7

 

26.9

 

26.9

 

28.0

 

Total OECD

 

46.0

 

45.5

 

46.0

 

46.4

 

47.9

 

Other

 

43.2

 

44.3

 

45.4

 

46.8

 

51.9

 

Total World Consumption (4)

 

89.2

 

89.7

 

91.4

 

93.2

 

99.7

 

 

 

 

 

 

 

 

 

 

 

 

 

U.S. Production as % of World Production

 

12

%

13

%

13

%

13

%

13

%

U.S. Consumption as % of World Consumption

 

21

%

21

%

21

%

21

%

20

%

Net U.S. (Consumption)

 

(7.5

)

(7.3

)

(6.9

)

(7.0

)

(6.8

)

 


(1)                                     The 2012 amounts are derived from the EIA’s Short-Term Energy Outlook.

 

(2)                                     Amounts may not recalculate due to rounding.

 

(3)                                     Organization for Economic Co-operation and Development.

 

(4)                                     Production and consumption may not equal in every year due to inventory builds or draws.

 

World economic growth is a driver of the world petroleum market. The challenging global economic climate of the last several years has resulted in continued uncertainty in the petroleum market. To the extent that an event causes weaker world economic growth, energy demand would likely decline and could result in lower energy prices, depending on the production responses of producers.

 

Crude Oil Market Overview

 

The definition of a commodity is a “mass-produced unspecialized product” and implies the attribute of fungibility. Crude oil is typically referred to as a commodity; however, it is neither unspecialized nor fungible. The crude slate available to U.S. and world-wide refineries consists of a substantial number of different grades and varieties of crude oil. Each crude grade has distinguishing physical properties. For example, specific gravity (generally referred to as light or heavy), sulfur content (generally referred to as sweet or sour) and metals content, along with other characteristics, collectively result in varying economic attributes. In many cases, these factors result in the need for such grades to be batched or segregated in the transportation and storage processes, blended to precise specifications or adjusted in value.

 

The lack of fungibility of the various grades of crude oil creates logistical transportation, terminalling and storage challenges and inefficiencies associated with regional volumetric supply and demand imbalances. These logistical inefficiencies are created as certain qualities of crude oil are indigenous to particular regions or countries. Also, each refinery has a distinct configuration of process units designed to handle particular grades of crude oil. The relative yields and the cost to obtain, transport and process the crude oil drives the refinery’s choice of feedstock. In addition, from time to time, natural disasters and geopolitical factors such as hurricanes, earthquakes, tsunamis, inclement weather, labor strikes, refinery disruptions, embargoes and armed conflicts may impact supply, demand and transportation and storage logistics.

 

Our assets and our business strategy are designed to serve our producer and refiner customers by addressing regional crude oil supply and demand imbalances that exist in the United States and Canada.  The nature and extent of these imbalances change from time to time as a result of a variety of factors, including regional production declines and/or increases; refinery expansions, modifications and shut-downs; available transportation and storage capacity; and government mandates and related regulatory factors.

 

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During the 20-year period from 1985 through 2004, U.S. refinery demand for crude oil 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 result of a major economic slowdown and recession, from 2008 to 2012 total U.S. petroleum consumption declined and refinery demand decreased, averaging approximately 15.0 million barrels per day for the 12 months ended November 2012.  Of this amount, approximately 6.4 million barrels per day were produced domestically. Accordingly, for the 12 months ended November 2012, approximately 8.6 million barrels per day of the crude oil used 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 a 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.  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 2020 and is derived from recent information published by the EIA (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.

 

 

 

Actual (1)

 

Projected (1)

 

 

 

2012

 

2013

 

2014

 

2015

 

2020

 

 

 

(In millions of barrels per day)

 

Supply

 

 

 

 

 

 

 

 

 

 

 

Domestic Crude Oil Production

 

6.4

 

6.8

 

7.2

 

7.3

 

7.5

 

Net Imports - Crude Oil

 

8.6

 

8.0

 

7.3

 

7.3

 

6.8

 

Crude Oil Input to Domestic Refineries

 

15.0

 

14.9

 

14.5

 

14.6

 

14.3

 

 

 

 

 

 

 

 

 

 

 

 

 

Product Imports

 

1.9

 

2.1

 

2.7

 

2.7

 

2.7

 

Product Exports

 

(2.8

)

(2.9

)

(3.2

)

(3.2

)

(2.8

)

Net Product Imports / (Exports)

 

(0.9

)

(0.8

)

(0.5

)

(0.4

)

(0.1

)

 

 

 

 

 

 

 

 

 

 

 

 

Supply from Renewable Sources

 

0.9

 

1.0

 

1.1

 

1.1

 

1.2

 

Other - (NGL Production, Refinery Processing Gain)

 

3.6

 

3.7

 

4.1

 

4.2

 

4.5

 

Total Domestic Petroleum Consumption

 

18.6

 

18.8

 

19.1

 

19.5

 

19.8

 

 


(1)                                     Amounts may not recalculate due to rounding.

 

As illustrated in the table above, imports of foreign crude oil and other petroleum products 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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By way of illustration, the Department of Energy segregates the United States into five Petroleum Administration Defense Districts (“PADDs”), which are used by the energy industry for reporting statistics regarding crude oil supply and demand. The table below sets forth supply, demand and shortfall information for each PADD for the twelve months ended November 2012 and is derived from information published by the EIA (see EIA website at www.eia.doe.gov):

 

 

 

Regional

 

Refinery

 

Supply

 

Petroleum Administration Defense District (in millions of barrels per day) (1)

 

Supply

 

Demand

 

Shortfall

 

PADD I (East Coast)

 

0.0

 

0.9

 

(0.9

)

PADD II (Midwest)

 

1.1

 

3.4

 

(2.4

)

PADD III (South)

 

3.7

 

7.8

 

(4.0

)

PADD IV (Rockies)

 

0.4

 

0.6

 

(0.1

)

PADD V (West Coast)

 

1.1

 

2.3

 

(1.2

)

Total U.S.

 

6.4

 

15.0

 

(8.6

)

 


(1)            Amounts may not recalculate or cross-foot due to rounding.

 

As a result 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.

 

Overall, volatility in various 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. Some factors that we believe are causing and will continue to cause volatility in the market include:

 

·                  the multi-year narrowing of the gap between supply and demand in North America;

 

·                  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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Refined Products Market Overview

 

After transport to a refinery, the crude oil is processed into different petroleum products. These “refined products” fall into three major categories: transportation fuels such as motor gasoline and distillate fuel oil (diesel fuel and jet fuel); finished non-fuel products such as solvents, lubricating oils and asphalt; and feedstocks for the petrochemical industry such as naphtha and various refinery gases. Demand is greatest for transportation fuels, particularly motor gasoline.

 

The characteristics of the gasoline produced depend upon the setup of the refinery at which it is produced. Gasoline characteristics are also impacted by other ingredients that may be blended into it, such as ethanol and octane enhancers. The performance of the gasoline must meet strictly defined industry standards and environmental regulations that vary based on season and location.

 

After crude oil is refined into gasoline and other petroleum products, the products are distributed to consumers. The majority of products are shipped by pipeline to storage terminals near consuming areas, and then loaded into trucks for delivery to gasoline stations and end users. Products that are used as feedstocks are typically transported by pipeline or barges to chemical plants.

 

Demand for refined products has generally been affected by price levels, economic growth trends, conservation, fuel efficiency mandates and, to a lesser extent, weather conditions. According to the EIA, petroleum consumption in the United States rose from approximately 15.7 million barrels per day in 1985 to an average of approximately 20.7 million barrels per day during the four-year period ending with 2007.  From 2008 through the 12 months ended November 2012, petroleum consumption averaged approximately 19.0 million barrels per day, an approximate 8% decrease from peak levels, largely due to the economic weakness.  Given this decreased demand for refined products, the increased use of ethanol and other renewable fuels and the resulting excess refining capacity, a number of U.S. refineries reduced output and, in some cases, indefinitely shut-down. The EIA is currently forecasting growth in overall refined product demand to increase marginally over the next decade.

 

The level of future domestic demand generally will be influenced by economic conditions as well as the absolute prices of the products. Counteracting the impact of decreased domestic refined product demand on many U.S. refineries has been the combination of a significant decrease in refined product imports and a significant increase in refined product exports.  Refined product imports decreased from 3.2 million barrels per day in 2005 to an average of approximately 1.9 million barrels per day for the twelve months ended November 2012.  Conversely, refined product exports increased from approximately 1.1 million barrels per day in 2005 to 2.8 million barrels per day for the twelve months ended November 2012.  We believe that potential demand growth will be met primarily by the increase in mandated alternative fuels and increased utilization of existing refining capacity, which could generate demand for midstream infrastructure in certain areas, including pipelines and terminals.

 

NGL Market Overview

 

NGL primarily includes ethane, propane, normal butane, iso-butane, and natural gasoline, and are derived from natural gas production and processing activities as well as crude oil refining processes.  LPG primarily includes propane, butane, and natural gasoline, 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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·                  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.

 

NGL Supply. The bulk (approximately 79%) of the U.S. NGL supply comes from gas processing plants, which separate a mixture of NGL from the dry gas (primarily methane). The NGL mix (also referred to as “Y Grade”) is then either fractionated at the processing site into the five individual NGL components (known as purity products), which may be transported, stored and sold to end use markets or transported as a Y-Grade to a regional fractionation facility.

 

The majority of gas processing plants in the U.S. are located along the Gulf Coast, in the West Texas/Oklahoma area and in the Rockies region. Smaller gas processing regions are located in Michigan and Illinois as well as the Marcellus region (which is expanding rapidly) and Southern California. In Canada, the vast majority of the processing capacity is located in Alberta, with a much smaller (but increasing) amount in British Columbia.

 

NGL products from refineries represent approximately 15% of U.S. supply and are by-products of the refinery conversion processes.  Consequently, they have generally already been separated into individual components and do not require further fractionation. NGL products from refineries are principally propane, with lesser amounts of butane, refinery naphthas (products similar to natural gasoline) and ethane.  Due to refinery maintenance schedules and seasonal demand considerations, refinery production of propane and butane varies on a seasonal basis.

 

NGL are also imported into certain regions of the U.S. from Canada and other parts of the world (approximately 6% of total supply). NGL (primarily propane) are also exported from certain regions of the United States.

 

NGL Transportation and Trading Hubs. NGL, whether as a mixture or as purity products, are transported by pipelines, barges, railcars and tank trucks. The method of transportation used depends on, among other things, the resources of the transporter, the locations of the production points and the delivery points, cost-efficiency and the quantity of product being transported. Pipelines are generally the most cost-efficient mode of transportation when large, consistent volumes of product are to be delivered.

 

The major NGL infrastructure and trading hubs in North America are located at Mont Belvieu, Texas; Conway, Kansas; Edmonton, Alberta; and Sarnia, Ontario. Each of these hubs contains a critical mass of infrastructure, including fractionators, storage, pipelines and access to end markets, particularly Mont Belvieu.  In addition, there are several other production hubs, including Empress, Alberta and Hobbs, New Mexico. The West Virginia/Western Pennsylvania area is also rapidly developing as a meaningful NGL infrastructure hub.

 

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 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.  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 next several years with some analysts projecting U.S. supply volumes to increase from 2012 levels over 30% by 2016.  A significant amount of this volume is expected to come from recently discovered, unconventional resource plays which do not have the NGL infrastructure to process the wet natural gas or transport, fractionate, and store the NGL products.  Nor are these new supply areas near historical markets for the NGL purity products.  As a result of these dynamics, substantial incremental infrastructure is likely to be developed throughout the NGL value chain over the next several years, and traditional regional basis relationships could change significantly.  A portion of the increased supply of NGL will likely be absorbed by the domestic petrochemical sector as low-cost feed stocks.  In addition, growing production of Canadian heavy crude oil is likely to create demand for additional diluents, primarily natural gasoline and butane. The remaining product not absorbed domestically will likely drive continued growth in the NGL export market.  Due to rapid increases in NGL production, the 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.  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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·                  drilling activity and wet natural gas production in developing liquids-rich production areas;

 

·                  production growth/decline rates of wet natural gas in established supply areas;

 

·                  available processing, fractionation, storage and transportation capacity;

 

·                  infrastructure development costs and timing as well as development risk sharing;

 

·                  the cost of acquiring rights from producers to process their gas;

 

·                  petro-chemical demand;

 

·                  diluent requirements for heavy Canadian oil;

 

·                  international demand for NGL products;

 

·                  regulatory changes in gasoline specifications affecting demand for butane;

 

·                  refinery shut downs;

 

·                  alternating needs of refineries to store and blend NGL;

 

·                  seasonal shifts in weather; and

 

·                  inefficiencies caused by regional supply and demand imbalances.

 

As a result of these and other factors, the NGL market is complex and volatile, which along with expected market growth creates opportunities to solve the logistical inefficiencies inherent in the business.

 

Natural Gas Storage Market Overview

 

North American natural gas storage facilities provide a staging and warehousing function for seasonal swings in demand relative to supply, as well as an essential reliability cushion against disruptions in natural gas supply, demand and transportation by allowing natural gas to be injected into, withdrawn from or warehoused in such storage facilities as dictated by market conditions. Natural gas storage (and to a lesser extent imported natural gas from Canada) serves as the “shock absorber” that balances the market, serving as a source of supply to meet the consumption demands in excess of daily production capacity and a warehouse for gas production in excess of daily demand during low demand periods.

 

The market for natural gas storage services in the United States is driven by:

 

·                  the long-term supply and demand for natural gas and the overall lack of balance between the supply of and demand for natural gas on a seasonal, monthly, daily or hourly basis;

 

·                  natural gas demand from seasonal or weather-sensitive end-users such as gas-fired power generators and residential and commercial consumers;

 

·                  any factors that contribute to more frequent and severe imbalances between the supply of and demand for natural gas, whether caused by supply or demand fluctuations;

 

·                  operational imbalances, near-term seasonal spreads, shorter-term spreads and basis differentials; and

 

·                  the extent to which there is a surplus or shortfall of storage capacity relative to the overall demand for storage services in a given market area.

 

During the period from 2002 through 2012, domestic natural gas consumption has grown, albeit unevenly, driven primarily by growth in the seasonal and weather-sensitive electric power generation sector, partially offset by declines in the residential and industrial sectors. For a number of years during the same period, domestic natural gas production was relatively flat and failed to keep pace with domestic consumption. Over the past several years, however, domestic natural gas production has been growing rapidly. This trend reversal is primarily due to increases in production from developing shale resource plays.

 

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The seasonality of natural gas demand has remained strong during the last decade, with consumption during the peak winter months averaging approximately 40% more than consumption during the summer months, per EIA data. This strong seasonal trend has produced seasonal spreads (the price difference between the summer and winter season) that have generally moved within a range of approximately $0.19 to $4.74 per MMBtu, with the high end of that range occurring during the 2006-2007 timeframe.  However, in 2012 the seasonal spreads (Oct-Jan) for 2013-2014 and 2014-2015, which influence the rates at which we will be able to contract firm storage capacity in future years, have ranged from $0.35 to $0.48. In addition, lower short-term spreads and basis differentials have reduced overall market opportunities, which negatively impacts storage demand and value. While there are a variety of factors that have contributed to these softer market conditions, we believe the key drivers are (i) increased natural gas supplies due to production from shale resources, (ii) net increases in storage capacity and (iii) lower basis differentials due to expansion and improved connectivity of natural gas transportation infrastructure in the U.S. over the last five years. We believe that certain of the supply and demand factors are cyclical and self correcting over time, and that the long term outlook for storage utilization and demand is positive.

 

Description of Segments and Associated Assets

 

Our business activities are conducted through three segments—Transportation, Facilities and Supply and Logistics. We have an extensive network of transportation, terminalling and storage facilities at major market hubs and in key oil producing basins, as well as crude oil, NGL and refined product transportation corridors in the United States and Canada.

 

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

 

Transportation Segment

 

Our transportation segment operations generally consist of fee-based activities associated with transporting crude oil, NGL and refined products on pipelines, gathering systems, trucks and barges. We generate revenue through a combination of tariffs, third-party leases of pipeline capacity and 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 pipeline systems, in which we own noncontrolling interests.

 

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

 

·                  17,400 miles of active crude oil, NGL and refined products pipelines and gathering systems;

 

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

 

·                  582 trailers (primarily in Canada); and

 

·                  104 transport and storage barges and 51 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 products pipeline assets in the United States and Canada as of December 31, 2012, grouped by geographic location:

 

Region / Pipeline and Gathering Systems (1) 

 

System Miles

 

2012 Average
Net Barrels
per Day
 (2)

 

 

 

 

 

(in thousands)

 

United States Crude Oil

 

 

 

 

 

 

 

 

 

 

 

Permian Basin

 

 

 

 

 

Basin / Mesa

 

599

 

696

 

Permian Basin Area Systems

 

2,952

 

461

 

Permian Basin Subtotal

 

3,551

 

1,157

 

 

 

 

 

 

 

Eagle Ford Area Systems

 

179

 

23

 

 

 

 

 

 

 

Western

 

 

 

 

 

All American

 

138

 

33

 

Line 63 / Line 2000

 

357

 

128

 

Other

 

142

 

96

 

Western Subtotal

 

637

 

257

 

 

 

 

 

 

 

Rocky Mountain

 

 

 

 

 

Bakken Area Systems

 

954

 

130

 

Salt Lake City Area Systems

 

982

 

149

 

White Cliffs (3)

 

527

 

18

 

Other

 

1,323

 

105

 

Rocky Mountain Subtotal

 

3,786

 

402

 

 

 

 

 

 

 

Gulf Coast

 

 

 

 

 

Capline (3)

 

631

 

146

 

Other

 

945

 

299

 

Gulf Coast Subtotal

 

1,576

 

445

 

 

 

 

 

 

 

Central

 

 

 

 

 

Mid-Continent Area Systems

 

1,987

 

249

 

Other

 

421

 

120

 

Central Subtotal

 

2,408

 

369

 

 

 

 

 

 

 

United States Refined Products Pipelines

 

903

 

116

 

 

 

 

 

 

 

United States Total

 

13,040

 

2,769

 

 

 

 

 

 

 

Canada

 

 

 

 

 

Crude Oil Pipelines:

 

 

 

 

 

Manito

 

555

 

57

 

Rainbow

 

759

 

145

 

Rangeland

 

1,345

 

62

 

Other

 

462

 

165

 

Crude Oil Pipelines Subtotal

 

3,121

 

429

 

NGL Pipelines:

 

 

 

 

 

Co-Ed

 

813

 

44

 

Other

 

434

 

131

 

NGL Pipelines Subtotal

 

1,247

 

175

 

 

 

 

 

 

 

Canada Total

 

4,368

 

604

 

 

 

 

 

 

 

Grand Total

 

17,408

 

3,373

 

 


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

 

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(2)                       Represents average volume for the entire year attributable to our interest.

 

(3)                       Non-operated pipeline.

 

United States Pipelines

 

Permian Basin

 

Basin Pipeline System.  We own an approximate 87% undivided joint interest in and are the operator of the Basin Pipeline system. The Basin system is a primary route for transporting crude oil from the Permian Basin (in west Texas and southern New Mexico) to Cushing, Oklahoma, for further delivery to Mid-Continent and Midwest refining centers. The Basin system accommodates three primary movements of crude oil: (i) barrels that are shipped from Jal, New Mexico to the West Texas markets of Wink/Hendrick and Midland; (ii) barrels that are shipped from Midland to connecting carriers at Colorado City, Texas or Wichita Falls, Texas; and (iii) barrels that are shipped from Jal, Midland, Colorado City and Wichita Falls to connecting carriers at Cushing.

 

The Basin system is an approximate 520-mile mainline, telescoping crude oil system with a system capacity ranging from approximately 144,000 barrels per day to 450,000 barrels per day (approximately 125,000 barrels per day to 392,000 barrels per day attributable to our interest) depending on the segment. During 2012, we completed two expansion projects on the Basin system including (i) increasing capacity from 400,000 to 450,000 barrels per day (from 348,000 barrels per day to 392,000 barrels per day attributable to our interest) on crude oil movements from Colorado City to Cushing and (ii) increasing capacity from 144,000 to 240,000 barrels per day (from 125,000 barrels per day to 209,000 barrels per day attributable to our interest) on movements from Wink/Hendrick to Midland. System throughput (as measured by system deliveries) was approximately 506,000 barrels per day (attributable to our interest) during 2012. The system also includes approximately 6 million barrels of tankage located along the system. The Basin system is subject to tariff rates regulated by the Federal Energy Regulatory Commission (“FERC”).

 

Mesa Pipeline System. We own an approximate 63% interest in and are the operator of the Mesa Pipeline system, which transports crude oil from Midland to a refinery at Big Spring, Texas and to connecting carriers at Colorado City. The Mesa system is an 80-mile mainline with a system capacity of up to 400,000 barrels per day (approximately 252,000 barrels per day attributable to our interest).  System throughput (as measured by system deliveries) was approximately 190,000 barrels per day (attributable to our interest) during 2012.

 

Permian Basin Area Systems. We operate wholly owned systems of approximately 3,000 miles that aggregate receipts from wellhead gathering lines and bulk truck injection locations into a combination of 4- to 16-inch diameter trunk lines for transportation and delivery into the Basin system at Jal, Wink and Midland as well as our terminal facilities in Midland. These systems are subject to tariff rates regulated by either the FERC or state regulatory agencies. For 2012, combined throughput on the Permian Basin area systems totaled an average of approximately 461,000 barrels per day.

 

During 2011 and 2012, we commenced construction of multiple expansion and extension projects servicing the Bone Spring, Spraberry and Wolfberry producing areas in the Permian Basin. These projects, which included adding over 145 miles of pipeline and approximately 200,000 barrels of additional gathering capacity, interconnect with our Basin system as well as third-party systems. Portions of these projects were placed into service during 2012, with the remainder expected to be completed during 2013.

 

Eagle Ford Area

 

Eagle Ford Area Systems. In November 2011, we acquired from Velocity a condensate gathering system (the “Gardendale Gathering System”) that was in the advanced stages of construction in the Eagle Ford area of South Texas. The Gardendale Gathering System currently consists of approximately 115 miles of pipeline with a capacity of approximately 150,000 barrels per day and terminals at Gardendale and Catarina with aggregate storage capacity of approximately 185,000 barrels. In December 2012, we acquired approximately 30 miles of crude oil and condensate pipelines with a throughput capacity of approximately 50,000 barrels per day that complement our existing Gardendale Gathering System assets.

 

In August 2012, we formed Eagle Ford Pipeline LLC with Enterprise Products Partners (“Enterprise”) for the purpose of developing a crude oil pipeline system in the Eagle Ford Area. This system will include a 175-mile crude oil and condensate pipeline, a marine terminal facility and approximately 1.8 million barrels of operational storage capacity across the system. The project is designed to provide approximately 350,000 barrels per day of take-away capacity from the western region of the Eagle Ford play to Corpus Christi, Texas refining markets and to Houston via an Enterprise connection at Lyssy, Texas and is supported by long-term throughput agreements. The system is expected to be placed into service during 2013.

 

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Western

 

All American Pipeline System.  We own a 100% interest in the All American Pipeline system. The All American Pipeline 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 Gaviota receives crude oil from the Plains Exploration and Production Company-operated Point Arguello field.  These systems both terminate at our Emidio Station. Between Gaviota and our Emidio Station, the All American Pipeline 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 in decline. See Item 1A. “Risk Factors” for discussion of the estimated impact of a decline in volumes.

 

Line 63.  We own a 100% interest in 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 5 miles of distribution pipelines in the Los Angeles Basin, with a throughput capacity of approximately 144,000 barrels per day, and 148 miles of gathering pipelines in the San Joaquin Valley, with a 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.

 

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, we commenced a project to place this idle segment into service. We expect the project to be completed by July 2014. For 2012, combined throughput on Line 63 totaled an average of approximately 66,000 barrels per day.

 

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) 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 a 130-mile, 20-inch trunk pipeline with a throughput capacity of approximately 130,000 barrels per day. During 2012, throughput on Line 2000 (excluding Line 63 volumes) averaged approximately 62,000 barrels per day.

 

Rocky Mountain

 

Bakken Area Systems. We own and operate the Baker, Trenton and Whitetail gathering systems as well as the Robinson Lake and Bakken North pipelines. The gathering systems consist of 919 miles of pipelines and transported approximately 96,000 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 to refiners in Salt Lake City, Utah and to other pipelines at Ft. Laramie, Wyoming. These pipeline systems consist of 693 miles of pipelines and approximately 1 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, throughput on the Salt Lake City and Wahsatch pipeline systems in total averaged approximately 140,000  barrels per day.

 

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Included in the Salt Lake City Area systems is our 22% interest in Frontier Pipeline, an interstate common carrier crude oil pipeline that consists of a 289-mile trunk pipeline with a maximum throughput capacity of 79,000 barrels per day and three storage tanks. Frontier Pipeline originates in Casper, Wyoming and delivers crude oil into the Salt Lake City Pipeline System. For 2012, throughput on Frontier averaged approximately 9,000 barrels per day (attributable to our interest).

 

White Cliffs Pipeline. We own an approximate 36% interest in the White Cliffs Pipeline, a 527-mile, 12-inch common carrier pipeline that originates in Platteville, Colorado and terminates in Cushing, Oklahoma. Rose Rock Midstream, L.P. serves as the operator of the pipeline. For 2012, throughput on White Cliffs Pipeline averaged approximately 18,000 barrels per day (attributable to our interest). In 2012, White Cliffs announced an expansion project that will increase total system capacity from 70,000 barrels per day to 150,000 barrels per day and is underpinned by long-term shipper commitments. This expansion is expected to be completed in the first half of 2014.

 

Gulf Coast

 

Capline Pipeline System.  The Capline Pipeline system, in which we own an aggregate undivided joint interest of approximately 54%, is a 631-mile, 40-inch mainline crude oil pipeline originating in St. James, Louisiana, and terminating in Patoka, Illinois. We also own a 100% interest in approximately 720,000 barrels of tankage located at Patoka, Illinois.

 

Capline has direct connections to a significant amount of crude production in the Gulf of Mexico. In addition, it has two active docks capable of handling approximately 600,000-barrel tankers and is connected to the Louisiana Offshore Oil Port and our St. James terminal and transports various grades of crude oil to PADD II. Total designed operating capacity is approximately 1.1 million barrels per day of crude oil, of which our attributable interest is approximately 600,000 barrels per day.  Throughput on our interest averaged approximately 146,000 barrels per day during 2012.

 

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 2,000 miles of pipeline with transportation and delivery into and out of our terminal facilities at Cushing. For 2012, combined throughput on the Mid-Continent Area systems totaled an average of approximately 249,000 barrels per day.

 

In January 2012, we completed the conversion of an existing Oklahoma NGL pipeline into crude oil service. The pipeline extends from Medford, 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 day in July 2012.

 

In 2012, we began construction on a new 170-mile pipeline to service the increasing Mississippian Lime crude oil production in northern Oklahoma and Southern Kansas. This pipeline is designed 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. This pipeline is expected to go into service by mid-2013.  In early 2013, we announced a 55-mile extension of this pipeline, which will provide up to 75,000 barrels per day of crude oil throughput capacity and is supported by a long-term commitment from an area producer. This extension is expected to be brought into service in the fourth quarter of 2013.

 

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-mile system is comprised of the Manito pipeline, the North Sask pipeline and the Bodo/Cactus Lake pipeline. Each system consists of a blended crude oil line and a parallel diluent line which 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 334 miles of pipeline, and the mainline segment originates at Dulwich and terminates at Kerrobert, Saskatchewan. The Bodo/Cactus Lake pipeline is 137 miles long

 

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and originates in Bodo, Alberta and also terminates at our Kerrobert storage facility. The Kerrobert storage and terminalling facility is connected to the Enbridge pipeline system and can both receive and deliver heavy crude from and to the Enbridge pipeline system.  For 2012, approximately 57,000 barrels per day of crude oil were transported on the Manito system.

 

Rainbow System.  We own a 100% interest in the Rainbow system. The Rainbow system consists of a 480-mile, 20-inch to 24-inch mainline crude oil pipeline extending from the Norman Wells Pipeline connection in Zama, Alberta to Edmonton, Alberta and has 279 miles of gathering pipelines. The system has a throughput capacity of approximately 220,000 barrels per day and transported approximately 145,000  barrels per day during 2012.

 

During 2012, we commenced construction on a 187-mile, 10-inch pipeline to transport diluent north from Edmonton, Alberta to our Nipisi truck terminal in Northern Alberta. The pipeline is projected to have an initial capacity of 35,000 barrels per day and to be expandable to 70,000 barrels per day. We expect this project in service by mid-2013.

 

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 675 miles of 3-inch to 8-inch gathering pipelines.  The Rangeland system transports NGL mix, butane, condensate, light sweet crude and light sour crude 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 2012 on the Rangeland system was approximately 62,000 barrels per day.

 

NGL Pipelines

 

Co-Ed Pipeline System.  As part of the BP NGL acquisition completed during the first half of 2012, we became 100% owners and operators of the Co-Ed NGL Pipeline System.  The Co-Ed NGL system consists of approximately 813 miles of 3-inch to 10-inch pipeline. This pipeline gathers NGL from approximately 35 field gas processing plants located in the Cochrane, Alberta to Edmonton, Alberta region, as well as gathers all of the NGL produced at the Cochrane Straddle Plant.  The Co-Ed NGL system has throughput capacity of approximately 72,000 barrels per day. During 2012, throughput averaged approximately 44,000 barrels per day.

 

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, NGL fractionation and isomerization services and natural gas processing services. We generate revenue through a combination of month-to-month and multi-year leases and processing arrangements. Revenues generated in this segment include (i) storage fees that are generated when we lease storage capacity, (ii) terminal throughput fees that are generated when we receive crude oil, refined products or NGL from one connecting source and redeliver the applicable product to another connecting carrier, (iii) loading and unloading fees at our rail terminals, (iv) hub service 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, we owned, operated or employed a variety of long-term physical assets throughout the United States and Canada in this segment, including:

 

·                  approximately 74 million barrels of crude oil and refined products storage capacity primarily at our terminalling and storage locations;

 

·                  approximately 22 million barrels of NGL storage capacity;

 

·                  approximately 93 Bcf of natural gas storage working capacity;

 

·                  approximately 16 Bcf of base gas in storage facilities owned by us;

 

·                  eleven natural gas processing plants located throughout Canada and the Gulf Coast area of the United States;

 

·                  seven fractionation plants located throughout Canada and the United States with an aggregate gross processing capacity of approximately 272,100 barrels per day, and an isomerization and fractionation facility in California with an aggregate processing capacity of approximately 14,000 barrels per day;

 

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

 

·                  23 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.

 

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The following is a tabular presentation of our active facilities segment storage and service assets in the United States and Canada as of December 31, 2012, grouped by product and service type and capacity and volume as indicated:

 

Crude Oil and Refined Products Storage Facilities

 

Total Capacity
(MMBbls)

 

Cushing

 

19

 

Kerrobert

 

1

 

LA Basin

 

9

 

Martinez and Richmond

 

5

 

Mobile and Ten Mile

 

3

 

Patoka

 

6

 

Philadelphia Area

 

4

 

St. James

 

8

 

Yorktown (1)

 

6

 

Other

 

13

 

 

 

74

 

 

 

 

 

NGL Storage Facilities

 

Total Capacity
(MMBbls)

 

Bumstead

 

2

 

Fort Saskatchewan

 

4

 

Sarnia Area

 

8

 

Tirzah

 

1

 

Other

 

7

 

 

 

22

 

 

Natural Gas Storage Facilities

 

Total Capacity
(Bcf)

 

Salt-caverns (Pine Prairie and Southern Pines)

 

67

 

Depleted Reservoir (Bluewater)

 

26

 

 

 

93

 

 

Natural Gas Processing Facilities (2)

 

Ownership Interest

 

Total Gas
Inlet Volume
(3)
(Bcf/d)

 

Gross Gas
Processing
Capacity
(4)
(Bcf/d)

 

Net Gas
Processing
Capacity
(Bcf/d)

 

United States Gulf Coast Area

 

100

%

0.3

 

0.6

 

0.6

 

Canada

 

36-100

%

1.2

 

5.9

 

4.3

 

 

 

 

 

1.5

 

6.5

 

4.9

 

 

NGL Fractionation and Isomerization Facilities

 

Ownership Interest

 

Total
Inlet Volume
 (3)
(Bpd)

 

Gross
Capacity
(4)
(Bpd)

 

Net
Capacity
(Bpd)

 

Fort Saskatchewan

 

21-100

%

57,944

 

125,000

 

101,300

 

Sarnia

 

62-84

%

62,800

 

120,000

 

90,000

 

Shafter

 

100

%

10,664

 

14,000

 

14,000

 

Other

 

68-100

%

11,830

 

27,100

 

24,600

 

 

 

 

 

143,238

 

286,100

 

229,900

 

 

Crude Oil and NGL Rail Facilities

 

Ownership Interest

 

Loading
Capacity
(5)
(Bpd)

 

Unloading
Capacity
(5)
(Bpd)

 

Crude Oil Rail Facilities

 

100

%

140,000

 

140,000

 

 

 

 

 

 

 

 

 

 

 

Ownership Interest

 

Number of
Rack Spots

 

Number of
Storage Spots

 

NGL Rail Facilities (6)

 

50-100

%

247

 

833

 

 

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(1)             Amount includes 1.6 million barrels of capacity for which we hold lease options (1.1 million barrels of which have been exercised).

 

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

 

(3)             Inlet volumes represent average inlet volumes for the entire year, except for the facilities we acquired as part of the BP NGL Acquisition.  Inlet volumes for these facilities are calculated based on a 275-day period, which was the number of days we owned the assets during 2012.

 

(4)             Gross capacity represents original facility design specifications.  Actual usable capacity in certain instances is limited by seasonality and other factors as well as by incremental capital investments necessary to effectively utilize full capacity.

 

(5)             Capacity transported will vary according to specification of product moved.

 

(6)             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 following discussion contains a detailed description of our more significant facilities segment assets.

 

Major Facilities Assets

 

Crude Oil and Refined Products Facilities

 

Cushing Terminal.  Our Cushing, Oklahoma Terminal (the “Cushing Terminal”) is located at the Cushing Interchange, one of the largest wet-barrel trading hubs in the U.S. and the delivery point for crude oil futures contracts traded on the NYMEX. The Cushing Terminal has been designated by the NYMEX as an approved delivery location for crude oil delivered under the NYMEX light sweet crude oil futures contract. As the NYMEX delivery point and a cash market hub, the Cushing Interchange serves as a primary source of refinery feedstock for the Midwest refiners and plays an integral role in establishing and maintaining markets for many varieties of foreign and domestic crude oil. The facility is designed to handle multiple grades of crude oil while minimizing the interface and enabling deliveries to connecting carriers at their maximum rate.

 

Since 1999, we have completed multiple expansions, which have increased the capacity of the Cushing Terminal to a total of approximately 19 million barrels. During 2012, we commenced our Phase XII terminal expansion, which includes adding approximately 1 million barrels of storage capacity through the construction of four 270,000 barrel tanks. We expect three of these tanks to be in service during the first quarter of 2013, with the last tank placed in service during the second half of 2013.

 

Kerrobert Terminal.  We own a crude oil and condensate storage and terminalling facility, which is located near Kerrobert, Saskatchewan and is connected to our Manito and Cactus Lake pipeline systems. The total storage capacity at the Kerrobert terminal is approximately 1 million barrels. This facility is also connected to the Enbridge pipeline system and can both receive and deliver heavy crude from and to the Enbridge pipeline system.

 

L.A. Basin.  We own four crude oil and refined product storage facilities in the Los Angeles area with a total of approximately 9 million barrels of storage capacity in service and a distribution pipeline system of approximately 50 miles of pipeline in the Los Angeles Basin. Approximately 8 million barrels of the storage capacity are used for commercial service and approximately 1 million barrels are used primarily for throughput to other storage tanks and for displacement oil and do not generate revenue independently. We use the Los Angeles area storage and distribution system to service the storage and distribution needs of the refining, pipeline and marine terminal industries in the Los Angeles Basin. Our Los Angeles area system’s pipeline distribution assets connect our storage assets with major refineries and third-party pipelines and marine terminals in the Los Angeles Basin.

 

Martinez and Richmond Terminals.  We own two terminals in the San Francisco, California area: a terminal at Martinez (which provides refined product and crude oil service) and a terminal at Richmond (which provides refined product service). Our San Francisco area terminals have approximately 5 million barrels of combined storage capacity that are connected to area refineries through a network of owned and third-party pipelines that carry crude oil and refined products to and from area refineries. The terminals have dock facilities and our Richmond terminal is also able to receive products by rail.

 

Mobile and Ten Mile Terminal.  We have a marine terminal in Mobile, Alabama (the “Mobile Terminal”) that has current useable capacity of approximately 2 million barrels. Approximately 3 million barrels of additional storage capacity is available at our nearby Ten Mile Facility, which is connected to our Mobile Terminal via a 36-inch pipeline. Approximately two-thirds of the additional storage capacity at Ten Mile is included in our transportation segment.

 

The Mobile Terminal is equipped with a ship/tanker dock, barge dock, truck unloading facilities and various third-party connections for crude oil movements to area refiners. Additionally, the Mobile Terminal serves as a source for imports of foreign crude oil to PADD II refiners through our Mississippi/Alabama pipeline system, which connects to the Capline System at our station in Liberty, Mississippi.

 

Patoka Terminal.  Our Patoka Terminal has approximately 6 million barrels of storage capacity and the associated manifold and header system at the Patoka Interchange located in southern Illinois. Patoka is a growing regional hub with access to domestic and foreign crude oil for certain volumes moving north on the Capline system as well as Canadian barrels moving south. During 2012, we completed construction of Phase IV at our Patoka Terminal, which included two 286,000 barrel crude oil tanks and one 400,000 barrel crude oil tank.

 

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Philadelphia Area Terminals.  We own four refined product terminals in the Philadelphia, Pennsylvania area. Our Philadelphia area terminals have a combined storage capacity of approximately 4 million barrels. The terminals have 20 truck loading lanes, two barge docks and a ship dock. The Philadelphia area terminals provide services and products to all of the refiners in the Philadelphia harbor, and include two dock facilities. The Philadelphia area terminals also receive products from connecting pipelines and offer truck loading services.

 

St. James Terminal.  We have approximately 8 million barrels of crude oil storage capacity at the St. James crude oil interchange in Louisiana, which is one of the three most liquid crude oil interchanges in the United States. The facility includes a manifold and header system that allows for receipts and deliveries with connecting pipelines at their maximum operating capacity. Over the past few years, we completed the construction of a marine dock that is able to receive from tankers and receive from, and load, barges.  The facility is also connected to our rail unloading facility. See “Rail Facilities” below for further discussion.

 

During 2012, we completed our Phase IV expansion at the St. James Terminal, which included the construction of an additional 1 million barrels of crude oil storage capacity and is supported by multi-year contracts and throughput arrangements with third-party customers. We have begun construction of our Phase V expansion, which will increase storage capacity by an additional 1.1 million barrels. We expect this construction to be completed near the end of 2013.

 

Yorktown Terminal.  During late 2011, we acquired the idled Western Refinery in Yorktown, Virginia and are operating it as a terminal. This facility has approximately 6 million barrels of storage for crude oil, black oil, propane, butane and refined products, including 1.6 million barrels of capacity for which we hold lease options (1.1 million barrels of which have been exercised). The Yorktown facility has its own deep-water port on the York River with the capacity to service the receipt and delivery of product from ships and barges.  This facility also has an active truck rack and rail capacity.  See “Rail Facilities” below for further discussion. We are in the process of making a number of modifications to the Yorktown facility, which will enhance the capabilities of the rail system, the dock facilities and related infrastructure, and increase connectivity and flexibility within the terminal itself. We expect to complete these projects by mid-2013.

 

NGL Storage Facilities

 

Bumstead.  The Bumstead facility is located at a major rail transit point near Phoenix, Arizona. With approximately 3 million barrels of working capacity (approximately 2 million barrels of useable capacity), the facility’s primary assets include three salt-dome storage caverns, a 30-car rail rack and six truck racks.

 

During 2010, we began upgrading and improving our Bumstead NGL storage facility, which will increase the useable capacity by approximately 700,000 barrels. This project is expected to be completed during 2013.

 

Fort Saskatchewan.  The Fort Saskatchewan facility is located approximately 16 miles northeast of Edmonton, Alberta in one of the key North American NGL hubs. The facility is a receipt, storage, fractionation and delivery facility for NGL and is connected to other major NGL plants and pipeline systems in the area. The facility’s primary assets include 10 storage caverns with approximately 4 million barrels in useable storage capacity. NGL mix and spec products can be delivered to the Enbridge and Cochin pipeline in addition to the propane truck loading rack at the facility. The facility includes assets operated by us and assets operated by a third-party.  Our ownership in the various facility assets ranges from approximately 21% to 100%. See the section entitled “––NGL Fractionation and Isomerization Facilities” below for additional discussion of this facility.

 

Sarnia Area.  The Sarnia facility is a large NGL fractionation, storage and shipping facility located on a 380 acre plant site in the Sarnia Chemical Valley. There are 36 multi-product rail car loading spots, 4 multi-product truck loading racks and a network of 14 pipelines providing product delivery capabilities to our Windsor, St. Clair and Green Springs terminal facilities, in addition to refineries, chemical plants, and other pipeline systems in the area. The facility has approximately 3 million barrels in useable storage capacity.

 

The Windsor storage terminal in Windsor, Canada, is a pipeline hub and underground storage facility. The facility is served by three Plains owned receipt/dispatch pipelines, the Cochin pipeline and rail and truck offloading. There are eight storage caverns on site with a useable capacity of approximately 3 million barrels. The primary terminal assets consist of 16 multi-product rail tank car loading spots and a propane truck loading rack.

 

The St. Clair terminal is a propane, isobutane and butane storage and distribution facility located in St. Clair, Michigan and is connected to the Sarnia facility via a Plains owned pipeline.  On site are seven storage caverns with useable capacity of approximately 2 million barrels and 28 multi-product rail tank car loading spots and six tank truck loading racks.

 

Tirzah.  The Tirzah facility is located in South Carolina and consists of an underground granite storage cavern with approximately 1 million barrels of useable capacity. The Tirzah facility is connected to the Dixie Pipeline System (a third-party system) via our 62-mile pipeline.

 

Natural Gas Storage Facilities

 

Salt Cavern Storage Facilities. We own two FERC regulated, high deliverability salt cavern natural gas storage facilities located on the Gulf Coast. Our Pine Prairie facility is located in Evangeline, Rapides and Acadian Parishes, Louisiana and is permitted for up to 80 Bcf of working gas capacity, which includes 32 Bcf of incremental capacity that was approved by the FERC subject to the requirement that Pine Prairie conduct an open season in accordance with applicable FERC policy. Our Southern Pines facility is located in Greene County Mississippi and is permitted for up to 40 Bcf of working gas capacity. During 2012, we placed

 

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into commercial service an aggregate of approximately 17 Bcf of working gas capacity at our Pine Prairie and Southern Pines facilities, including expansions of existing caverns and the addition of a new cavern at both Pine Prairie and Southern Pines. These two facilities had an aggregate working gas capacity as of December 31, 2012 of approximately 67 Bcf. During 2013, our expansion plans include the creation of approximately 6.5 Bcf of working gas capacity from incremental leaching activities, which capacity will be placed into service during 2013 and 2014.

 

Both of these facilities are strategically located and have a diverse group of customers, including utilities, pipelines, producers, power generators, marketers and liquefied natural gas (“LNG”) exporters, whose storage needs include both traditional seasonal storage services and short-term storage services. Pine Prairie is strategically positioned relative to several major market hubs, including the Henry Hub (the delivery point for NYMEX natural gas futures contracts and located approximately 50 miles southeast of Pine Prairie), the Carthage Hub (located in East Texas), and the Perryville Hub (located in North Louisiana), and to existing and proposed LNG import and export facilities.

 

Pine Prairie’s pipeline header system, which includes an aggregate of approximately 80 miles of 24-inch diameter pipe located within a 20-mile radius of Pine Prairie, is directly connected to eight large-diameter interstate pipelines through nine interconnects that service both conventional and unconventional natural gas production in Texas and Louisiana, including production from existing and emerging shale plays, as well as the Gulf of Mexico. These interconnects also provide direct or indirect access to each of the market hubs described above and to consumer and industrial markets in the Gulf Coast, Midwest, Northeast and Southeast regions of the United States. Pine Prairie’s peak daily injection and withdrawal rates are 2.4 Bcf and 3.2 Bcf, respectively, and Pine Prairie has a total of 71,000 horsepower of compression capacity currently in service with another 27,500 horsepower of permitted capacity.

 

Southern Pines’ pipeline header system, which includes an aggregate of 60 miles of 24-inch diameter pipe, is connected to 4 major natural gas pipelines servicing the Gulf Coast, Northeast, Mid-Atlantic and Southeastern U.S. markets. Southern Pines’ peak daily injection and withdrawal rates are 1.2 Bcf and 2.4 Bcf, respectively, and Southern Pines has a total of 48,000 horsepower of compression capacity currently in service.

 

Depleted Reservoir Facility (Bluewater). Bluewater is located in the State of Michigan and primarily services seasonal storage needs throughout the Midwestern and Northeastern portions of the U.S. and the Southeastern portion of Canada. Accordingly, Bluewater’s customers consist primarily of pipelines, utilities and marketers seeking seasonal storage services. Bluewater’s 30-mile, 20-inch diameter pipeline header system is supported by 13,350 horsepower of compression and connects with three interstate and three natural gas utility pipelines that provide access to the major market hubs of Chicago, Illinois and Dawn, Ontario, which supply natural gas to eastern Ontario and the northeastern United States. These interconnects also provide access to natural gas utilities that serve local markets in Michigan and Ontario. Bluewater’s peak daily injection and withdrawal rates are 0.5 Bcf and 0.8 Bcf, respectively.

 

Bluewater has total working gas storage capacity of approximately 26.0 Bcf in two depleted reservoirs and is permitted for an additional 3.0 Bcf of working gas storage capacity. We expect to increase Bluewater’s working gas capacity by approximately 1.0 Bcf ratably over a 7 to 8-year period in connection with an ongoing liquids removal project. Bluewater also leases third-party storage capacity and pipeline transportation capacity from time to time to increase its operational flexibility and enhance its service offerings. In addition, on December 14, 2012, the FERC granted Bluewater to place in service the St. Clair River Crossing Replacement facilities located in St. Clair County, Michigan.  Facilities included the construction of a 20-inch pipeline with a permitted capacity for up to 300 million cubic feet (“MMcf”) per day that connects Bluewater to a Canadian pipeline owned by an affiliate of Spectra Energy. The new facilities replaced a 12-inch pipeline that was permitted for up to 250 MMcf per day and leased from Nova Chemical through January 2013.

 

Natural Gas Processing Facilities

 

We own and operate five natural gas processing plants located in Louisiana and Alabama with an aggregate natural gas processing capacity of approximately 0.6 Bcf per day. In January 2013, we completed construction of a condensate stabilization facility in South Texas designed to extract NGL from condensate, which will enable condensate to meet specifications of pipelines originating out of Gardendale, Texas.  This facility will have a total capacity of approximately 80,000 barrels per day.

 

We also own and/or operate four straddle plants and two field gas processing plants located in Western Canada with an aggregate gross natural gas processing capacity of approximately 5.9 Bcf per day and long-term liquid supply contracts relating to a third-party owned straddle plant with gross processing capacity of approximately 2.5 Bcf per day.

 

NGL Fractionation and Isomerization Facilities

 

Fort Saskatchewan.  Our Fort Saskatchewan facility has a fractionation capacity of approximately 95,000 barrels per day (feedstock capacity) and produces both spec NGL products and a C3/C4 mix for delivery to the Sarnia facility via the Enbridge pipeline.

 

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The fractionation feedstock is supplied via the Fort Saskatchewan Pipeline System which connects to the Co-Ed pipeline system. Through ownership in the Keyera Fort Saskatchewan fractionation plant, we have additional fractionation capacity, net to our share of 6,300 barrels per day.

 

Sarnia.  The Sarnia Fractionator is the largest fractionation plant in Eastern Canada and receives NGL feedstock from the Enbridge Pipeline, the Kalkaska Pipeline, and from refineries, gas plants and chemical plants in the area.  The fractionation unit has a gross capacity of 120,000 barrels per day and produces specification propane, isobutane, normal butane and natural gasoline. Our ownership in the various processing units at the Sarnia Fractionator ranges from 62% to 84%.

 

Shafter.  Our Shafter facility located near Bakersfield, California provides isomerization and fractionation services to producers and customers. The primary assets consist of approximately 200,000 barrels of NGL storage and a processing facility with butane isomerization capacity of approximately 14,000 barrels per day and NGL fractionation capacity of approximately 12,000 barrels per day. During 2011, we commenced our Shafter Expansion Project. This project will include the construction of a 15-mile NGL pipeline system that will be capable of delivering up to 10,000 barrels per day from Occidental Petroleum Corporation’s Elk Hills Gas plant to our Shafter facility.  It will also include enhancements to our storage and rail facilities and is expected to be placed into service in the first quarter of 2014.

 

Rail Facilities

 

Crude Oil Rail Loading Facilities

 

We own four active crude oil and condensate rail loading terminals, with one additional terminal being developed. Our active terminals service production in the Niobrara, Eagle Ford and Bakken shale formations and are located in Carr, Colorado; Gardendale, Texas; Manitou, North Dakota; and Van Hook, North Dakota and have a combined loading capacity of approximately 140,000 barrels per day.

 

During 2012, we began pre-construction activities, which include obtaining necessary permits, on a new rail facility in Tampa, Colorado. This facility will be designed to receive crude oil via truck and pipeline and to load unit trains at a rate of up to 68,000 barrels per day.  We anticipate commencing construction on this project, which is supported by firm contracts, in early-2013, and the facility is expected to be in service by the second half of 2013. In addition, we are currently expanding the Carr, Colorado and Van Hook, North Dakota terminals.  These expansions are expected to be completed in the second half of 2013. After our various terminal expansion and development activities are complete, our expected loading capacity will be over 265,000 barrels per day.

 

Crude Oil Rail Unloading Facilities

 

We own one active crude oil rail unloading terminal and have two additional unloading terminals under construction and development. Our terminal at St. James, Louisiana is connected to an active rail unloading facility and has been expanded to unload 52 railcars at a time with capacity to unload 140,000 barrels of sweet crude oil per day.

 

We are currently developing a crude oil rail facility at our multi-product terminal in Yorktown, Virginia. The rail facility will receive unit trains and is expected to have a capacity of 140,000 barrels per day upon its completion projected to occur during the second half of 2013. In connection with our 2012 acquisition of rail terminals from US Development Group, we acquired a project to construct a crude oil unloading terminal near Bakersfield, California, This project is expected to reach completion during the first half of 2014 at which point this terminal will have capacity to unload 68,000 barrels per day when construction is complete. We expect total unloading capacity of approximately 400,000 barrels per day after our rail unloading projects are in service.

 

NGL Rail Facilities

 

We own eighteen operational NGL rail facilities located throughout the United States and Canada that are strategically located near NGL storage, pipelines, gas production or propane distribution centers. Our NGL rail facilities currently have 247 railcar rack spots and 833 railcar storage spots and we have the ability to switch our own rail cars at six of these terminals.

 

Supply and Logistics Segment

 

Our supply and logistics segment operations generally consist of the following merchant-related activities:

 

·                  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;

 

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·                  the storage of inventory during contango market conditions and the seasonal storage of NGL;

 

·                  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 or other resellers to maximize profits; and

 

·                  the transportation of crude oil and NGL on trucks, barges, railcars, pipelines and ocean-going vessels to various delivery points, including but not limited to refineries, connecting carriers and fractionation facilities.

 

The majority of activities that are carried out within our supply and logistics segment are designed to produce a stable baseline of results in a variety of market conditions, while at the same time provide upside potential associated with opportunities inherent in volatile market conditions (including opportunities to benefit from fluctuating crude oil quality differentials). These activities utilize storage facilities at major interchange and terminalling locations and various hedging strategies to provide a balance. The tankage that is used to support our arbitrage activities positions us to capture margins in a contango market or when the market switches from contango to backwardation. See “—Impact of Commodity Price Volatility and Dynamic Market Conditions on Our Business Model” below for further discussion.

 

In addition to substantial working inventories associated with its merchant activities, as of December 31, 2012, our supply and logistics segment also owned significant volumes of crude oil and NGL classified as long-term assets for linefill or minimum inventory requirements under service arrangements with transportation carriers and terminalling providers. The supply and logistics segment also employs a variety of owned or leased physical assets throughout the United States and Canada, including approximately:

 

·                  11 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;

 

·                  815 trucks and 926 trailers; and

 

·                  5,380 railcars (net of railcars subleased to other parties).

 

In connection with its operations, the supply and logistics segment secures transportation and facilities services from our other two segments as well as third-party service providers under month-to-month and multi-year arrangements. Intersegment sales are based on posted tariff rates, rates similar to those charged to third parties or rates that we believe approximate market rates. However, certain terminalling and storage rates recognized within our facilities segment are discounted to our supply and logistics segment to reflect the fact that these services may be canceled on short notice to enable the facilities segment to provide services to third parties, generally under longer term arrangements.

 

The following table shows the average daily volume of our supply and logistics activities for the year ended December 31, 2012 (in thousands of barrels per day):

 

 

 

Volumes

 

Crude oil lease gathering purchases

 

818

 

NGL sales

 

182

 

Waterborne cargos

 

3

 

Supply & Logistics activities total

 

1,003

 

 

Crude Oil and NGL Purchases.  We purchase crude oil and NGL from multiple producers under contracts and believe that we have established long-term, broad-based relationships with the crude oil and NGL producers in our areas of operations. These contracts generally range in term from a thirty-day evergreen to five years, with the majority ranging from thirty days to one year and a limited number of contracts extending to approximately ten years. We utilize our truck fleet and gathering pipelines as well as leased railcars, third-party pipelines, trucks and barges to transport the crude oil to market. In addition, we purchase foreign crude oil. Under these contracts we may purchase crude oil upon delivery in the U.S. or we may purchase crude oil in foreign locations and transport it on third-party tankers.

 

We purchase NGL from producers, refiners, and other NGL marketing companies under contracts that generally range from immediate delivery to one year in term. We utilize our trucking fleet as well as leased railcars, third-party tank trucks or pipelines to transport NGL.

 

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In addition to purchasing crude oil from producers, we purchase both domestic and foreign crude oil and refined products in bulk at major pipeline terminal locations and barge facilities. We also purchase NGL in bulk at major pipeline terminal points and storage facilities from major integrated oil companies, large independent producers or other NGL marketing companies or processors. Crude oil, refined products and NGL are purchased in bulk when we believe additional opportunities exist to realize margins further downstream in the crude oil, refined products or NGL distribution chain. The opportunities to earn additional margins vary over time with changing market conditions. Accordingly, the margins associated with our bulk purchases will fluctuate from period to period.

 

Crude Oil and NGL Sales.  The activities involved in the supply, logistics and distribution of crude oil and NGL are complex and require current detailed knowledge of crude oil and NGL sources and end markets, as well as a familiarity with a number of factors including grades of crude oil, individual refinery demand for specific grades of crude oil, area market price structures, location of customers, various modes and availability of transportation facilities and timing and costs (including storage) involved in delivering crude oil and NGL to the appropriate customer.

 

We sell our crude oil to major integrated oil companies, independent refiners and other resellers in various types of sale and exchange transactions. We sell NGL primarily to retailers and refiners, and limited volumes to other marketers. The contracts generally range in term from a thirty-day evergreen to five years, with the majority ranging from thirty days to one year and a limited number of contracts extending to approximately ten years. We establish a margin for the crude oil and NGL we purchase by entering into physical sales contracts with third parties, or by entering into a future delivery obligation with respect to futures contracts on the NYMEX, ICE or over-the-counter. Through these transactions, we seek to maintain a position that is substantially balanced between purchases and sales and future delivery obligations. From time to time, we enter into various types of sale and exchange transactions including fixed price delivery contracts, floating price collar arrangements, financial swaps and crude oil and NGL-related futures contracts as hedging devices.

 

Crude Oil and NGL Exchanges.  We pursue exchange opportunities to enhance margins throughout the gathering and marketing process. When opportunities arise to increase our margin or to acquire a grade, type or volume of crude oil or NGL that more closely matches our physical delivery requirement, location or the preferences of our customers, we exchange physical crude oil or NGL, as appropriate, with third parties. These exchanges are effected through contracts called exchange or buy/sell agreements. Through an exchange agreement, we agree to buy crude oil or NGL that differs in terms of geographic location, grade of crude oil or type of NGL, or physical delivery schedule from crude oil or NGL we have available for sale. Generally, we enter into exchanges to acquire crude oil or NGL at locations that are closer to our end markets, thereby reducing transportation costs and increasing our margin. We also exchange our crude oil to be physically delivered at a later date, if the exchange is expected to result in a higher margin net of storage costs, and enter into exchanges based on the grade of crude oil, which includes such factors as sulfur content and specific gravity, in order to meet the quality specifications of our physical delivery contracts. See Note 2 to our Consolidated Financial Statements for further discussion of our accounting for exchange and buy/sell agreements.

 

Credit.  Our merchant activities involve the purchase of crude oil, natural gas, refined products and NGL for resale and require significant extensions of credit by our suppliers. In order to assure our ability to perform our obligations under the purchase agreements, various credit arrangements are negotiated with our suppliers. These arrangements include open lines of credit and, to a lesser extent, standby letters of credit issued under our hedged inventory facility or our senior unsecured revolving credit facility.

 

When we sell crude oil, NGL, refined products and natural gas, we must determine the amount, if any, of the line of credit to be extended to any given customer. We manage our exposure to credit risk through credit analysis, credit approvals, credit limits, prepayment, letters of credit and monitoring procedures.

 

Because our typical crude oil sales transactions can involve tens of thousands of barrels of crude oil, the risk of nonpayment and nonperformance by customers is a major consideration in our business. We believe our sales are made to creditworthy entities or entities with adequate credit support. Generally, sales of crude oil are settled within 30 days of the month of delivery, and pipeline, transportation and terminalling services settle within 30 days from the date we issue an invoice for the provision of services.

 

We also have credit risk exposure related to our sales of NGL and natural gas; however, because our sales are typically in relatively small amounts to individual customers, we do not believe that these transactions pose a material concentration of credit risk. Typically, we enter into annual contracts to sell NGL on a forward basis, as well as to sell NGL on a current basis to local distributors and retailers. In certain cases our NGL customers prepay for their purchases, in amounts ranging up to 100% of their contracted amounts.

 

Certain activities in our supply and logistics segment are affected by seasonal aspects, primarily with respect to NGL supply and logistics activities, which generally have higher activity levels during the first and fourth quarters of each year.

 

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Impact of Commodity Price Volatility and Dynamic Market Conditions on Our Business Model

 

Through our three business segments, we are engaged in the transportation, storage, terminalling and marketing of crude oil, refined products, NGL and natural gas.  The majority of our activities are focused on crude oil, which is the principal feedstock used by refineries in the production of transportation fuels.

 

Crude oil, NGL, refined products and natural gas commodity prices have historically been very volatile. For example, since the mid-1980s, NYMEX West Texas Intermediate crude oil benchmark prices have ranged from a low of approximately $10 per barrel during 1986 to a high of over $147 per barrel during 2008. During 2012, crude oil prices traded within a range of $77 to $111 per barrel.

 

Absent extended periods of lower crude oil prices that are below production replacement costs or higher crude oil prices that have a significant adverse impact on consumption, demand for the services we provide in our fee-based transportation and facilities segments and our gross profit from these activities have little correlation to absolute crude oil prices.  Relative contribution levels will vary from quarter-to-quarter due to seasonal and other similar factors, but our fee-based transportation and facilities segments should comprise approximately 70% to 80% of our aggregate base level segment profit.

 

Base level segment profit from our supply and logistics activities is dependent on our ability to sell crude oil and NGL at prices in excess of our aggregate cost. Although segment profit may be adversely affected during certain transitional periods, our crude oil supply, logistics and distribution operations are not directly affected by the absolute level of crude oil prices, but are affected by overall levels of supply and demand for crude oil and relative fluctuations in market-related indices.

 

In developing our business model and allocating our resources among our three segments, we attempt to anticipate the impacts of shifts between supply-driven markets and demand-driven markets, seasonality, cyclicality, regional surpluses and shortages, economic conditions and a number of other influences that can cause volatility and change market dynamics on a short, intermediate and long-term basis.  Our objective is to position the Partnership such that our overall annual base level of cash flow is not materially adversely affected by the absolute level of energy prices, shifts between demand-driven markets and supply-driven markets or other similar dynamics.  We believe the complementary, balanced nature of our business activities and diversification of our asset base among varying regions and demand-driven and supply-driven markets provides us with a durable base level of cash flow in a variety of market scenarios.

 

In addition to providing a durable base level of cash flow, this approach is also intended to provide opportunities to realize incremental margin during volatile market conditions. For example, if crude oil prices are high relative to historical levels, we may hedge some of our expected pipeline loss allowance barrels, and if crude oil prices are low relative to historical prices, we may hedge a portion of our anticipated diesel purchases needed to operate our trucks and barges.  Also, during periods when supply exceeds the demand for crude oil, NGL or natural gas in the near term, the market for such product is often in contango, meaning that the price for future deliveries is higher than current prices. In a contango market, entities that have access to storage at major trading locations can purchase crude oil, NGL or natural gas at current prices for storage and simultaneously sell forward such products for future delivery at higher prices.  Conversely, when there is a higher demand than supply of crude oil, NGL or natural gas in the near term, the market is backwardated, meaning that the price for future deliveries is lower than current prices.  In a backwardated market, hedged positions established in a contango market can be unwound, with the physical product or futures position sold into the current higher priced market at a level that more than compensates for any loss associated with closing out future delivery obligations.

 

The combination of a high level of fee-based cash flow from our transportation and facilities segments, complemented by a number of diverse, flexible and counter-balanced sources of cash flow within our supply and logistics segment is intended to enable us to accomplish our objectives of maintaining a durable base level of cash flow and providing upside opportunities.  In executing this business model, we employ a variety of financial risk management tools and techniques, predominantly in our supply and logistics segment.

 

Risk Management

 

In order to hedge margins involving our physical assets and manage risks associated with our various commodity purchase and sale obligations and, in certain circumstances, to realize incremental margin during volatile market conditions, we use derivative instruments.  We also use various derivative instruments to manage our exposure to interest rate risk and currency exchange rate risk. In analyzing our risk management activities, we draw a distinction between enterprise level risks and trading-related risks. Enterprise level risks are those that underlie our core businesses and may be managed based on management’s assessment of the cost or benefit in doing so. Conversely, trading-related risks (the risks involved in trading in the hopes of generating an increased return) are not inherent in our core business; rather, those risks arise as a result of engaging in the trading activity. Our policy is to manage the enterprise level risks inherent in our core businesses, rather than trying to profit from trading activity. Our commodity risk

 

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management policies and procedures are designed to monitor NYMEX, ICE and over the counter positions, as well as physical volumes, grades, locations, delivery schedules and storage capacity, to help ensure that our hedging activities address our risks. Our interest rate and currency exchange rate risk management policies and procedures are designed to monitor our derivative positions and ensure that those positions are consistent with our objectives and approved strategies. We have a risk management function that has direct responsibility and authority for our risk policies, related controls around commercial activities and procedures and certain other aspects of corporate risk management. Our risk management function also approves all new risk management strategies through a formal process. Our approved strategies are intended to mitigate and manage enterprise level risks that are inherent in our core businesses.

 

Except for pre-defined inventory positions, our policy is generally to structure our purchase and sales contracts so that price fluctuations do not materially affect our operating income, and not to acquire and hold physical inventory or derivatives for the purpose of speculating on outright commodity price changes.

 

Although we seek to maintain a position that is substantially balanced within our supply and logistics activities, we purchase crude oil, refined products, NGL and natural gas from thousands of locations and may experience net unbalanced positions for short periods of time as a result of production, transportation and delivery variances as well as logistical issues associated with inclement weather conditions and other uncontrollable events that occur within each month. When unscheduled physical inventory builds or draws do occur, they are monitored constantly and managed to a balanced position over a reasonable period of time. This activity is monitored independently by our risk management function and must take place within predefined limits and authorizations.

 

Geographic Data; Financial Information about Segments

 

See Note 18 to our Consolidated Financial Statements.

 

Customers

 

Marathon Petroleum Corporation and its affiliates accounted for approximately 16%, 16% and 14% of our revenues for the years ended December 31, 2012, 2011 and 2010, respectively. ConocoPhillips Company (prior to the spin-off of Phillips 66, which was effective May 1, 2012) accounted for approximately 10% of our revenues for each of the years ended December 31, 2011 and 2010. No other customers accounted for 10% or more of our revenues during any of the three years ended December 31, 2012, 2011 and 2010. The majority of revenues from these customers pertain to our supply and logistics operations. The sales to these customers occur at multiple locations and we believe that the loss of these customers would have only a short-term impact on our operating results. There is risk, however, that we would not be able to identify and access a replacement market at comparable margins.  For a discussion of customers and industry concentration risk, see Note 13 to our Consolidated Financial Statements.

 

Competition

 

Competition among pipelines is based primarily on transportation charges, access to producing areas and demand for the crude oil by end users. We believe that high capital requirements, environmental considerations and the difficulty in acquiring rights-of-way and related permits make it unlikely that competing pipeline systems comparable in size and scope to our pipeline systems will be built in the foreseeable future. However, to the extent there are already third-party owned pipelines or owners with joint venture pipelines with excess capacity in the vicinity of our operations, we are exposed to significant competition based on the relatively low cost of moving an incremental barrel of crude oil. In addition, in areas where additional infrastructure is necessary to accommodate new or increased production or changing product flows, we face competition in providing the required infrastructure solutions as well as the risk of building capacity in excess of sustained demand. Depending upon the specific movement, pipelines, which generally offer the lowest cost of transportation, may also face competition from other forms of transportation, such as rail and barge. Although these alternative forms of transportation are typically higher cost, they can provide access to alternative markets at which a higher price may be realized for the commodity being transported, thereby overcoming the increased transportation cost.

 

We also face competition with respect to our supply and logistics and facilities services. Our competitors include other crude oil pipeline companies, the major integrated oil companies, their marketing affiliates and independent gatherers, banks that have established a trading platform, brokers and marketers of widely varying sizes, financial resources and experience. Some of these competitors have capital resources many times greater than ours, and control greater supplies of crude oil.

 

With respect to our natural gas storage operations, the principal elements of competition are rates, terms of service, supply and market access and flexibility of service.  An increase in competition in our markets could arise from new ventures or expanded operations from existing competitors.  Our natural gas storage facilities compete with several other storage providers, including regional storage facilities and utilities. Certain major pipeline companies and independent storage providers also have existing storage facilities connected to their systems that compete with some of our facilities.

 

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Regulation

 

Our assets, operations and business activities are subject to extensive legal requirements and regulations under the jurisdiction of numerous federal, state, provincial and local agencies. Many of these agencies are authorized by statute to issue, and have issued, requirements binding on the pipeline industry, related businesses and individual participants. The failure to comply with such legal requirements and regulations can result in substantial penalties. At any given time there may be proposals, provisional rulings or proceedings in legislation or under governmental agency or court review that could affect our business. The regulatory burden on our assets, operations and activities increases our cost of doing business and, consequently, affects our profitability, but we do not believe that these laws and regulations affect us in a significantly different manner than our competitors. We may at any time also be required to apply significant resources in responding to governmental requests for information. In 2010 we settled by means of separate Consent Decrees, two ongoing Department of Justice (“DOJ”)/Environmental Protection Agency (“EPA”) proceedings regarding certain releases of crude oil. One Consent Decree applies to a specific system.  The other (the “General Consent Decree”) applies to our crude oil pipelines in general. Although we believe that all material aspects of the injunctive elements of the Consent Decrees (costs and operational effects) have been incorporated into our budgeting and planning process, future proceedings could result in additional injunctive remedies, the effect of which would subject us to operational requirements and constraints that would not apply to our competitors.

 

The following is a discussion of certain, but not all, of the laws and regulations affecting our operations.

 

Environmental, Health and Safety Regulation

 

General

 

Our operations involving the storage, treatment, processing, and transportation of liquid hydrocarbons including crude oil are subject to stringent federal, state, provincial and local laws and regulations governing the discharge of materials into the environment or otherwise relating to protection of the environment. As with the industry generally, compliance with these laws and regulations increases our overall cost of doing business, including our capital costs to construct, maintain and upgrade equipment and facilities. Failure to comply with these laws and regulations could result in the assessment of administrative, civil, and criminal penalties, the imposition of investigatory and remedial liabilities, and the issuance of injunctions that may subject us to additional operational constraints that our competitors are not required to follow. Environmental and safety laws and regulations are subject to changes that may result in more stringent requirements, and we cannot provide any assurance that compliance with current and future laws and regulations will not have a material effect on our results of operations or earnings. A discharge of hazardous liquids into the environment could, to the extent such event is not insured, subject us to substantial expense, including both the cost to comply with applicable laws and regulations and any claims made by third parties. The following is a summary of some of the environmental and safety laws and regulations to which our operations are subject.

 

Pipeline Safety/Pipeline and Storage Tank Integrity Management

 

A substantial portion of our petroleum pipelines and our storage tank facilities in the United States are subject to regulation by the Pipeline and Hazardous Materials Safety Administration (“PHMSA”) pursuant to the Hazardous Liquids Pipeline Safety Act of 1979, as amended (the “HLPSA”). The HLPSA imposes safety requirements on the design, installation, testing, construction, operation, replacement and management of pipeline and tank facilities. Federal regulations implementing the HLPSA require pipeline operators to adopt measures designed to reduce the environmental impact of oil discharges from onshore oil pipelines, including the maintenance of comprehensive spill response plans and the performance of extensive spill response training for pipeline personnel. These regulations also require pipeline operators to develop and maintain a written qualification program for individuals performing covered tasks on pipeline facilities. Comparable regulation exists in some states in which we conduct intrastate common carrier or private pipeline operations. Regulation in Canada is under the National Energy Board (“NEB”) and provincial agencies.

 

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United States

 

The HLPSA was amended by the Pipeline Safety Improvement Act of 2002 and the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006. These amendments have resulted in the adoption of rules by the Department of Transportation (“DOT”) that require transportation pipeline operators to implement integrity management programs, including more frequent inspections, correction of identified anomalies and other measures to ensure pipeline safety in “high consequence areas,” such as high population areas, areas unusually sensitive to environmental damage, and commercially navigable waterways. In the United States, our costs associated with the inspection, testing and correction of identified anomalies were approximately $39 million in 2012, $32 million in 2011 and $31 million in 2010. Based on currently available information, our preliminary estimate for 2013 is that we will incur approximately $21 million in operational expenditures and approximately $38 million in capital expenditures associated with our required pipeline integrity management program. Significant additional expenses could be incurred if new or more stringently interpreted pipeline safety requirements are implemented. Currently, we believe our pipelines are in substantial compliance with HLPSA and the 2002 and 2006 amendments. In addition to required activities, our integrity management program includes several internal programs designed to prevent incidents and includes activities such as automating valves and replacing river crossings. Costs incurred for such activities were approximately $24 million in 2012, $22 million in 2011 and $10 million in 2010, and our preliminary estimate for 2013 is that we will incur approximately $30 million.

 

On December 13, 2011, the United States Congress passed the “Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011” (the “Act”). The President signed the Act into law on January 3, 2012.  Under the Act, maximum civil penalties for certain violations have been increased from $100,000 to $200,000 per violation per day, and from a total cap of $1 million to $2 million.  In addition, the Act reauthorizes the federal pipeline safety programs of PHMSA through September 30, 2015, and directs the Secretary of Transportation to undertake a number of reviews, studies and reports, some of which may result in additional natural gas and hazardous liquids pipeline safety rulemaking.

 

A number of the provisions of the Act have the potential to cause owners and operators of pipeline facilities to incur significant capital expenditures and/or operating costs.  Any additional requirements resulting from these directives are not expected to impact us differently than our competitors.  We will work closely with our industry associations to participate with and monitor DOT-PHMSA’s efforts.

 

In December 2009, PHMSA finalized a new rule dictating the shape and content of new control room management programs for hazardous liquid, gas transmission and distribution pipelines.  The rule addresses human factors, including fatigue and other aspects of control room management for pipelines where controllers use supervisory control and data acquisition systems.  The new rule became effective on February 1, 2010 and requires that control room management plans be written by August 1, 2011, which we completed on time. Implementation of certain aspects such as fatigue training for Controllers and Supervisors, Change Management, Operating Experience and establishing Shift Change procedures was required and completed by October 1, 2011.  Implementation of the remaining aspects of the rule was completed by August 1, 2012.

 

We have an internal review process in which we examine the condition and operating history of our pipelines and gathering assets to determine if any of our assets warrant additional investment or replacement. Accordingly, in addition to potential cost increases related to unanticipated regulatory changes or injunctive remedies resulting from U.S. EPA enforcement actions, we may elect (as a result of our own internal initiatives) to spend substantial sums to ensure the integrity of and upgrade our pipeline systems and, in some cases, we may take pipelines out of service if we believe the cost of upgrades will exceed the value of the pipelines.

 

If approved by PHMSA, states may assume responsibility for enforcing federal interstate pipeline regulations as agents for PHMSA and conduct inspections of intrastate pipelines. In practice, states vary in their authority and capacity to address pipeline safety. We do not anticipate any significant issues in complying with applicable state laws and regulations.

 

The DOT has issued guidelines with respect to securing regulated facilities against terrorist attack. We have instituted security measures and procedures in accordance with such guidelines to enhance the protection of certain of our facilities. We cannot provide any assurance that these security measures would fully protect our facilities from an attack.

 

The DOT has adopted American Petroleum Institute Standard 653 (“API 653”) as the standard for the inspection, repair, alteration and reconstruction of steel aboveground petroleum storage tanks subject to DOT jurisdiction. API 653 requires regularly scheduled inspection and repair of tanks remaining in service. In the United States, costs associated with this program were approximately $31 million, $22 million and $25 million in 2012, 2011 and 2010, respectively. For 2013, we have budgeted approximately $30 million in connection with continued API 653 compliance activities and similar new EPA regulations for tanks not regulated by the DOT. Certain storage tanks may be taken out of service if we believe the cost of compliance will exceed the value of the storage tanks or replacement tankage may be constructed.

 

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Canada

 

In Canada, the NEB and provincial agencies such as the Energy Resources Conservation Board (“ERCB”) in Alberta and the Saskatchewan Ministry of Energy and Resources regulate the construction, alteration, inspection and repair of crude oil storage tanks. We have incurred and will continue to incur costs under laws and regulations related to pipeline and storage tank integrity, such as operator competency programs, regulatory upgrades to our operating and maintenance systems and environmental upgrades of buried sump tanks. We spent approximately $80 million in 2012, $35 million in 2011 and $23 million in 2010 on these types of costs. Our preliminary estimate for 2013 is approximately $109 million.

 

Although we believe that our pipeline operations are in substantial compliance with currently applicable regulatory requirements (including the Consent Decrees, to the extent applicable), we cannot predict the potential costs associated with additional, future regulation. Asset acquisitions are an integral part of our business strategy. As we acquire additional assets, we may be required to incur additional costs in order to ensure that the acquired assets comply with the regulatory standards (including the General Consent Decree) in the U.S. and Canada.

 

Occupational Safety and Health

 

United States

 

In the U.S., we are subject to the requirements of the Occupational Safety and Health Act, as amended (“OSHA”) and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that certain information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities and citizens. Certain of our facilities are subject to OSHA Process Safety Management (“PSM”) regulations, which are designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals.  These regulations apply to any process which involves a chemical at or above specified thresholds or any process that involves 10,000 pounds or more of a flammable liquid or gas in one location.  We believe that our operations are in substantial compliance with OSHA requirements, including general industry standards, recordkeeping requirements and monitoring of occupational exposure to regulated substances.

 

Canada

 

Similar regulatory requirements exist in Canada under the federal and provincial Occupational Health and Safety Acts and related regulations. The agencies with jurisdiction under these regulations are empowered to enforce them through inspection, audit, incident investigation or public or employee complaint. Additionally, under the Criminal Code of Canada, organizations, corporations and individuals may be prosecuted criminally for violating the duty to protect employee and public safety. We believe that our operations are in substantial compliance with applicable occupational health and safety requirements.

 

Solid Waste

 

We generate wastes, including hazardous wastes, which are subject to the requirements of the federal Resource Conservation and Recovery Act, as amended, (“RCRA”) and analogous state and provincial laws. Many of the wastes that we generate are not subject to the most stringent requirements of RCRA because our operations generate primarily oil and gas wastes, which currently are excluded from consideration as RCRA hazardous wastes. It is possible, however, that in the future oil and gas wastes may be included as hazardous wastes under RCRA, in which event our wastes as well as the wastes of our competitors will be subject to more rigorous and costly disposal requirements, resulting in additional capital expenditures or operating expenses.

 

Hazardous Substances

 

The federal Comprehensive Environmental Response, Compensation and Liability Act, as amended (“CERCLA”), also known as “Superfund,” and comparable state laws impose liability, without regard to fault or the legality of the original act, on certain classes of persons that contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of the site or sites where the release occurred and companies that disposed of, or arranged for the disposal of, the hazardous substances found at the site. Such persons may be subject to strict, joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain health studies. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. In the course of our ordinary operations, we may generate waste that falls within CERCLA’s definition of a “hazardous substance.”  Canadian and provincial laws also impose liabilities for releases of certain substances into the environment.

 

We are subject to the EPA’s Risk Management Plan regulations at certain facilities. These regulations are intended to work with OSHA’s PSM regulations (see “Occupational Safety and Health” above) to minimize the offsite consequences of catastrophic

 

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releases.  The regulations require us to develop and implement a risk management program that includes a five-year accident history, an offsite consequence analysis process, a prevention program and an emergency response program.  We believe we are operating in substantial compliance with our risk management program.

 

Environmental Remediation

 

We currently own or lease, and in the past have owned or leased, properties where hazardous liquids, including hydrocarbons, are or have been handled. These properties and the hazardous liquids or associated wastes disposed thereon may be subject to CERCLA, RCRA and state and Canadian federal and provincial laws and regulations. Under such laws and regulations, we could be required to remove or remediate hazardous liquids or associated wastes (including wastes disposed of or released by prior owners or operators) and to clean up contaminated property (including contaminated groundwater).

 

We maintain insurance of various types with varying levels of coverage that we consider adequate under the circumstances to cover our operations and properties. The insurance policies are subject to deductibles and retention levels that we consider reasonable and not excessive. Consistent with insurance coverage generally available in the industry, in certain circumstances our insurance policies provide limited coverage for losses or liabilities relating to gradual pollution, with broader coverage for sudden and accidental occurrences.

 

In conjunction with our acquisitions, we typically make an assessment of potential environmental exposure and determine whether to negotiate an indemnity, what the terms of any indemnity should be and whether to obtain environmental risk insurance, if available. These contractual indemnifications typically are subject to specific monetary requirements that must be satisfied before indemnification will apply, and have term and total dollar limits. For instance, in connection with the purchase of former Texas New Mexico (“TNM”) pipeline assets from Link Energy LLC (“Link”) in 2004, we identified a number of environmental liabilities for which we received a purchase price reduction from Link and recorded a total environmental reserve of $20 million, of which we agreed in an arrangement with TNM to bear the first $11 million in costs of pre-May 1999 environmental issues. TNM also agreed to pay all costs in excess of $20 million (excluding certain deductibles). TNM’s obligations are guaranteed by Shell Oil Products (“SOP”). As of December 31, 2012, we had incurred approximately $24 million of remediation costs associated with these sites, while SOP’s share has been approximately $13 million.

 

Other assets we have acquired or will acquire in the future may have environmental remediation liabilities for which we are not indemnified.

 

We have in the past experienced and in the future likely will experience releases of crude oil into the environment from our pipeline and storage operations. We also may discover environmental impacts from past releases that were previously unidentified.

 

Air Emissions

 

Our U.S. operations are subject to the U.S. Clean Air Act (“Clean Air Act”), comparable state laws and associated state and federal regulations. Our Canadian operations are subject to federal and provincial air emission regulations. In 2010, the Canadian Council of Ministers of the Environment agreed to move forward to finalize a new air quality management system.  The new Canadian standards for air quality and industrial air emissions are currently in development, with implementation expected to begin in 2013. Under these laws, permits may be required before construction can commence on a new or modified source of potentially significant air emissions, and operating permits may be required for sources already constructed. We may be required to incur certain capital and operating expenditures in the next several years to install air pollution control equipment and otherwise comply with more stringent federal, state, provincial and regional air emissions control requirements when we attempt to obtain or maintain permits and approvals for sources of air emissions. Although we believe that our operations are in substantial compliance with these laws in the areas in which we operate, we can provide no assurance that future compliance obligations will not have a material adverse effect on our financial condition or results of operations.

 

Climate Change Initiatives

 

Canada

 

In response to recent studies suggesting that emissions of carbon dioxide, methane and certain other gases may be contributing to warming of the Earth’s atmosphere, many nations, including Canada, have agreed to limit emissions of these gases, generally referred to as greenhouse gases (“GHG”), pursuant to the 1997 United Nations Framework Convention on Climate Change, also known as the “Kyoto Protocol.” The Kyoto Protocol required Canada to reduce its emissions of GHG to 6% below 1990 levels by 2012. However, by 2009, emissions in Canada were 17% higher than 1990 levels.  In December 2011, Canada withdrew from the Kyoto Protocol, but signed the “Durban Platform” committing it to a legally binding treaty to reduce GHG emissions, the terms of

 

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which are to be defined by 2015 and are to become effective in 2020. Environment Canada continues to promote the domestic GHG initiatives implemented while Canada was signatory to the Kyoto Protocol.

 

In 2007, in response to the Kyoto Protocol, the Canadian federal government introduced the Regulatory Framework for Air Emissions (also known as the “Turning the Corner”  measures) a regulatory framework for regulating industrial GHG emissions by establishing mandatory emissions reduction requirements on a sector basis. Originally, this framework was intended to be implemented by 2010; however no federally mandated reduction targets for GHGs have been implemented to date.  Since 2004, companies emitting more than 100 thousand tons per year (“kt/y”) of CO2 equivalent (“CO2e”) were required to report their GHG emissions under the Greenhouse Gas Emissions Reporting Program. In 2010, this reporting threshold was reduced to 50 kt/y. The current operations of PMC fall well below this 50 kt/y threshold.

 

In Alberta, the provincial government implemented the Specified Gas Emitters Regulation in 2007 (under the Alberta Environmental and Protection and Enhancement Act), which mandated a 12% reduction in emission intensity over 2003-2005 levels for all facilities emitting more than 100 kt/y of CO2e.  It is anticipated that the threshold for this regulation will be reduced in future years. Alberta also has a GHG reporting threshold at 50 kt/y of CO2e. Again, emissions from PMC’s facilities are well below the 50 kt/y threshold.

 

In April 2010, Environment Canada proposed the Passenger Automobile and Light Truck Greenhouse Gas Emission Regulations under the Canadian Environmental Protection Act (“CEPA”). Transportation is one of the largest sources of GHG emissions in Canada, accounting for about 27% of total GHG emissions in 2007. Passenger cars and light trucks account for approximately 12% of total GHG emissions or 45% of transportation emissions. The objective of the proposed regulations is to reduce GHG emissions by establishing mandatory GHG emission standards for new vehicles of the 2011 and later model years that are aligned with U.S. standards. The alignment of vehicle emission standards across North America will provide a level playing field for North American automobile manufacturers. The governments of Canada and the U.S. are consulting to develop aligned regulations to reduce emissions from heavy-duty trucks. In December 2010, the Canadian federal government finalized the Renewable Fuel Regulations under CEPA. These regulations require an annual average renewable content of five percent in gasoline and required a two percent renewable content in diesel fuel and heating oil by 2011. These requirements are further intended to reduce GHG emissions in the transportation sector. No other regulatory initiatives to reduce GHG emissions in the truck transportation sector have been announced.

 

In August 2011, Environment Canada released the text of the proposed regulations to reduce emissions from the coal-fired electricity sector.  The proposed regulations apply a stringent performance standard to coal-fired electricity generated units.  The standard will be based on parity with the emissions performance of high-efficiency natural gas generation.  This is expected to promote replacement of coal-fired units that are reaching the end of their economic life, and will encourage investment in cleaner generation technologies, such as high-efficiency natural gas generation and renewable energy, as well as the use of carbon capture and storage.  Regulations are scheduled to come into effect in July 2015, and are likely to stimulate increased demand for natural gas.  No other regulatory initiatives to reduce GHG emissions in the electricity sector have been announced.

 

With regard to the oil and gas industry and the pipeline transportation sector, it is unclear at this time what direction the government plans to take. However, given that there have been no specific regulatory changes announced to date regarding GHG emissions reduction in these sectors; any future initiatives would likely not take effect until beyond 2015.

 

United States

 

In 2009, the U.S. EPA adopted rules for establishing a GHG emissions reporting program.  Fewer than ten of our facilities are presently subject to the federal GHG reporting requirements.  These include facilities with combustion GHG emissions and potential fugitive emissions above the reporting thresholds.  We import sufficient quantities of finished fuel products into the U.S. to be required to report that activity as well.  We also continue to monitor GHG emissions for all of our facilities and activities.  At the present time, we do not anticipate the need to purchase GHG credits or install control technology to reduce GHG emissions at any of our facilities.

 

In 2010, the EPA promulgated regulations establishing Title V and Prevention of Significant Deterioration permitting requirements for large sources of GHG’s.  Fewer than ten of our existing facilities are potential major sources of GHG subject to these permitting requirements.  We may be required to install “best available control technology” to limit emissions of GHG’s from any new or significantly modified facilities that we may seek to construct in the future if they would otherwise emit large volumes of GHG’s.  The EPA is in the process of identifying what constitutes best available control technology for various sources of GHG emissions, but it appears likely that the agency will seek to impose efficient combustion requirements on sources that burn large volumes of fossil fuels rather than post-combustion GHG capture requirements.  If the EPA imposes efficient combustion requirements, we do not anticipate that they will have an adverse effect on the cost of our operations.

 

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In the absence of federal climate legislation in the U.S., a number of regional efforts have emerged aimed at reducing GHG emissions.  Two of the more significant non-federal GHG programs are the Regional Greenhouse Gas Initiative (RGGI) and the Western Climate Initiative (WCI).  RGGI, which includes a number of states in the northeastern U.S., implemented a cap-and-trade program in 2009.  At present, this program only applies to utility power plants.  None of our facilities are affected by RGGI.

 

The WCI originally included several U.S. states and Canadian provinces, either as full voting members or observers.  Most U.S. states have withdrawn from WCI, with California the sole remaining member from the U.S.  California has implemented a GHG cap-and-trade program, authorized under Assembly Bill 32 (“AB32”).  The California Air Resources Board has published a list of facilities expected to be subject to this program.  At this time, the list only includes one of our facilities, the Lone Star Gas Liquids facility in Shafter, California. The rules implementing the AB32 program were finalized in December 2011, and the first auction of GHG emission credits was conducted in the fall of 2012, with the average credit selling for $10.09 per ton.    The compliance requirements of the GHG cap-and-trade program will not kick in until 2013 and we do not anticipate any problems in complying with those obligations going forward or for such impacts to be material.

 

Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations could result in increased compliance costs or additional operating restrictions, and could have a material adverse effect on our business, financial condition, demand for our services, results of operations, and cash flows. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climate events that could have an adverse effect on our assets and operations.

 

The operations of our refinery customers could also be negatively impacted by current GHG legislation or new regulations resulting in increased operating or compliance costs.  Some of the proposed federal and state “cap and trade” legislation would require businesses that emit GHG’s to buy emission credits from government, other businesses, or through an auction process.  In addition, refiners could be required to purchase emission credits for GHG emissions resulting from their own refining operations as well as the fuels they sell.  While it is not possible at this time to predict the final form of “cap-and-trade” legislation, any new federal or state restrictions on GHG emissions could result in material increased compliance costs, additional operating restrictions and an increase in the cost of feedstock and products produced by our refinery customers.

 

Water

 

The Federal Water Pollution Control Act, as amended, also known as the Clean Water Act (“CWA”), and analogous state and Canadian federal and provincial laws impose restrictions and strict controls regarding the discharge of pollutants into navigable waters of the United States and Canada, as well as state and provincial waters. See “—Pipeline Safety/Pipeline and Storage Tank Integrity Management” above and Note 16 to our Consolidated Financial Statements. Federal, state and provincial regulatory agencies can impose administrative, civil and/or criminal penalties for non-compliance with discharge permits or other requirements of the CWA.

 

The Oil Pollution Act of 1990 (“OPA”) amended certain provisions of the CWA, as they relate to the release of petroleum products into navigable waters. OPA subjects owners of facilities to strict, joint and potentially unlimited liability for containment and removal costs, natural resource damages, and certain other consequences of an oil spill. We believe that we are in substantial compliance with applicable OPA requirements. State and Canadian federal and provincial laws also impose requirements relating to the prevention of oil releases and the remediation of areas affected by releases when they occur. We believe that we are in substantial compliance with all such federal, state and Canadian requirements.

 

With respect to our new pipeline construction activities and maintenance on our existing pipelines, Section 404 of the CWA authorizes the Army Corps of Engineers (“Corps”) to permit the discharge of dredged or fill materials into “navigable waters,” which are defined as “the waters of the United States.”  Section 404 (e) authorizes the Corps to issue permits on a nationwide basis for categories of discharges that have no more than minimal individual or cumulative environmental effects.  For the past 35 years, the Corps has authorized construction, maintenance and repair of pipelines under a streamlined nationwide permit program known as Nationwide Permit 12 (“NWP”).  In a June 2012 lawsuit (Sierra Club v. Bostick), to which we are not a party, plaintiff seeks to have the court strike down the NWP.   NWP is supported by strong statutory and regulatory history and was originally approved by Congress in 1977.  In the event the court rules in favor of the plaintiff and wholly or partially strikes down NWP, which we believe is unlikely, we could face significant delays and financial costs when seeking project approvals.

 

Other Regulation

 

Transportation Regulation

 

Our transportation activities are subject to regulation by multiple governmental agencies. Our historical and projected operating costs reflect the recurring costs resulting from compliance with these regulations, and we do not anticipate material expenditures in excess of these amounts in the absence of future acquisitions or changes in regulation, or discovery of existing but unknown compliance issues. The following is a summary of the types of transportation regulation that may impact our operations.

 

General Interstate Regulation.  Our interstate common carrier liquids pipeline operations are subject to rate regulation by the FERC under the Interstate Commerce Act (“ICA”). The ICA requires that tariff rates for liquids pipelines, which include both crude oil pipelines and refined products pipelines, be just and reasonable and non-discriminatory.

 

State Regulation.  Our intrastate liquids pipeline transportation activities are subject to various state laws and regulations, as well as orders of state regulatory bodies, including the Railroad Commission of Texas (“TRRC”) and the California Public Utility

 

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Commission (“CPUC”). The CPUC prohibits certain of our subsidiaries from acting as guarantors of our senior notes and credit facilities.

 

Regulation of OCS Pipelines.  The Outer Continental Shelf Lands Act requires that all pipelines operating on or across the OCS provide open access, non-discriminatory transportation service. In June 2008, the Minerals Management Service (now replaced by the Bureau of Ocean Energy Management, Regulation and Enforcement) issued a final rule establishing formal and informal complaint procedures for shippers that believe they have been denied open and nondiscriminatory access to transportation on the OCS. We do not expect the rule to have a material impact on our operations or results.

 

Energy Policy Act of 1992 and Subsequent Developments.  In October 1992, Congress passed the Energy Policy Act of 1992 (“EPAct”), which, among other things, required the FERC to issue rules to establish a simplified and generally applicable ratemaking methodology for petroleum pipelines and to streamline procedures in petroleum pipeline proceedings. The FERC responded to this mandate by establishing a formulaic methodology for petroleum pipelines to change their rates within prescribed ceiling levels that are tied to an inflation index. The FERC reviews the formula every five years. Effective July 1, 2011, the annual index adjustment for the five year period ending June 30, 2016 will equal the producer price index for finished goods for the applicable year plus an adjustment factor of 2.65 percent. Pipelines may raise their rates to the rate ceiling level generated by application of the annual index adjustment factor each year; however, a shipper may challenge such increase if the increase in the pipeline’s rates was substantially in excess of the actual cost increases incurred by the pipeline during the relevant year. If FERC’s annual index adjustment reduces the ceiling level such that it is lower than a pipeline’s filed rate, the pipeline must reduce its rate to conform with the lower ceiling unless doing so would reduce a rate “grandfathered” by the EPAct (see below) to below the grandfathered level. A pipeline must, as a general rule, use the indexing methodology to change its rates. The FERC, however, retained cost-of-service ratemaking, market-based rates and settlement rates as alternatives to the indexing approach that may be used in certain specified circumstances. Because the indexing methodology for the next five-year period is tied to an inflation index and is not based on pipeline-specific costs, the indexing methodology could hamper our ability to recover cost increases.

 

Under the EPAct, petroleum pipeline rates in effect for the 365-day period ending on the date of enactment of EPAct are deemed to be just and reasonable under the ICA, if such rates had not been subject to complaint, protest or investigation during such 365-day period. Generally, complaints against such “grandfathered” rates may only be pursued if the complainant can show that a substantial change has occurred since the enactment of EPAct in either the economic circumstances of the oil pipeline or in the nature of the services provided that were a basis for the rate. EPAct places no such limit on challenges to a provision of an oil pipeline tariff as unduly discriminatory or preferential.

 

Canadian Regulation.  Our Canadian pipeline assets are subject to regulation by the NEB and by provincial authorities, such as the Alberta ERCB. With respect to a pipeline over which it has jurisdiction, the relevant regulatory authority has the power, upon application by a third party, to determine the rates we are allowed to charge for transportation on, and set other terms of access to, such pipeline. In such circumstances, if the relevant regulatory authority determines that the applicable terms and conditions of service are not just and reasonable, the regulatory authority can impose conditions it considers appropriate.

 

Our Pipelines.  The FERC generally has not investigated rates of liquids pipelines on its own initiative when those rates have not been the subject of a protest or complaint by a shipper. The majority of our transportation segment profit in the U.S. is produced by rates that are either grandfathered or set by agreement with one or more shippers. In Canada, rates are set to cover operating costs and a return on capital, without specific agreements with shippers.  Shippers may make application to federal or provincial regulatory agencies if they disagree with rates that have been set.

 

Trucking Regulation

 

United States

 

We operate a fleet of trucks to transport crude oil and oilfield materials as a private, contract and common carrier. We are licensed to perform both intrastate and interstate motor carrier services. As a motor carrier, we are subject to certain safety regulations issued by the DOT. The trucking regulations cover, among other things: (i) driver operations, (ii) log book maintenance, (iii) truck manifest preparations, (iv) safety placard placement on the trucks and trailer vehicles, (v) drug and alcohol testing, (vi) operation and equipment safety and (vii) many other aspects of truck operations. We are also subject to OSHA with respect to our trucking operations.

 

Canada

 

Our trucking assets in Canada are subject to regulation by both federal and provincial transportation agencies in the provinces in which they are operated. These regulatory agencies do not set freight rates, but do establish and administer rules and regulations relating to other matters including equipment, facility inspection, reporting and safety. We are licensed to operate both intra and inter provincially under the direction of the National Safety Code (NSC) that is administered by Transport Canada.  Our for-hire service is

 

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primarily the transportation of crude oil, condensates and NGL.  We are required under the NCS among other things to monitor: (i) driver operations, (ii) log book maintenance, (iii) truck manifest preparations, (iv) safety placard placement on the trucks and trailers, (v) operation and equipment safety and (vi) many other aspects of trucking operations.  We are also subject to Occupational Health and Safety regulations with respect to our trucking operations.

 

Railcar Regulation

 

We operate a number of railcar loading and unloading facilities, and lease a significant number of railcars, in the United States and Canada.  Our railcar operations are subject to the regulatory jurisdiction of the Federal Railroad Administration of the DOT, the Occupational Safety and Health Administration, as well as other federal and state regulatory agencies and Canadian regulatory agencies for operations in Canada.  We believe that our railcar operations are in substantial compliance with all existing federal, state, and local regulations.

 

Cross Border Regulation

 

As a result of our cross border activities, including importation of crude oil, NGL and natural gas between the United States and Canada, we are subject to a variety of legal requirements pertaining to such activities including export/import license requirements, tariffs, Canadian and U.S. customs and taxes and requirements relating to toxic substances. U.S. legal requirements relating to these activities include regulations adopted pursuant to the Short Supply Controls of the Export Administration Act, the North American Free Trade Agreement and the Toxic Substances Control Act. Violations of these licensing, tariff and tax reporting requirements or failure to provide certifications relating to toxic substances could result in the imposition of significant administrative, civil and criminal penalties. Furthermore, the failure to comply with U.S., Canadian, state, provincial and local tax requirements could lead to the imposition of additional taxes, interest and penalties.

 

Market Anti-Manipulation Regulation

 

In November 2009, the Federal Trade Commission (“FTC”) issued regulations pursuant to the Energy Independence and Security Act of 2007, intended to prohibit market manipulation in the petroleum industry.  Violators of the regulations face civil penalties of up to $1 million per violation per day.  In July 2010, Congress passed the Dodd-Frank Act, which incorporated an expansion of the authority of the Commodity Futures Trading Commission (“CFTC”) to prohibit market manipulation in the markets regulated by the CFTC.  This authority, with respect to crude oil swaps and futures contracts, is similar to the anti-manipulation authority granted to the FTC with respect to crude oil purchases and sales.  In November 2010, the CFTC issued proposed rules to implement their new anti-manipulation authority.  The proposed rules would subject violators to a civil penalty of up to the greater of $1 million or triple the monetary gain to the person for each violation.

 

We have not experienced a material impact from the FTC regulations.  The CFTC rules are not final.  We will continue to monitor the status of proposed rules.

 

Natural Gas Storage Regulation

 

PNG is subject to extensive laws and regulations.  PNG’s natural gas storage operations are subject to regulatory oversight by numerous federal, state and local regulatory agencies, many of which are authorized by statute to issue, and have issued, rules and regulations binding on the natural gas storage and pipeline industry, related businesses and market participants.  The failure to comply with such laws and regulations can result in substantial penalties and fines.  The regulatory burden increases our cost of doing business and, consequently, affects our profitability.  Our historical and projected operating costs reflect the recurring costs resulting from compliance with these regulations, and we do not anticipate material expenditures in excess of these amounts in the absence of future acquisitions or changes in regulation, or discovery of existing but unknown compliance issues.  We do not believe that we are affected by applicable laws and regulations in a significantly different manner than are our competitors.

 

The following is a summary of the kinds of regulation that may impact our natural gas storage operations.  However, our unitholders should not rely on such discussion as an exhaustive review of all regulatory considerations affecting our natural gas storage operations.

 

Our natural gas storage facilities provide natural gas storage services in interstate commerce and are subject to comprehensive regulation by the FERC under the Natural Gas Act of 1938 (“NGA”).  Pursuant to the NGA and FERC regulations, storage providers are prohibited from making or granting any undue preference or advantage to any person or subjecting any person to any undue prejudice or disadvantage or from maintaining any unreasonable difference in rates, charges, service, facilities, or in any other respect.  The terms and conditions for services provided by our facilities are set forth in FERC approved tariffs.  We have been

 

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granted market-based rate authorization for the services that our facilities provide.  Market-based rate authority allows us to negotiate rates with individual customers based on market demand.

 

The FERC also has authority over the siting, construction, and operation of U.S. pipeline transportation and storage facilities and related facilities used in the transportation, storage and sale for resale of natural gas in interstate commerce, including the extension, enlargement or abandonment of such facilities.  The FERC’s authority extends to maintenance of accounts and records, terms and conditions of service, acquisition and disposition of facilities, initiation and discontinuation of services, imposition of creditworthiness and credit support requirements applicable to customers and relationships among pipelines and storage companies and certain affiliates.  Our natural gas storage entities are required by the FERC to post certain information daily regarding customer activity, capacity and volumes on their respective websites. Additionally, the FERC has jurisdiction to impose rules and regulations applicable to all natural gas market participants including PNG Marketing and PAA Natural Gas Canada to ensure market transparency. FERC regulations require that buyers and sellers of more than a de minimis volume of natural gas report annual numbers and volumes of relevant transactions to the FERC.  Our natural gas storage facilities and related marketing entities are subject to these annual reporting requirements.

 

Under the Energy Policy Act of 2005 (“EPAct 2005”) and related regulations, it is unlawful in connection with the purchase or sale of natural gas or transportation services subject to FERC jurisdiction to use or employ any device, scheme or artifice to defraud; to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or to engage in any act or practice that operates as a fraud or deceit upon any person.  EPAct 2005 gives the FERC civil penalty authority to impose penalties for certain violations of up to $1,000,000 per day for each violation.  FERC also has the authority to order disgorgement of profits from transactions deemed to violate the NGA and the EPAct 2005.

 

Bluewater provides storage service by means of receipts or deliveries of natural gas at the international border with Canada or within the Province of Ontario. The importation and exportation of natural gas from and to the U.S. and Canada is subject to regulation by U.S. Customs and Border Protection, U.S. Department of Energy and the NEB.  Bluewater, PNG Marketing and PAA Natural Gas Canada have regulatory authorization to import and export natural gas from and to the U.S. and Canada.

 

The natural gas industry historically has been heavily regulated. New rules, orders, regulations or laws may be passed or implemented that impose additional costs, burdens or restrictions on us. We cannot give any assurance regarding the likelihood of such future rules, orders, regulations or laws or the effect they could have on our business, financial condition, and results of operations or ability to make distributions to our unitholders.

 

Operational Hazards and Insurance

 

Pipelines, terminals, trucks or other facilities or equipment may experience damage as a result of an accident or natural disaster. These hazards can cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage and suspension of operations. Since the time we and our predecessors commenced midstream crude oil activities in the early 1990s, we have maintained insurance of various types and varying levels of coverage that we consider adequate under the circumstances to cover our operations and properties. The insurance policies are subject to deductibles and retention levels that we consider reasonable and not excessive. However, such insurance does not cover every potential risk associated with operating pipelines, terminals and other facilities, including the potential loss of significant revenues. Consistent with insurance coverage generally available to the industry, in certain circumstances our insurance policies provide limited coverage for losses or liabilities relating to gradual pollution, with broader coverage for sudden and accidental occurrences. Over the last several years, our operations have expanded significantly, with total assets increasing over thirty times since the end of 1998. At the same time that the scale and scope of our business activities have expanded, the breadth and depth of the available insurance markets have contracted. The overall cost of such insurance as well as the deductibles and overall retention levels that we maintain have increased. As a result, we have elected to self-insure more activities against certain of these operating hazards and expect this trend will continue in the future. Due to the events of September 11, 2001, insurers have excluded acts of terrorism and sabotage from our insurance policies. We have elected to purchase a separate insurance policy for acts of terrorism and sabotage.

 

Since the terrorist attacks, the United States Government has issued numerous warnings that energy assets, including our nation’s pipeline infrastructure, may be future targets of terrorist organizations. These developments expose our operations and assets to increased risks. We have instituted security measures and procedures in conformity with DOT guidance. We will institute, as appropriate, additional security measures or procedures indicated by the DOT or the Transportation Safety Administration. However, we cannot assure you that these or any other security measures would protect our facilities from an attack. Any future terrorist attacks on our facilities, those of our customers and, in some cases, those of our competitors, could have a material adverse effect on our business, whether insured or not.

 

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The occurrence of a significant event not fully insured, indemnified or reserved against, or the failure of a party to meet its indemnification obligations, could materially and adversely affect our operations and financial condition. We believe we are adequately insured for public liability and property damage to others with respect to our operations. We believe that our levels of coverage and retention are generally consistent with those of similarly situated companies in our industry. With respect to all of our coverage, no assurance can be given that we will be able to maintain adequate insurance in the future at rates we consider reasonable, or that we have established adequate reserves to the extent that such risks are not insured.

 

Title to Properties and Rights-of-Way

 

Our real property holdings are generally comprised of: (i) parcels of land that we own in fee, (ii) surface leases, underground storage leases and (iii) easements, rights-of-way, permits, crossing agreements or licenses from landowners or governmental authorities permitting the use of certain lands for our operations. We believe we have satisfactory title or the right to use the sites upon which our significant facilities are located, subject to customary liens, restrictions or encumbrances. We have no knowledge of any challenge to the underlying fee title of any material fee, lease, easement, right-of-way, permit or license held by us or to our rights pursuant to any material deed, lease, easement, right-of-way, permit or license, and we believe that we have satisfactory rights pursuant to all of our material leases, easements, rights-of-way, permits and licenses. Some of our real property rights (mainly for pipelines) may be subject to termination under agreements that provide for one or more of: periodic payments, term periods, renewal rights, revocation by the licensor or grantor and possible relocation obligations. We believe that our real property holdings are adequate for the conduct of our business activities and that none of the burdens discussed above will materially (i) detract from the value of such properties or (ii) interfere with the use of such properties in our business.

 

Employees and Labor Relations

 

To carry out our operations, our general partner or its affiliates (including Plains Midstream Canada) employed approximately 4,700 employees at December 31, 2012. None of the employees of our general partner are subject to a collective bargaining agreement, except for eight employees covered by an agreement scheduled for renegotiation in September 2015 and another nine employees covered by another agreement scheduled for renegotiation in September 2013. Our general partner considers its employee relations to be good.

 

Summary of Tax Considerations

 

The following is a brief summary of material tax considerations of owning and disposing of common units, however, the tax consequences of ownership of common units depends in part on the owner’s individual tax circumstances. It is the responsibility of each unitholder, either individually or through a tax advisor, to investigate the legal and tax consequences, under the laws of pertinent U.S. federal, states and localities, as well as Canada and the Canadian provinces, of the unitholder’s investment in us. Further, it is the responsibility of each unitholder to file all U.S. federal, Canadian, state, provincial and local tax returns that may be required of the unitholder.  Also see Item 1A. “Risk Factors—Tax Risks to Common Unitholders.”

 

Partnership Status; Cash Distributions

 

We are treated for federal income tax purposes as a partnership based upon our meeting the “Qualifying Income Exception” imposed by Section 7704 of the Internal Revenue Code (the “Code”), which we must meet each year. The owners of our common units are considered partners in the Partnership so long as they do not loan their common units to others to cover short sales or otherwise dispose of those units. Accordingly, we are not liable for U.S. federal income taxes, and a common unitholder is required to report on the unitholder’s federal income tax return the unitholder’s share of our income, gains, losses and deductions. In general, cash distributions to a common unitholder are taxable only if, and to the extent that, they exceed the tax basis in the common units held. In certain cases, we are subject to, or have paid Canadian income and withholding taxes. Canadian withholding taxes are due on intercompany interest payments and dividend payments and are treated as income tax expenses as a result of our restructuring of how we hold our Canadian investment on January 1, 2011.  Unitholders may be eligible for foreign tax credits with respect to allocable Canadian withholding and income taxes paid.

 

Partnership Allocations

 

In general, our income and loss is allocated to the general partner and the unitholders for each taxable year in accordance with their respective percentage interests in the Partnership, as determined annually and prorated on a monthly basis and subsequently apportioned among the general partner and the unitholders of record as of the opening of the first business day of the month to which they relate, even though unitholders may dispose of their units during the month in question. In determining a unitholder’s U.S. federal income tax liability, the unitholder is required to take into account the unitholder’s share of income generated by us for each taxable year of the Partnership ending with or within the unitholder’s taxable year, even if cash distributions are not made to the unitholder. As a consequence, a unitholder’s share of our taxable income (and possibly the income tax payable by the unitholder with respect to

 

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such income) may exceed the cash actually distributed to the unitholder by us. Any time incentive distributions are made to the general partner, gross income will be allocated to the recipient to the extent of those distributions.

 

Basis of Common Units

 

A unitholder’s initial tax basis for a common unit is generally the amount paid for the common unit and the unitholder’s share of our nonrecourse liabilities (or liabilities for which no partner bears the economic risk of loss). A unitholder’s basis is generally increased by the unitholder’s share of our income and by any increases in the unitholder’s share of our nonrecourse liabilities. That basis will be decreased, but not below zero, by the unitholder’s share of our losses and distributions (including deemed distributions due to a decrease in the unitholder’s share of our nonrecourse liabilities).

 

Limitations on Deductibility of Partnership Losses

 

The deduction by a unitholder of that unitholder’s allocable share of our losses will be limited to the amount of that unitholder’s tax basis in his or her common units and, in the case of an individual unitholder or a corporate unitholder who is subject to the “at risk” rules (generally, certain closely-held corporations), to the amount for which the unitholder is considered to be “at risk” with respect to our activities, if that is less than the unitholder’s tax basis. A unitholder must recapture losses deducted in previous years to the extent that distributions cause the unitholder’s at risk amount to be less than zero at the end of any taxable year.  Losses disallowed to a unitholder or recaptured as a result of these limitations will carry forward and will be allowable as a deduction to the extent that his at-risk amount is subsequently increased, provided such losses do not exceed such unitholder’s tax basis in his common units.  Upon the taxable disposition of a common unit, any gain recognized by a unitholder can be offset by losses that were previously suspended by the at risk limitation but may not be offset by losses suspended by the basis limitation. Any loss previously suspended by the at risk limitation in excess of that gain could no longer be used.

 

In addition to the basis and at-risk limitations described above, a passive activity loss limitation generally limits the deductibility of losses incurred by individuals, estates, trusts, some closely-held corporations and personal service corporations from “passive activities” (generally, trade or business activities in which the taxpayer does not materially participate). The passive loss limitations are applied separately with respect to each publicly-traded partnership. Consequently, any passive losses we generate will be available to offset only passive income generated by us, and will not be available to offset your income from other passive activities or investments, including your investments in other publicly traded partnerships (including PAA Natural Gas Storage, L.P.) or your salary, active business or other income. The application of the passive loss limitations to tiered partnerships is uncertain. However, we will take the position that any passive losses we generate that are reasonably allocable to our investment in any publicly-traded partnership (such as PAA Natural Gas Storage, L.P.) in which we own an interest will only be available to offset its passive income generated in the future, and will not be available to offset our income from any other passive activities. Passive losses that exceed a unitholder’s share of passive income we generate may be deducted in full when the unitholder disposes of all of its units in a fully taxable transaction with an unrelated party. The passive activity loss rules are generally applied after other applicable limitations on deductions, including the at risk and basis limitations.

 

Section 754 Election

 

We have made the election provided for by Section 754 of the Code, which will generally result in a unitholder being allocated income and deductions calculated by reference to the portion of the unitholder’s purchase price attributable to each asset of the Partnership.

 

Disposition of Common Units

 

A unitholder who sells common units will recognize gain or loss equal to the difference between the amount realized and the adjusted tax basis of those common units. A unitholder may not be able to trace basis to particular common units for this purpose. Thus, distributions of cash from us to a unitholder in excess of the income allocated to the unitholder will, in effect, become taxable income if the unitholder sells the common units at a price greater than the unitholder’s adjusted tax basis even if the price is less than the unitholder’s original cost. Moreover, a portion of the amount realized (whether or not representing gain) will be taxed as ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, a unitholder may incur a tax liability in excess of the amount of cash the unitholder receives from the sale.

 

State, Local and Other Tax Considerations

 

In addition to federal income taxes, unitholders will likely be subject to other taxes, including state and local income taxes, unincorporated business taxes, and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which a unitholder resides or in which we conduct business or own property. We own property and conduct business in most states in the

 

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United States as well as several provinces in Canada. A unitholder may also be required to file state income tax returns and to pay taxes in various states, even if they do not live in those jurisdictions. As a result of an organizational restructuring of our Canadian entities as of January 1, 2011, our Canadian-source income will pass through a taxable entity and thus will not be subject to Canadian filing obligations for our unitholders. For 2010 and prior years, a unitholder was required to file Canadian federal income tax returns and to pay Canadian federal and provincial income taxes in respect of our Canadian source income earned by partnership entities that were pass-through entities for tax purposes. Unitholders who are not resident in the United States may have additional tax reporting and payment requirements.

 

A unitholder may be subject to interest and penalties for failure to comply with such requirements. In certain states, tax losses may not produce a tax benefit in the year incurred (if, for example, we have no income from sources within that state) and also may not be available to offset income in subsequent taxable years. Some states may require us, or we may elect, to withhold a percentage of income from amounts to be distributed to a unitholder who is not a resident of the state. Withholding, the amount of which may be more or less than a particular unitholder’s income tax liability owed to a particular state, may not relieve the unitholder from the obligation to file an income tax return in that state. Amounts withheld may be treated as if distributed to unitholders for purposes of determining the amounts distributed by us.

 

Ownership of Common Units by Tax-Exempt Organizations and Certain Other Investors

 

An investment in common units by tax-exempt organizations (including Individual Retirement Accounts (“IRAs”) and other retirement plans) and non-U.S. persons raises issues unique to such persons. Virtually all of our income allocated to a unitholder that is a tax-exempt organization is unrelated business taxable income and, thus, is taxable to such a unitholder. A unitholder who is a nonresident alien, non-U.S. corporation or other non-U.S. person is regarded as being engaged in a trade or business in the United States as a result of ownership of a common unit and, thus, is required to file federal income tax returns and to pay tax on the unitholder’s share of our taxable income. Finally, distributions to non-U.S. unitholders are subject to federal income tax withholding at the highest applicable rate.

 

Available Information

 

We make available, free of charge on our Internet website at www.paalp.com, our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after we electronically file the material with, or furnish it to, the Securities and Exchange Commission (SEC).

 

Item 1A.  Risk Factors

 

Risks Related to Our Business

 

We may not be able to fully implement or capitalize upon planned growth projects.

 

We have a number of organic growth projects that involve the construction of new midstream energy infrastructure assets or the expansion or modification of existing assets. Many of these projects involve numerous regulatory, environmental, commercial, economic, weather-related, political and legal uncertainties that are beyond our control, including the following:

 

·                  As these projects are undertaken, required approvals, permits and licenses may not be obtained, may be delayed or may be obtained with conditions that materially alter the expected return associated with the underlying projects;

·                  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 not be able to secure, 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;

·                  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, 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.

 

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As a result of these uncertainties, the anticipated benefits associated with our capital projects may not be achieved.  In turn, this could negatively impact our cash flow and our ability to make or increase cash distributions to our partners.

 

Our results of operations are influenced by the overall forward market for crude oil, and certain market structures or the absence of pricing volatility may adversely impact our results.

 

Results from our supply and logistics segment are influenced by the overall forward market for crude oil. A contango market is favorable to commercial strategies that are associated with storage capacity as it allows a party to simultaneously purchase crude oil at current prices for storage and sell at higher prices for future delivery. Wide contango spreads combined with price structure volatility generally have a favorable impact on our results. A backwardated market (meaning that the price of crude oil for future deliveries is lower than current prices) has a positive impact on lease gathering margins because crude oil gatherers can capture a premium for prompt deliveries; however, in this environment there is little incentive to store crude oil as current prices are above future delivery prices. In either case, margins can be improved when prices are volatile. The periods between these two market structures are referred to as transition periods. If the market is in a backwardated to transitional structure, our results from our supply and logistics segment may be less than those generated during the more favorable contango market conditions. Additionally, a prolonged transition period or a lack of volatility in the pricing structure may further negatively impact our results. Depending on the overall duration of these transition periods, how we have allocated our assets to particular strategies and the time length of our crude oil purchase and sale contracts and storage lease agreements, these transition periods may have either an adverse or beneficial effect on our aggregate segment profit. A prolonged transition from a backwardated market to a contango market, or vice versa (essentially a market that is neither in pronounced backwardation nor contango), represents the least beneficial environment for our supply and logistics segment.

 

A natural disaster, catastrophe, terrorist attack or other event, including attacks on our electronic and computer systems, could interrupt our operations and/or result in severe personal injury, property damage and environmental damage, which could have a material adverse effect on our financial position, results of operations and cash flows.

 

Some of our operations involve risks of personal injury, property damage and environmental damage, which could curtail our operations and otherwise materially adversely affect our cash flow. Virtually all of our operations are exposed to potential natural disasters, including hurricanes, tornadoes, storms, floods and/or earthquakes. The location of our assets and our customers’ assets in the U.S. Gulf Coast region makes them particularly vulnerable to hurricane or tropical storm risk. In addition, since the September 11, 2001 terrorist attacks, the U.S. government has issued warnings that energy assets, specifically the nation’s pipeline infrastructure, may be future targets of terrorist organizations. Terrorists may target our physical facilities and hackers may attack our electronic and computer systems.

 

If one or more of our facilities, including electronic and computer systems, or any facilities or businesses that deliver products, supplies or services to us or that we rely on in order to operate our business, are damaged by severe weather or any other disaster, accident, catastrophe, terrorist attack or event, our operations could be significantly interrupted. These interruptions could involve significant damage or injury to people, property or the environment, and repairs could take from a week or less for minor incidents to six months or more for major interruptions. Any such event that interrupts the revenues generated by our operations, or which causes us to make significant expenditures not covered by insurance, could reduce our cash available for paying distributions and, accordingly, adversely affect our financial condition and the market price of our securities.

 

If we do not make acquisitions or if we make acquisitions that fail to perform as anticipated, our future growth may be limited.

 

Our ability to grow our distributions depends in part on our ability to make acquisitions that result in an increase in operating surplus per unit. If we are unable to make such accretive acquisitions either because we are (i) unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with the sellers, (ii) unable to raise financing for such acquisitions on economically acceptable terms or (iii) outbid by competitors, our future growth will be limited. As a result, we may not be able to complete the number or size of acquisitions that we have targeted internally or to continue to grow as quickly as we have historically.

 

In evaluating acquisitions, we generally prepare one or more financial cases based on a number of business, industry, economic, legal, regulatory, and other assumptions applicable to the proposed transaction. Although we expect a reasonable basis will exist for those assumptions, the assumptions will generally involve current estimates of future conditions. Realization of many of the assumptions will be beyond our control. Moreover, the uncertainty and risk of inaccuracy associated with any financial projection will increase with the length of the forecasted period. Some acquisitions may not be accretive in the near term, and will be accretive in the long term only if we are able to timely and effectively integrate the underlying assets and such assets perform at or near the levels anticipated in our acquisition projections.

 

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Our acquisition strategy involves risks that may adversely affect our business.

 

Any acquisition involves potential risks, including:

 

·                  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, 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.

 

Any of these factors could adversely affect our ability to achieve anticipated levels of cash flows from our acquisitions, realize other anticipated benefits and our ability to pay distributions or meet our debt service requirements.

 

Our growth strategy requires access to new capital. Tightened capital markets or other factors that increase our cost of capital could impair our ability to grow.

 

We continuously consider potential acquisitions and opportunities for organic growth projects. Acquisition transactions can be effected quickly, may occur at any time and may be significant in size relative to our existing assets and operations. Our ability to fund our capital projects and make acquisitions depends on whether we can access the necessary financing to fund these activities.  Any limitations on our access to capital or increase in the cost of that capital could significantly impair our growth strategy. Our ability to maintain our targeted credit profile, including maintaining our credit ratings, could affect our cost of capital as well as our ability to execute our growth strategy. In addition, a variety of factors beyond our control could impact the availability or cost of capital, including domestic or international economic conditions, changes in key benchmark interest rates, the adoption of new or amended banking or capital market laws or regulations, the re-pricing of market risks and volatility in capital and financial markets.

 

Due to these factors, we cannot be certain that funding for our capital needs will be available from bank credit arrangements or capital markets on acceptable terms. If funding is not available when needed, or is available only on unfavorable terms, we may be unable to implement our development plans, enhance our existing business, complete acquisitions and construction projects, take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our revenues and results of operations.

 

Loss of our investment grade credit rating or the ability to receive open credit could negatively affect our ability to purchase crude oil, natural gas and NGL supplies or to capitalize on market opportunities.

 

We believe that, because of our strategic asset base and complementary business model, we will continue to benefit from swings in market prices and shifts in market structure during periods of volatility in the crude oil, natural gas and NGL markets. The extent to which we are able to capture that benefit, however, is subject to numerous risks and uncertainties, including whether we will be able to maintain an attractive credit rating and continue to receive open credit from our suppliers and trade counterparties. Our senior unsecured debt is currently rated as “investment grade” by Standard & Poor’s and Moody’s Investors Service.  A downgrade by either of such rating agencies could increase our borrowing costs, reduce our borrowing capacity and cause our counterparties to reduce the amount of open credit we receive from them.  This could negatively impact our ability to capitalize on market opportunities. For example, our ability to utilize our crude oil storage capacity for merchant activities to capture contango market opportunities (meaning that the price of crude oil for future deliveries is higher than current prices) is dependent upon having adequate credit facilities, both in terms of the total amount of credit facilities and the cost of such credit facilities, which enables us to finance the storage of the crude oil from the time we complete the purchase of the oil until the time we complete the sale of the oil.

 

We are exposed to the credit risk of our customers in the ordinary course of our business activities.

 

Risks of nonpayment and nonperformance by customers are a significant consideration in our business.  Although we have credit risk management policies and procedures that are designed to mitigate and limit our exposure in this area, there can be no assurance that we have adequately assessed and managed the creditworthiness of our existing or future counterparties or that there will

 

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not be an unanticipated deterioration in their creditworthiness or unexpected instances of nonpayment or nonperformance, all of which could have an adverse impact on our cash flow and our ability to pay or increase our cash distributions to our partners.

 

In those cases in which we provide division order services for crude oil purchased at the wellhead, we may be responsible for distribution of proceeds to all parties. In other cases, we pay all of or a portion of the production proceeds to an operator who distributes these proceeds to the various interest owners. These arrangements expose us to operator credit risk, and there can be no assurance that we will not experience losses in dealings with such operators and other parties.

 

Our risk policies cannot eliminate all risks. In addition, any non-compliance with our risk policies could result in significant financial losses.

 

Generally, it is our policy that we establish a margin for crude oil or other products we purchase by selling such products for physical delivery to third-party users, or by entering into a future delivery obligation under derivative contracts. Through these transactions, we seek to maintain a position that is substantially balanced between purchases on the one hand, and sales or future delivery obligations on the other hand. Our policy is not to acquire and hold physical inventory or derivative products for the purpose of speculating on commodity price changes. These policies and practices cannot, however, eliminate all risks. For example, any event that disrupts our anticipated physical supply of crude oil or other products could expose us to risk of loss resulting from price changes. We are also exposed to basis risk when crude oil or other products are purchased against one pricing index and sold against a different index. Moreover, we are exposed to some risks that are not hedged, including risks on certain of our inventory, such as linefill, which must be maintained in order to transport crude oil on our pipelines. In an effort to maintain a balanced position, specifically authorized personnel can purchase or sell an aggregate limit of up to 800,000 barrels of crude oil, refined products and NGL. Although this activity is monitored independently by our risk management function, it exposes us to risks within predefined limits and authorizations.

 

In addition, our operations involve the risk of non-compliance with our risk policies. We have taken steps within our organization to implement processes and procedures designed to detect unauthorized trading; however, we can provide no assurance that these steps will detect and prevent all violations of our risk policies and procedures, particularly if deception, collusion or other intentional misconduct is involved.

 

Our operations are also subject to laws and regulations relating to protection of the environment and wildlife, operational safety, climate change and related matters that may expose us to significant costs and liabilities.

 

Our operations involving the storage, treatment, processing, and transportation of liquid hydrocarbons, including crude oil, NGL and refined products, as well as our operations involving the storage of natural gas, are subject to stringent federal, state, and local laws and regulations governing the discharge of materials into the environment. Our operations are also subject to laws and regulations relating to protection of the environment and wildlife, operational safety, climate change and related matters. Compliance with all of these laws and regulations increases our overall cost of doing business, including our capital costs to construct, maintain and upgrade equipment and facilities. For example, the adoption of legislation or regulatory programs to reduce emissions of greenhouse gases, including cap and trade programs, could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. Failure to comply with these laws and regulations may result in the assessment of administrative, civil, and criminal penalties, the imposition of investigatory and remedial liabilities, the issuance of injunctions that may subject us to additional operational requirements and constraints, or claims of damages to property or persons resulting from our operations. The laws and regulations applicable to our operations are subject to change and interpretation by the relevant governmental agency, including the possibility that exemptions we currently qualify for may be modified or changed in ways that require us to incur significant additional compliance costs. Any such change or interpretation adverse to us could have a material adverse effect on our operations, revenues, expenses and profitability.

 

We have a history of incremental additions to the miles of pipelines we own. We have also increased our terminal and storage capacity and operate several facilities on or near navigable waters and domestic water supplies. Although we have implemented programs intended to maintain the integrity of our assets (discussed below), as we acquire additional assets we historically have observed an increase in the number of releases of liquid hydrocarbons into the environment. These releases expose us to potentially substantial expense, including clean-up and remediation costs, fines and penalties, and third party claims for personal injury or property damage related to past or future releases. Some of these expenses could increase by amounts disproportionately higher than the relative increase in pipeline mileage and the increase in revenues associated therewith. Our refined products pipeline and terminal assets are also subject to significant compliance costs and liabilities. In addition, because of their increased volatility and tendency to migrate farther and faster than crude oil, releases of refined products into the environment can have a more significant impact than crude oil and require significantly higher expenditures to respond and remediate. The incurrence of such expenses not covered by insurance, indemnity or reserves could materially adversely affect our results of operations.

 

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We currently devote substantial resources to comply with DOT-mandated pipeline integrity rules. The 2006 Pipeline Safety Act requires the DOT to issue regulations for certain pipelines that were not previously subject to regulation. The DOT regulations include requirements for the establishment of pipeline integrity management programs and for protection of “high consequence areas” where a pipeline leak or rupture could produce significant adverse consequences. We have also developed and implemented certain pipeline integrity measures that go beyond regulatory mandate, some of which are now incorporated into the 2010 Consent Decrees. See Items 1 and 2. “Business and Properties—Regulation.”

 

The acquisitions we have completed over the last several years have included pipeline assets with varying ages and maintenance and operational histories. Accordingly, for 2013 and beyond, we will continue to focus on pipeline integrity management as a primary operational emphasis. In that regard, we have implemented programs intended to maintain the integrity of our assets, with a focus on risk reduction through testing, enhanced corrosion control, leak detection, and damage prevention. We have an internal review process pursuant to which we examine various aspects of our pipeline and gathering systems that are not subject to the DOT pipeline integrity management mandate. The purpose of this process is to review the surrounding environment, condition and operating history of these pipeline and gathering assets to determine if such assets warrant additional investment or replacement. Accordingly, in addition to potential cost increases related to unanticipated regulatory changes or injunctive remedies resulting from regulatory agency enforcement actions, we may elect (as a result of our own internal initiatives) to spend substantial sums to ensure the integrity of and upgrade our pipeline systems to maintain environmental compliance and, in some cases, we may take pipelines out of service if we believe the cost of upgrades will exceed the value of the pipelines. We cannot provide any assurance as to the ultimate amount or timing of future pipeline integrity expenditures but any such expenditures could be significant. See Item 3. “Legal Proceedings—Environmental.”

 

Our profitability depends on the volume of crude oil, refined product, natural gas and NGL shipped, processed, purchased, stored, fractionated and/or gathered at or through the use of our facilities, which can be negatively impacted by a variety of factors outside of our control.

 

Our profitability could be materially impacted by a decline in the volume of crude oil, natural gas, refined product and NGL transported, gathered, stored or processed at our facilities. A material decrease in crude oil or natural gas production or crude oil refining, as a result of depressed commodity prices, natural decline rates attributable to oil and natural reservoirs, a decrease in exploration and development activities, supply disruptions, economic conditions or otherwise, could result in a decline in the volume of crude oil, natural gas, refined product or NGL handled by our facilities and other energy logistics assets.

 

For example, a portion of our transportation segment profit is derived from pipeline transportation tariffs associated with the Santa Ynez and Point Arguello fields located offshore California and the onshore fields in the San Joaquin Valley. We expect that there will continue to be natural production declines from each of these fields as the underlying reservoirs are depleted. In addition, any significant production disruption from OCS fields and the San Joaquin Valley due to production problems, transportation problems, earthquakes or other reasons could have a material adverse effect on our business.

 

In addition, catastrophic accidents, such as the explosion and sinking of the Deepwater Horizon drilling rig in the Gulf of Mexico and the resulting oil spill, could lead to increased governmental regulation of our industry’s operations in a number of areas, including health and safety, environmental, and licensing, any of which could restrict the supply of crude oil available for transportation and have a negative impact on our profitability.

 

Also, third-party shippers generally do not have long-term contractual commitments to ship crude oil on our pipelines. A decision by a shipper to substantially reduce or cease to ship volumes of crude oil on our pipelines could cause a significant decline in our revenues.

 

To maintain the volumes of crude oil we purchase in connection with our operations, we must continue to contract for new supplies of crude oil to offset volumes lost because of natural declines in crude oil production from depleting wells or volumes lost to competitors. Generally, because producers experience inconveniences in switching crude oil purchasers, such as delays in receipt of proceeds while awaiting the preparation of new division orders, producers typically do not change purchasers on the basis of minor variations in price. Thus, we may experience difficulty acquiring crude oil at the wellhead in areas where relationships already exist between producers and other gatherers and purchasers of crude oil.

 

Fluctuations in demand, which can be caused by a variety of factors outside of our control, can negatively affect our operating results.

 

Demand for crude oil and other hydrocarbon products we handle is dependent upon a variety of factors, including price, the impact of future economic conditions, fuel conservation measures, alternative fuel requirements, governmental regulation, including climate change regulations, and technological advances in fuel economy and energy generation devices. For example, the adoption of legislation or regulatory programs to reduce emissions of greenhouse gases could increase the cost of consuming crude oil and

 

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other hydrocarbon products, thereby causing a reduction in the demand for such products. Demand also depends on the ability and willingness of shippers having access to our transportation assets to satisfy their demand by deliveries through those assets.

 

Fluctuations in demand for crude oil, such as those caused by refinery downtime or shutdowns, can have a negative effect on our operating results. Specifically, reduced demand in an area serviced by our transportation systems will negatively affect the throughput on such systems. Although the negative impact may be mitigated or overcome by our ability to capture differentials created by demand fluctuations, this ability is dependent on location and grade of crude oil, and thus is unpredictable.

 

Fluctuations in demand for NGL products, whether because of general or industry specific economic conditions, new government regulations, global competition, reduced demand by consumers for products made with NGL products, increased competition from petroleum-based feedstocks due to pricing differences, mild winter weather for some NGL products, particularly propane, or other reasons, could result in a decline in the volume of NGL products we handle or a reduction of the fees we charge for our services. Also, increased supply of NGL products could reduce the value of NGL we handle and reduce the margins realized by us. Specifically, our NGL products and their demand are affected as follows:

 

Ethane.  Ethane is typically supplied as purity ethane and as part of an ethane-propane mix. Ethane is primarily used in the petrochemical industry as feedstock for ethylene, one of the basic building blocks for a wide range of plastics and other chemical products. Although ethane is typically extracted as part of the mixed NGL stream at gas processing plants, if natural gas prices increase significantly in relation to NGL product prices or if the demand for ethylene falls, it may be more profitable for natural gas processors to leave the ethane in the natural gas stream thereby reducing the volume of NGL delivered for fractionation and marketing.

 

Propane.  Propane is used as a petrochemical feedstock in the production of ethylene and propylene, as a heating, engine and industrial fuel, and in agricultural applications such as crop drying. Changes in demand for ethylene and propylene could also adversely affect demand for propane. The demand for propane as a heating fuel is significantly affected by weather conditions. The volume of propane sold is at its highest during the six-month peak heating season of October through March. Demand for propane may be reduced during periods of warmer-than-normal weather.

 

Normal Butane.  Normal butane is used in the production of isobutane, as a refined product blending component, as a fuel gas, either alone or in a mixture with propane, and in the production of ethylene and propylene. Changes in the composition of refined products resulting from governmental regulation, changes in feedstocks, products and economics, demand for heating fuel and for ethylene and propylene could adversely affect demand for normal butane.

 

Iso-butane.  Iso-butane is predominantly used in refineries to produce alkylates to enhance octane levels. Accordingly, any action that reduces demand for motor gasoline or demand for isobutane to produce alkylates for octane enhancement might reduce demand for isobutane.

 

Natural Gasoline.  Natural gasoline is used as a blending component for certain refined products and as a feedstock used in the production of ethylene and propylene. Changes in the mandated composition of motor gasoline resulting from governmental regulation and in demand for ethylene and propylene could adversely affect demand for natural gasoline.

 

NGL and products produced from NGL also compete with products from global markets. Any reduced demand or increased supply for ethane, propane, normal butane, iso-butane or natural gasoline in the markets we access for any of the reasons stated above could adversely affect demand for the services we provide as well as NGL prices, which could negatively impact our operating results.

 

Our assets are subject to federal, state and provincial regulation. Rate regulation or a successful challenge to the rates we charge on our U.S. and Canadian pipeline systems may reduce the amount of cash we generate.

 

Our U.S. interstate common carrier liquids pipelines, which include both crude oil and refined products pipelines, are subject to regulation by the FERC under the ICA. The ICA requires that tariff rates for liquids pipelines be just and reasonable and non-discriminatory. We are also subject to the Pipeline Safety Regulations of the DOT. Our intrastate pipeline transportation activities are subject to various state laws and regulations as well as orders of regulatory bodies.

 

For our U.S. interstate common carrier liquids pipelines subject to FERC regulation under the ICA, shippers may protest our pipeline tariff filings, file complaints against our existing rates, or the FERC can investigate on its own initiative. Under certain circumstances, the FERC could limit our ability to set rates based on our costs, or could order us to reduce our rates and could require the payment of reparations to complaining shippers for up to two years prior to the complaint. Natural gas storage facilities are subject to regulation by the FERC and certain state agencies.

 

Our Canadian pipelines are subject to regulation by the NEB and by provincial authorities. Under the National Energy Board Act, the NEB could investigate the tariff rates or the terms and conditions of service relating to a jurisdictional pipeline on its own initiative upon the filing of a toll or tariff application, or upon the filing of a written complaint. If it found the rates or terms of service relating to such pipeline to be unjust or unreasonable or unjustly discriminatory, the NEB could require us to change our rates, provide access to other shippers, or change our terms of service. A provincial authority could, on the application of a shipper or other

 

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interested party, investigate the tariff rates or our terms and conditions of service relating to our provincially regulated proprietary pipelines. If it found our rates or terms of service to be contrary to statutory requirements, it could impose conditions it considers appropriate. A provincial authority could declare a pipeline to be a common carrier pipeline, and require us to change our rates, provide access to other shippers, or otherwise alter our terms of service. Any reduction in our tariff rates would result in lower revenue and cash flows.

 

Some of our operations cross the U.S./Canada border and are subject to cross-border regulation.

 

Our cross border activities subject us to regulatory matters, including import and export licenses, tariffs, Canadian and U.S. customs and tax issues and toxic substance certifications. Such regulations include the Short Supply Controls of the Export Administration Act, the North American Free Trade Agreement and the Toxic Substances Control Act. Violations of these licensing, tariff and tax reporting requirements could result in the imposition of significant administrative, civil and criminal penalties.

 

Our sales of oil, natural gas, NGL and other energy commodities, and related transportation and hedging activities, expose us to potential regulatory risks.

 

The Federal Trade Commission, the FERC and the Commodity Futures Trading Commission hold statutory authority to monitor certain segments of the physical and futures energy commodities markets. These agencies have imposed broad regulations prohibiting fraud and manipulation of such markets. With regard to our physical sales of oil, natural gas, NGL or other energy commodities, and any related transportation and/or hedging activities that we undertake, we are required to observe the market-related regulations enforced by these agencies, which hold substantial enforcement authority.  Our sales may also be subject to certain reporting and other requirements. Additionally, to the extent that we enter into transportation contracts with natural gas pipelines that are subject to FERC regulation, we are subject to FERC requirements related to the use of such capacity. Any failure on our part to comply with the regulations and policies of the FERC, the Federal Trade Commission or the Commodity Futures Trading Commission could result in the imposition of civil and criminal penalties. Failure to comply with such regulations, as interpreted and enforced, could have a material adverse effect on our business, results of operations, financial condition and our ability to make cash distributions to our unitholders.

 

The adoption and implementation of new statutory and regulatory requirements for derivative transactions could have an adverse impact on our ability to hedge risks associated with our business and increase the working capital requirements to conduct these activities.

 

The Dodd Frank Wall Street Reform and Consumer Protection Act enacted in 2010 (the “Dodd Frank Act”) provides for new statutory and regulatory requirements for swaps and other financial derivative transactions, including oil and gas hedging transactions. The Dodd Frank Act requires the CFTC, federal regulators of banks and other financial institutions, or the prudential regulators, and the SEC to promulgate rules implementing the new law.

 

In its rulemaking under the Dodd Frank Act the CFTC has issued final regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. However, the position limits rule was vacated by the United States District Court for the District of Colombia in September 2012 and the CFTC has stated that it will appeal the District Court’s decision. The CFTC also has finalized other regulations, including critical rulemakings on the definition of “swap”, “security-based swap”, “swap dealer” and “major swap participant”.  The CFTC also has issued rules that will require certain derivatives transactions to comply with clearing and trade-execution requirements (or take steps to qualify for an exemption to such requirements).   The CFTC has not yet released final rules on margin or collateral requirements, and it is possible that any new rules will increase the amount of cash or collateral required to support exchange and over-the-counter derivative transactions.  Other regulations also remain to be finalized, and the CFTC recently has delayed the compliance dates for various regulations already finalized.   The Dodd Frank Act also may require the counterparties to our derivative instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty.  As a result it is not possible at this time to predict with certainty the full effects of the Dodd Frank Act and CFTC rules on us and the timing of such effects.

 

The majority of our financial derivative transactions used for hedging purposes are currently executed and cleared over exchanges that already require the posting of margins or letters of credit based on initial and variation margin requirements. Depending on the rules and definitions adopted by the CFTC, we might in the future be required to provide additional cash margin or new cash collateral for our commodities hedging transactions whether cleared over an exchange or over-the- counter. Furthermore, it is possible that letters of credit issued by banks on our behalf will no longer be considered an acceptable form of margin support which would increase overall cash margin requirements.

 

Posting of additional cash margin or collateral could affect our liquidity (defined as unrestricted cash on hand plus available credit under our revolving credit facility) and reduce our ability to use cash for capital expenditures or other partnership purposes. A requirement to post additional cash margin or collateral could therefore reduce our ability to execute hedges necessary to reduce commodity price exposures thus protecting cash flows. We are at risk for reduced liquidity unless and until the CFTC adopts rules and definitions that relieve companies such as ourselves from requirements to post additional cash margins or collateral for our exchange or over-the-counter derivative hedging activities. Even if we ourselves are not required to post additional cash margin or collateral for our derivative contracts, the banks and other derivatives dealers who are our contractual counterparties will be required to comply with other new requirements under the Dodd Frank Act and related rules, and the costs of their compliance will likely be passed on to customers such as ourselves, thus decreasing the benefits to us of hedging transactions and reducing our profitability. In addition, implementation of the Dodd Frank Act and related rules and regulations could reduce the overall liquidity and depth of the markets for financial and other derivatives we utilize in connection with our business, which could expose us to additional risks or limit the opportunities we are able to capture by limiting the extent to which we are able to execute our hedging strategies.

 

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Legislation and regulatory initiatives relating to hydraulic fracturing could reduce domestic production of crude oil and natural gas.

 

Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from unconventional geological formations. Recent advances in hydraulic fracturing techniques have resulted in significant increases in crude oil and natural gas production in many basins in the United States and Canada. The process involves the injection of water, sand and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production, and it is typically regulated by state and provincial oil and gas commissions.  Hydraulic fracturing has been subject to increased scrutiny due to public concerns that it could result in contamination of drinking water supplies, and there have been a variety of legislative and regulatory proposals to prohibit, restrict, or more closely regulate various forms of hydraulic fracturing.  Any legislation or regulatory initiatives that curtail hydraulic fracturing could reduce the production of crude oil and natural gas in the United States or Canada, and could thereby reduce demand for our transportation, terminalling and storage services as well as our supply and logistics services.

 

We may not be able to compete effectively in our transportation, facilities and supply and logistics activities, and our business is subject to the risk of a capacity overbuild of midstream energy infrastructure in the areas where we operate.

 

We face competition in all aspects of our business and can give no assurances that we will be able to compete effectively against our competitors.  In general, competition comes from a wide variety of players in a wide variety of contexts, including new entrants and existing players and in connection with day-to-day business, organic growth projects, acquisitions and joint venture activities.  Some of our competitors have capital resources many times greater than ours and control greater supplies of crude oil, natural gas or NGL.

 

A significant driver of competition in some of the markets where we operate (including, for example, the Eagle Ford, Permian Basin, and Rockies\Bakken areas) is the rapid development of new midstream energy infrastructure capacity driven by the combination of (i) significant increases in oil and gas production and development in the applicable production areas, both actual and anticipated, (ii) low barriers to entry and (iii) generally widespread access to relatively low cost capital.  While this environment presents opportunities for us, we are also exposed to the risk that these areas become overbuilt, resulting in an excess of midstream energy infrastructure capacity.  Most midstream projects require several years of “lead time” to develop and companies like us that develop such projects are exposed (to varying degrees depending on the contractual arrangements that underpin specific projects) to the risk that expectations for oil and gas development in the particular area may not be realized or that too much capacity is developed relative to the demand for services that ultimately materializes.  In addition, as an established player in some markets, we also face competition from aggressive new entrants to the market who are willing to provide services at a discount in order to establish relationships and gain a foothold in the market.  If we experience a significant capacity overbuild in one or more of the areas where we operate, it could have a significant adverse impact on our financial position, cash flows and ability to pay or increase distributions to our unitholders.

 

With respect to our crude oil activities, our competitors include other crude oil pipelines, the major integrated oil companies, their marketing affiliates, refiners, industrial companies, independent gatherers, investment banks, brokers and marketers of widely varying sizes, financial resources and experience. We compete against these companies on the basis of many factors, including geographic proximity to production areas, market access, rates, terms of service, connection costs and other factors.

 

With respect to our natural gas storage operations, the principal elements of competition are rates, terms of service, supply and market access and flexibility of service. Our natural gas storage facilities compete with several other storage providers, including regional storage facilities and utilities. Certain major pipeline companies and independent storage providers have existing storage facilities connected to their systems that compete with some of our facilities.

 

With regard to our NGL operations, we compete with large oil, natural gas and natural gas liquids companies that may, relative to us, have greater financial resources and access to supplies of natural gas and NGL. The principal elements of competition are rates, processing fees (e.g., extraction premiums) paid to the owners or aggregators of natural gas to be processed, geographic proximity to the natural gas or NGL mix, available processing and fractionation capacity, transportation alternatives and their associated costs, and access to end user markets.

 

We may in the future encounter increased costs related to, and lack of availability of, insurance.

 

Over the last several years, as the scale and scope of our business activities has expanded, the breadth and depth of available insurance markets has contracted. As a result of these factors and other market conditions, premiums and deductibles for certain insurance policies has increased substantially. Accordingly, we can give no assurance that we will be able to maintain adequate insurance in the future at rates or on other terms we consider commercially reasonable. In addition, although we believe that we currently maintain adequate insurance coverage, insurance will not cover many types of interruptions or events that might occur and will not cover all risks associated with our operations. In addition, the proceeds of any such insurance may not be paid in a timely manner and may be insufficient if such an event were to occur. The occurrence of a significant event, the

 

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consequences of which are either not covered by insurance or not fully insured, or a significant delay in the payment of a major insurance claim, could materially and adversely affect our financial position, results of operations and cash flows.

 

The terms of our indebtedness may limit our ability to borrow additional funds or capitalize on business opportunities. In addition, our future debt level may limit our future financial and operating flexibility.

 

As of December 31, 2012, our consolidated debt outstanding was approximately $7.4 billion, consisting of approximately $6.3 billion principal amount of long-term debt (including senior notes) and approximately $1.1 billion of short-term borrowings (including current maturities of senior notes). As of December 31, 2012, we had approximately $2.4 billion of available borrowing capacity under our senior unsecured revolving credit facility, our senior secured hedged inventory facility and PNG’s credit agreement.

 

The amount of our current or future indebtedness could have significant effects on our operations, including, among other things:

 

·                  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.

 

Our credit agreements prohibit distributions on, or purchases or redemptions of, units if any default or event of default is continuing. In addition, the agreements contain various covenants limiting our ability to, among other things, incur indebtedness if certain financial ratios are not maintained, grant liens, engage in transactions with affiliates, enter into sale-leaseback transactions, and sell substantially all of our assets or enter into a merger or consolidation. Our credit facility treats a change of control as an event of default and also requires us to maintain a certain debt coverage ratio. Our senior notes do not restrict distributions to unitholders, but a default under our credit agreements will be treated as a default under the senior notes. Please read Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Credit Facilities and Indentures.”

 

Our ability to access capital markets to raise capital on favorable terms will be affected by our debt level, our operating and financial performance, the amount of our current maturities and debt maturing in the next several years, and by prevailing market conditions. Moreover, if the rating agencies were to downgrade our credit ratings, then we could experience an increase in our borrowing costs, face difficulty accessing capital markets or incurring additional indebtedness, be unable to receive open credit from our suppliers and trade counterparties, be unable to benefit from swings in market prices and shifts in market structure during periods of volatility in the crude oil market or suffer a reduction in the market price of our common units. If we are unable to access the capital markets on favorable terms at the time a debt obligation becomes due in the future, we might be forced to refinance some of our debt obligations through bank credit, as opposed to long-term public debt securities or equity securities, or sell assets. The price and terms upon which we might receive such extensions or additional bank credit, if at all, could be more onerous than those contained in existing debt agreements. Any such arrangements could, in turn, increase the risk that our leverage may adversely affect our future financial and operating flexibility and thereby impact our ability to pay cash distributions at expected rates.

 

Increases in interest rates could adversely affect our business and the trading price of our units.

 

As of December 31, 2012, we had approximately $7.4 billion of consolidated debt, of which approximately $6.4 billion was at fixed interest rates and approximately $1.0 billion was at variable interest rates (which excludes $100 million of interest rate derivatives that swap floating-rate debt for fixed). We are exposed to market risk due to the floating interest rates on our credit facilities. Our results of operations, cash flows and financial position could be adversely affected by significant increases in interest rates above current levels. Additionally, increases in interest rates could adversely affect our supply and logistics segment results by increasing interest costs associated with the storage of hedged crude oil and NGL inventory. Further, the trading price of our common units may be sensitive to changes in interest rates and any rise in interest rates could adversely impact such trading price.

 

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Changes in currency exchange rates could adversely affect our operating results.

 

Because we are a U.S. dollar reporting company and also conduct operations in Canada, we are exposed to currency fluctuations and exchange rate risks that may adversely affect the U.S. dollar value of our earnings, cash flow and partners’ capital under applicable accounting rules.

 

An impairment of goodwill or intangibles could reduce our earnings.

 

At December 31, 2012, we had approximately $2.5 billion of goodwill and approximately $473 million of intangibles. Goodwill is recorded when the purchase price of a business exceeds the fair market value of the acquired tangible and separately measurable intangible net assets. U.S. generally accepted accounting principles, or GAAP, requires us to test goodwill for impairment on an annual basis or when events or circumstances occur indicating that goodwill might be impaired. GAAP requires that we amortize finite-lived intangibles over their estimated useful lives and test all of our intangibles for impairment when events or circumstances indicate the carrying value may not be recoverable. If we were to determine that any of our goodwill or intangibles were impaired, we would be required to take an immediate charge to earnings with a corresponding reduction of partners’ equity and increase in balance sheet leverage as measured by debt to total capitalization.

 

Our natural gas storage facilities may not be able to deliver as anticipated, which could prevent us from meeting our contractual obligations and cause us to incur significant costs.

 

Although we believe that our operating gas storage facilities have been designed to meet our contractual obligations with respect to wheeling, injection, withdrawal and gas specifications, if our facilities do not perform as designed and we fail to wheel, inject or withdraw natural gas at contracted rates, or cannot deliver natural gas consistent with contractual quality specifications, we could incur significant costs to satisfy our contractual obligations.

 

Marine transportation of crude oil has inherent operating risks.

 

Our supply and logistics operations include purchasing crude oil that is carried on third-party tankers or barges. Such waterborne cargos are at risk of being damaged or lost because of events such as marine disaster, inclement weather, mechanical failures, grounding or collision, fire, explosion, environmental accidents, piracy, terrorism and political instability. Such occurrences could result in death or injury to persons, loss of property or environmental damage, delays in the delivery of cargo, loss of revenues from or termination of charter contracts, governmental fines, penalties or restrictions on conducting business, higher insurance rates and damage to our reputation and customer relationships generally. Although certain of these risks may be covered under our insurance program, any of these circumstances or events could increase our costs or lower our revenues.

 

Maritime claimants could arrest the vessels carrying our cargos.

 

Crew members, suppliers of goods and services to a vessel, other shippers of cargo and other parties may be entitled to a maritime lien against that vessel for unsatisfied debts, claims or damages. In many jurisdictions, a maritime lienholder may enforce its lien by arresting a vessel through foreclosure proceedings. The arrest or attachment of a vessel carrying a cargo of our oil could substantially delay our shipment.

 

In addition, in some jurisdictions, under the “sister ship” theory of liability, a claimant may arrest both the vessel that is subject to the claimant’s maritime lien and any “associated” vessel, which is any vessel owned or controlled by the same owner. Claimants could try to assert “sister ship” liability against one vessel carrying our cargo for claims relating to a vessel with which we have no relation.

 

We are dependent on use of third-party assets for certain of our operations.

 

Certain of our business activities require the use of third-party assets over which we may have little or no control. For example, a portion of our storage and distribution business conducted in the Los Angeles basin (acquired in connection with the Pacific merger) receives waterborne crude oil through dock facilities operated by a third party in the Port of Long Beach. If at any time our access to this dock was denied, and if access to an alternative dock could not be arranged, the volume of crude oil that we presently receive from our customers in the Los Angeles basin may be reduced, which could result in a reduction of facilities segment revenue and cash flow.

 

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Non-utilization of certain assets, such as our leased rail cars, could significantly reduce our profitability due fixed costs incurred to obtain the right to use such assets.

 

From time to time in connection with our business, we may lease or otherwise secure the right to use certain third party assets (such as rail cars, trucks, barges, pipeline capacity, storage capacity and other similar assets) with the expectation that the revenues we generate through the use of such assets will be greater than the fixed costs we incur pursuant to the applicable leases or other arrangements.  However, when such assets are not utilized or are under-utilized, our profitability is negatively impacted because the revenues we earn are either non-existent or reduced (in the event of under-utilization), but we remain obligated to continue paying any applicable fixed charges, in addition to incurring any other costs attributable to the non-utilization of such assets.   For example, in connection with our rail operations, we lease all of our rail cars, typically pursuant to five year leases that obligate us to pay the applicable lease rate without regard to utilization.   If business conditions are such that a portion of our rail fleet is not utilized for any period of time due to reduced demand for the services they provide, we will still be obligated to pay the applicable fixed lease rate for such rail cars.  In addition, during the period of time that we are not utilizing such rail cars, we will incur incremental costs associated with the cost of storing such rail cars and will continue to incur costs for maintenance and upkeep.  As of December 31, 2012, we leased 5,830 rail cars and our annualized lease costs for the year ended December 31, 2012 were over $45 million and are estimated to be over $65 million for the year ended December 31, 2013. Non-utilization of our leased rail cars and other similar assets in connection with our business could have a significant negative impact on our profitability and cash flows.

 

Risks Inherent in an Investment in Plains All American Pipeline, L.P.

 

Cost reimbursements due to our general partner may be substantial and will reduce our cash available for distribution to unitholders.

 

Prior to making any distribution on our common units, we will reimburse our general partner and its affiliates, including officers and directors of the general partner, for all expenses incurred on our behalf (other than expenses related to the Class B units of Plains AAP, L.P.). The reimbursement of expenses and the payment of fees could adversely affect our ability to make distributions. The general partner has sole discretion to determine the amount of these expenses. In addition, our general partner and its affiliates may provide us services for which we will be charged reasonable fees as determined by the general partner.

 

Cash distributions are not guaranteed and may fluctuate with our performance and the establishment of financial reserves.

 

Because distributions on our common units are dependent on the amount of cash we generate, distributions may fluctuate based on our performance. The actual amount of cash that is available to be distributed each quarter will depend on numerous factors, some of which are beyond our control and the control of the general partner. Cash distributions are dependent primarily on cash flow, including cash flow from financial reserves and working capital borrowings, and not solely on profitability, which is affected by non-cash items. Therefore, cash distributions might be made during periods when we record losses and might not be made during periods when we record profits.

 

Unitholders may not be able to remove our general partner even if they wish to do so.

 

Our general partner manages and operates the Partnership. Unlike the holders of common stock in a corporation, unitholders will have only limited voting rights on matters affecting our business. Unitholders have no right to elect the general partner or the directors of the general partner on an annual or any other basis.

 

Furthermore, if unitholders are dissatisfied with the performance of our general partner, they currently have little practical ability to remove our general partner or otherwise change its management. Our general partner may not be removed except upon the vote of the holders of at least 662/3% of our outstanding units (including units held by our general partner or its affiliates). Because the owners of our general partner, along with directors and executive officers and their affiliates, own a significant percentage of our outstanding common units, the removal of our general partner would be difficult without the consent of both our general partner and its affiliates.

 

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In addition, the following provisions of our partnership agreement may discourage a person or group from attempting to remove our general partner or otherwise change our management:

 

·                  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; 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.

 

As a result of these provisions, the price at which our common units will trade may be lower because of the absence or reduction of a takeover premium in the trading price.

 

We may issue additional common units without unitholder approval, which would dilute a unitholder’s existing ownership interests.

 

Our general partner may cause us to issue an unlimited number of common units without unitholder approval (subject to applicable NYSE rules). We may also issue at any time an unlimited number of equity securities ranking junior or senior to the common units without unitholder approval (subject to applicable NYSE rules). The issuance of additional common units or other equity securities of equal or senior rank may have the following effects:

 

·      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.

 

Our general partner has a limited call right that may require unitholders to sell their units at an undesirable time or price.

 

If at any time our general partner and its affiliates own 80% or more of the common units, the general partner will have the right, but not the obligation, which it may assign to any of its affiliates, to acquire all, but not less than all, of the remaining common units held by unaffiliated persons at a price generally equal to the then current market price of the common units. As a result, unitholders may be required to sell their common units at a time when they may not desire to sell them and/or at a price that is less than the price they would like to receive. They may also incur a tax liability upon a sale of their common units.

 

Unitholders may not have limited liability if a court finds that unitholder actions constitute control of our business.

 

Under Delaware law, a unitholder could be held liable for our obligations to the same extent as a general partner if a court determined that the right of unitholders to remove our general partner or to take other action under our partnership agreement constituted participation in the “control” of our business.

 

Our general partner generally has unlimited liability for our obligations, such as our debts and environmental liabilities, except for those contractual obligations that are expressly made without recourse to our general partner. Our partnership agreement allows the general partner to incur obligations on our behalf that are expressly non-recourse to the general partner. The general partner has entered into such limited recourse obligations in most instances involving payment liability and intends to do so in the future.

 

In addition, Section 17-607 of the Delaware Revised Uniform Limited Partnership Act provides that under some circumstances, a unitholder may be liable to us for the amount of a distribution for a period of three years from the date of the distribution.

 

Conflicts of interest could arise among our general partner and us or the unitholders.

 

These conflicts may include the following:

 

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·                  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.

 

The control of our general partner may be transferred to a third party without unitholder consent. A change of control may result in defaults under certain of our debt instruments and the triggering of payment obligations under compensation arrangements.

 

Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of our unitholders. Furthermore, there is no restriction in our partnership agreement on the ability of the general partner of our general partner to transfer its general partnership interest in our general partner to a third party. Any new owner of our general partner would be able to replace the board of directors and officers with its own choices and to control their decisions and actions.

 

In addition, a change of control would constitute an event of default under our revolving credit agreements. During the continuance of an event of default under our revolving credit agreements, the administrative agent may terminate any outstanding commitments of the lenders to extend credit to us under our revolving credit facility and/or declare all amounts payable by us under our revolving credit facility immediately due and payable. A change of control also may trigger payment obligations under various compensation arrangements with our officers.

 

Risks Related to an Investment in Our Debt Securities

 

The right to receive payments on our outstanding debt securities is unsecured and will be effectively subordinated to our existing and future secured indebtedness and will be structurally subordinated as to any existing and future indebtedness and other obligations of our subsidiaries, other than subsidiaries that may guarantee our debt securities in the future.

 

Our debt securities are effectively subordinated to claims of our secured creditors and to any existing and future indebtedness and other obligations of our subsidiaries, including trade payables, other than subsidiaries that may guarantee our debt securities in the future. In the event of the insolvency, bankruptcy, liquidation, reorganization, dissolution or winding up of the business of a subsidiary, other than a subsidiary that may guarantee our debt securities in the future, creditors of that subsidiary would generally have the right to be paid in full before any distribution is made to us or the holders of our debt securities.

 

Our leverage may limit our ability to borrow additional funds, comply with the terms of our indebtedness or capitalize on business opportunities.

 

Our leverage is significant in relation to our partners’ capital. At December 31, 2012, our total outstanding long-term debt was approximately $6.3 billion, and our total outstanding short-term debt was approximately $1.1 billion (including current maturities of senior notes). We will be prohibited from making cash distributions during an event of default under any of our indebtedness. Various limitations in our credit facilities and other debt instruments may reduce our ability to incur additional debt, to engage in some transactions and to capitalize on business opportunities. Any subsequent refinancing of our current indebtedness or any new indebtedness could have similar or greater restrictions.

 

Our leverage could have important consequences to investors in our debt securities. We will require substantial cash flow to meet our principal and interest obligations with respect to the notes and our other consolidated indebtedness. Our ability to make scheduled payments, to refinance our obligations with respect to our indebtedness or our ability to obtain additional financing in the future will depend on our financial and operating performance, which, in turn, is subject to prevailing economic conditions and to financial, business and other factors. We believe that we will have sufficient cash flow from operations and available borrowings under our bank credit facility to service our indebtedness, although the principal amount of the notes will likely need to be refinanced at maturity in whole or in part. A significant downturn in the hydrocarbon industry or other development adversely affecting our cash

 

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flow could materially impair our ability to service our indebtedness. If our cash flow and capital resources are insufficient to fund our debt service obligations, we may be forced to refinance all or a portion of our debt or sell assets. We can give no assurance that we would be able to refinance our existing indebtedness or sell assets on terms that are commercially reasonable.

 

Our leverage may adversely affect our ability to fund future working capital, capital expenditures and other general partnership requirements, future acquisition, construction or development activities, or to otherwise fully realize the value of our assets and opportunities because of the need to dedicate a substantial portion of our cash flow from operations to payments on our indebtedness or to comply with any restrictive terms of our indebtedness. Our leverage may also make our results of operations more susceptible to adverse economic and industry conditions by limiting our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate and may place us at a competitive disadvantage as compared to our competitors that have less debt.

 

The ability to transfer our debt securities may be limited by the absence of an organized trading market.

 

We do not currently intend to apply for listing of our debt securities on any securities exchange or stock market. The liquidity of any market for our debt securities will depend on the number of holders of those debt securities, the interest of securities dealers in making a market in those debt securities and other factors. Accordingly, we can give no assurance as to the development, continuation or liquidity of any market for the debt securities.

 

We have a holding company structure in which our subsidiaries conduct our operations and own our operating assets.

 

We are a holding company, and our subsidiaries conduct all of our operations and own all of our operating assets. We have no significant assets other than the ownership interests in our subsidiaries. As a result, our ability to make required payments on our debt securities depends on the performance of our subsidiaries and their ability to distribute funds to us. The ability of our subsidiaries to make distributions to us may be restricted by, among other things, credit facilities and applicable state partnership laws and other laws and regulations. Pursuant to our credit facilities, we may be required to establish cash reserves for the future payment of principal and interest on the amounts outstanding under our credit facilities. If we are unable to obtain the funds necessary to pay the principal amount at maturity of our debt securities, or to repurchase our debt securities upon the occurrence of a change of control, we may be required to adopt one or more alternatives, such as a refinancing of our debt securities. We cannot assure you that we would be able to refinance our debt securities.

 

We do not have the same flexibility as other types of organizations to accumulate cash, which may limit cash available to service our debt securities or to repay them at maturity.

 

Unlike a corporation, our partnership agreement requires us to distribute, on a quarterly basis, 100% of our available cash to our unitholders of record and our general partner. Available cash is generally all of our cash receipts adjusted for cash distributions and net changes to reserves. Our general partner will determine the amount and timing of such distributions and has broad discretion to establish and make additions to our reserves or the reserves of our operating partnerships in amounts the general partner determines in its reasonable discretion to be necessary or appropriate:

 

·                  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.

 

Although our payment obligations to our unitholders are subordinate to our payment obligations to debtholders, the value of our units will decrease in direct correlation with decreases in the amount we distribute per unit. Accordingly, if we experience a liquidity problem in the future, we may not be able to issue equity to recapitalize.

 

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Tax Risks to Common Unitholders

 

Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of additional entity-level taxation. If the Internal Revenue Service (“IRS”) were to treat us as a corporation for federal income tax purposes or if we become subject to material amounts of additional entity-level taxation for state or foreign tax purposes, it would reduce the amount of cash available to pay distributions and our debt obligations.

 

The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes. A publicly traded partnership such as us may be treated as a corporation for federal income tax purposes unless it satisfies a “qualifying income” requirement.  Based on our current operations we believe that we are treated as a partnership rather than a corporation for such purposes; however, a change in our business could cause us to be treated as a corporation for federal income tax purposes.  We have not requested, and do not plan to request, a ruling from the IRS on this or any other tax matter affecting us.

 

In addition, a change in current law may cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to additional entity-level taxation. In addition, because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Specifically, beginning in 2008, we became subject to a new entity level tax on the portion of our income that is generated in Texas in the prior year. Imposition of any such additional taxes on us will reduce the cash available for distribution to our unitholders. If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35%, and would likely pay state income taxes at varying rates. Distributions to our unitholders would generally be taxed again as corporate distributions, and no income, gains, losses, deductions or credits would flow through to our unitholders. Because a tax would be imposed upon us as a corporation, the cash available for distributions or to pay our debt obligations would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in cash flow and after-tax returns to our unitholders, likely causing a substantial reduction in the value of our common units.

 

Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal income tax purposes, our target distribution amounts will be adjusted to reflect the impact of that law on us.

 

The tax treatment of publicly traded partnerships or an investment in our units could be subject to potential legislative, judicial, or administrative changes and differing interpretations, possibly on a retroactive basis.

 

The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial changes, or differing interpretations at any time. For example, from time to time, members of Congress propose and consider substantive changes to the existing federal income tax laws that affect publicly traded partnerships. Currently, one such legislative proposal would eliminate the qualifying income exception to the treatment of all publicly traded partnerships as corporations upon which we rely for our treatment as a partnership for U.S. federal income tax purposes. We are unable to predict whether any of these changes or other proposals will be reintroduced or ultimately will be enacted. Any such changes could negatively impact the value of an investment in our common units. Any modification to the U.S. federal income tax laws may be applied retroactively and could make it more difficult or impossible to meet the exception for certain publicly traded partnerships to be treated as partnerships for U.S. federal income tax purposes.

 

The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in our termination as a partnership for federal income tax purposes.

 

We will be considered to have constructively terminated as a partnership for tax purposes if there are sales or exchanges which, in the aggregate, constitute 50% or more of the total interests in our capital and profits within a twelve-month period. For purposes of measuring whether the 50% threshold is reached, multiple sales of the same interest are counted only once. Our termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in our filing two tax returns for one fiscal year and could result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a calendar year, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but it would result in our being treated as a new partnership for tax purposes. If we were treated as a new partnership, we would be required to make new tax elections and could be subject to penalties if we were unable to determine that a termination occurred. The IRS has recently announced a relief procedure whereby if a publicly traded partnership that has technically terminated requests and the IRS grants

 

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special relief, among other things, the partnership may be permitted to provide only a single Schedule K-1 to unitholders for the tax years in which the termination occurs.

 

If the IRS or Canada Revenue Agency (“CRA”) contests the federal income tax positions we take, the market for our common units may be adversely impacted and the cost of any IRS or CRA contest will reduce our cash available for distribution or debt service.

 

The IRS has made no determination as to our status as a partnership for federal income tax purposes or as to any other matter affecting us. The IRS or CRA may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with some or all of the positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. In addition, our costs of any contest with the IRS or CRA will be borne indirectly by our unitholders and our general partner because the costs will reduce our cash available for distribution or debt service.

 

Our unitholders may be required to pay taxes on their share of our income even if they do not receive any cash distributions from us.

 

Because our unitholders will be treated as partners to whom we will allocate taxable income that could be different in amount than the cash we distribute, they will be required to pay any federal income taxes and, in some cases, state and local income taxes on their share of our taxable income even if they receive no cash distributions from us. Unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from that income.

 

Tax gain or loss on the disposition of our common units could be more or less than expected.

 

If our unitholders sell their common units, they will recognize gain or loss equal to the difference between the amount realized and their tax basis in those common units. Because distributions in excess of a unitholder’s allocable share of our net taxable income decrease the unitholder’s tax basis in their common units, the amount of any such prior excess distributions with respect to their units will, in effect, become taxable income to the unitholder if the common units are sold at a price greater than the unitholder’s tax basis in those common units, even if the price the unitholder receives is less than the unitholder’s original cost. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if a unitholder sells units, the unitholder may incur a tax liability in excess of the amount of cash received from the sale.

 

Tax-exempt entities and non-U.S. persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.

 

Investment in common units by tax-exempt entities, such as employee benefit plans and IRAs, and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file U.S. federal tax returns and pay tax on their share of our taxable income. Non-U.S. persons will also potentially have tax filing and payment obligations in additional jurisdictions. Tax-exempt entities and non-U.S. persons should consult their tax advisor before investing in our common units.

 

We treat each purchaser of our common units as having the same tax benefits without regard to the actual units purchased. The IRS may challenge this treatment, which could adversely affect the value of our common units.

 

Because we cannot match transferors and transferees of common units, we have adopted depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our unitholders. It also could affect the timing of these tax benefits or the amount of gain from the sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to our unitholders’ tax returns.

 

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Our unitholders will likely be subject to state, local and non-U.S. taxes and return filing requirements in states and jurisdictions where they do not live as a result of investing in our units.

 

In addition to U.S. federal income taxes, our unitholders will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future, even if our unitholders do not live in any of those jurisdictions. Our unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with those requirements. We currently own property and conduct business in most states in the United States, most of which impose a personal income tax on individuals and an income tax on corporations and other entities. It is our unitholders’ responsibility to file all U.S. federal, state, local and non-U.S. tax returns, as applicable.  As a result of the Canadian restructuring, non-Canadian resident unitholders are not required to file Canadian tax returns with respect to an investment in our units.

 

We have adopted certain valuation methodologies that may result in a shift of income, gain, loss and deduction between our general partner and our unitholders. The IRS may challenge this treatment, which could adversely affect the value of our common units.

 

When we issue additional units or engage in certain other transactions, we determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and the general partner, which may be unfavorable to such unitholders. Moreover, under our current valuation methods, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of income, gain, loss and deduction between the general partner and certain of our unitholders.

 

A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain from our unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.

 

A unitholder whose common units are the subject of a securities loan (e.g., a loan to a “short seller” to cover a short sale of common units) may be considered as having disposed of those common units. If so, he would no longer be treated for tax purposes as a partner with respect to those common units during the period of the loan and may recognize gain or loss from the disposition.

 

Because there are no specific rules governing the federal income tax consequences of loaning a partnership interest, a unitholder whose common units are the subject of a securities loan may be considered as having disposed of the loaned units.  In that case, the unitholder may no longer be treated for tax purposes as a partner with respect to those common units during the period of the loan and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan, any of our income, gain, loss or deduction with respect to those common units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those common units may be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller should modify any applicable brokerage account agreements to prohibit their brokers from borrowing their common units.

 

We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

 

We generally prorate our items of income, gain, loss and deduction between existing unitholders and unitholders who purchase our units based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred.  The use of this proration method may not be permitted under existing Treasury Regulations. Recently, the U.S. Treasury Department issued proposed Treasury Regulations that provide a safe harbor pursuant to which publicly traded partnerships may use a similar monthly simplifying convention to allocate tax items. Nonetheless, the proposed regulations do not specifically authorize the use of the proration method we have adopted.  If the IRS were to challenge our proration method or new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

 

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Item 1B.  Unresolved Staff Comments

 

None.

 

Item 3.  Legal Proceedings

 

General. In the ordinary course of business, we are involved in various legal proceedings. To the extent we are able to assess the likelihood of a negative outcome for these proceedings, our assessments of such likelihood range from remote to probable.  If we determine that a negative outcome is probable and the amount of loss is reasonably estimable, we accrue the estimated amount.  We do not believe that the outcome of these legal proceedings, individually or in the aggregate, will have a materially adverse effect on our financial condition, results of operations or cash flows.  Although we believe that our operations are presently in material compliance with applicable requirements, as we acquire and incorporate additional assets it is possible that the EPA or other governmental entities may seek to impose fines, penalties or performance obligations on us (or on a portion of our operations) as a result of any past noncompliance whether such noncompliance initially developed before or after our acquisition.

 

Pemex Exploración y Producción v. Big Star Gathering Ltd L.L.P. et al. In two cases filed in the Texas Southern District Court in May 2011 and April 2012, Pemex Exploración y Producción (“PEP”) alleges that certain parties stole condensate from pipelines and gathering stations and conspired with U.S. companies (primarily in Texas) to import and market the stolen condensate.  PEP does not allege that Plains was part of any conspiracy, but that it dealt in the condensate only after it had been obtained by others and resold to Plains Marketing, L.P.  PEP seeks actual damages, attorney’s fees, and statutory penalties from Plains Marketing, L.P.  At a hearing held on October 20, 2011, the Court ruled that Texas law (not Mexican law) governs the actions.  In February 2013, the Court granted Plains Marketing, L.P.’s motion to be dismissed from the April 2012 lawsuit and Plains Marketing, L.P. filed a motion for summary judgment in the May 2011 lawsuit.

 

Environmental

 

General

 

Although we believe that our efforts to enhance our leak prevention and detection capabilities have produced positive results, we have experienced (and likely will experience future) releases of hydrocarbon products into the environment from our pipeline and storage operations. These releases can result from unpredictable man-made or natural forces and may reach “navigable waters” or other sensitive environments. Whether current or past, damages and liabilities associated with any such releases from our assets may substantially affect our business.

 

At December 31, 2012, our estimated undiscounted reserve for environmental liabilities, including the reserve related to our Rangeland Pipeline release as discussed further below, totaled approximately $96 million, of which approximately $13 million was classified as short-term and $83 million was classified as long-term. At December 31, 2011, our estimated undiscounted reserve for environmental liabilities totaled approximately $74 million, of which approximately $12 million was classified as short-term and $62 million was classified as long-term. At December 31, 2012 and 2011, we had recorded receivables totaling approximately $42 million and $47 million, respectively, for amounts probable of recovery under insurance and from third parties under indemnification agreements.

 

In some cases, the actual cash expenditures may not occur for three to five years. Our estimates used in these reserves are based on information currently available to us and our assessment of the ultimate outcome. Among the many uncertainties that impact our estimates are the necessary regulatory approvals for, and potential modification of, our remediation plans, the limited amount of data available upon initial assessment of the impact of soil or water contamination, changes in costs associated with environmental remediation services and equipment and the possibility of existing legal claims giving rise to additional claims. Therefore, although we believe that the reserve is adequate, costs incurred may be in excess of the reserve and may potentially have a material adverse effect on our financial condition, results of operations or cash flows.

 

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Rangeland Pipeline Release

 

On June 7, 2012, we experienced a crude oil release on a section of our Rangeland Pipeline located near Sundre, Alberta, Canada.  Approximately 3,000 barrels were released into the Red Deer River and were contained downstream in the Gleniffer Reservoir. The pipeline, while pressurized, was shut in at the time of the incident. Clean-up and remediation activities were conducted in cooperation with the applicable regulatory agencies.  Remediation activities in the reservoir area were completed by June 30, 2012, remediation of the remaining impacted areas was completed by September 30, 2012 and interim closure was received from the applicable regulatory agencies.  Ongoing monitoring will continue into 2013, and a long-term monitoring plan, if required, will be developed and implemented in accordance with regulatory requirements.

 

We estimate that the aggregate total clean-up and remediation costs, before insurance recoveries, will be approximately $51 million. This estimate considers our prior experience in environmental investigation and remediation matters, as well as available data from, and in consultation with, our environmental specialists.  Although actual remediation costs may be more than amounts accrued, we believe we have established adequate reserves for all probable and reasonably estimable costs. We have accrued the total estimated costs to “Field operating costs” on our Consolidated Statement of Operations.

 

As of December 31, 2012, we had a remaining undiscounted gross environmental remediation liability related to this release of approximately $7 million, substantially all of which is presented as a current liability in “Accounts payable and accrued liabilities” on our Consolidated Balance Sheet. We maintain insurance coverage, which is subject to certain exclusions and deductibles, to protect us against such environmental liabilities. This coverage is adequate to cover the total remediation costs, net of our deductible.  As of December 31, 2012, we had a receivable of approximately $36 million for the portion of this liability that we believe is probable of recovery from insurance, net of deductibles. This receivable has been recognized as a current asset in “Trade accounts receivable and other receivables, net” on our Consolidated Balance Sheet with the offset reducing “Field operating costs” on our Consolidated Statement of Operations.

 

Bay Springs Pipeline Release

 

On February 5, 2013, we experienced a crude oil release on a portion of one of our pipelines near Bay Springs, Mississippi. Although the volume of oil released has not been finally determined, we estimate that approximately 125 barrels were released. Most of the released oil was contained within our pipeline right of way, but some of the released oil entered a nearby waterway where it was contained with booms.  The EPA has issued an administrative order requiring us to take various actions in response to the release, including remediation, reporting and other actions, and we may be subjected to a civil penalty.  We estimate that the aggregate clean-up and remediation costs, before insurance recoveries, associated with this release will not exceed $10 million.

 

Insurance

 

A pipeline, terminal or other facility may experience damage as a result of an accident, natural disaster or terrorist activity. These hazards can cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage and suspension of operations. We maintain various types of insurance that we consider adequate to cover our operations and certain assets. The insurance policies are subject to deductibles or self-insured retentions that we consider reasonable. Our insurance does not cover every potential risk associated with operating pipelines, terminals and other facilities, including the potential loss of significant revenues.

 

The occurrence of a significant event not fully insured, indemnified or reserved against, or the failure of a party to meet its indemnification obligations, could materially and adversely affect our operations and financial condition. We believe we are adequately insured for public liability and property damage with respect to our operations. In the future, we may not be able to maintain insurance at levels that we consider adequate for rates we consider reasonable. As a result, we may elect to self-insure or utilize higher deductibles in certain insurance programs. For example, the market for hurricane- or windstorm-related property damage coverage has remained difficult the last few years. The amount of coverage available has been limited, costs have increased substantially and deductibles have increased as well.

 

In 2011, we elected not to renew our hurricane insurance, and, instead, to self-insure this risk. Our assessment of the current availability of coverage and associated rates has led us to the decision to continue to self-insure. This decision does not affect our third-party liability insurance, which still covers hurricane-related liability claims which we have renewed at our historic coverage levels. In addition, although we believe that we have established adequate reserves to the extent such risks are not insured, costs incurred in excess of these reserves may be higher and may potentially have a material adverse effect on our financial conditions, results of operations or cash flows.

 

Item 4. Mine Safety Disclosures

 

Not applicable.

 

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PART II

 

Item 5.  Market for Registrant’s Common Units, Related Unitholder Matters and Issuer Purchases of Equity Securities

 

Our common units are listed and traded on the New York Stock Exchange (“NYSE”) under the symbol “PAA.”  On October 1, 2012, we completed a two-for-one split of our common units, which has been retroactively applied to all unit and per-unit amounts presented in this Form 10-K. As of February 20, 2013, the closing market price for our common units was $53.70 per unit and there were approximately 197,000 record holders and beneficial owners (held in street name). As of February 20, 2013, there were 336,152,761 common units outstanding.

 

The following table sets forth high and low sales prices for our common units and the cash distributions declared per common unit for the periods indicated:

 

 

 

Common Unit

 

 

 

 

 

Price Range

 

Cash

 

 

 

High

 

Low

 

Distributions (1)

 

2012

 

 

 

 

 

 

 

4th Quarter

 

$

47.14

 

$

42.60

 

$

0.5625

 

3rd Quarter

 

$

45.57

 

$

40.18

 

$

0.5425

 

2nd Quarter

 

$

41.23

 

$

37.59

 

$

0.5325

 

1st Quarter

 

$

42.24

 

$

34.74

 

$

0.5225

 

 

 

 

 

 

 

 

 

2011

 

 

 

 

 

 

 

4th Quarter

 

$

36.78

 

$

27.45

 

$

0.5125

 

3rd Quarter

 

$

32.49

 

$

28.21

 

$

0.4975

 

2nd Quarter

 

$

32.85

 

$

28.90

 

$

0.4913

 

1st Quarter

 

$

32.98

 

$

30.11

 

$

0.4850

 

 


(1)                                     Cash distributions associated with 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.

 

Our common units are also used as a form of compensation to our employees. Additional information regarding our equity compensation plans is included in Part III of this report under Item 13. “Certain Relationships and Related Transactions, and Director Independence.”

 

Cash Distribution Policy

 

In accordance with our partnership agreement, we will distribute all of our available cash to our unitholders within 45 days following the end of each quarter in the manner described below. Available cash generally means, for any quarter ending prior to liquidation, all cash on hand at the end of that quarter less the amount of cash reserves that are necessary or appropriate in the reasonable discretion of the general partner to:

 

·                  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.

 

In addition to distributions on its 2% general partner interest, our general partner is entitled to receive incentive distributions if the amount we distribute with respect to any quarter exceeds levels specified in our partnership agreement. Under the quarterly incentive distribution provisions, as amended for the two-for-one unit split, our general partner is entitled, without duplication and except for the agreed upon adjustment discussed below, to 15% of amounts we distribute in excess of $0.2250 per unit, 25% of the amounts we distribute in excess of $0.2475 per unit and 50% of amounts we distribute in excess of $0.3375 per unit.

 

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In order to enhance our distribution coverage ratio and liquidity in connection with a significant acquisition, our general partner has, from time to time, agreed to reduce the amounts due to it as incentive distributions.  In connection with our BP NGL Acquisition, our general partner agreed to reduce the amount of its incentive distributions by $3.75 million per quarter through February 2014 and $2.5 million per quarter thereafter. See Note 3 to our Consolidated Financial Statements for further discussion of the BP NGL Acquisition.

 

During 2012, we paid approximately $271 million to the general partner in incentive distributions, net of incentive distribution reductions of $11.25 million. Additionally, on February 14, 2013, we paid a quarterly distribution of $0.5625 per unit applicable to the fourth quarter of 2012, of which approximately $81 million was paid to the general partner in incentive distributions, net of incentive distribution reductions of $3.75 million. See Item 13. “Certain Relationships and Related Transactions, and Director Independence—Our General Partner.”

 

Under the terms of the agreements governing our debt, we are prohibited from declaring or paying any distribution to unitholders if a default or event of default (as defined in such agreements) exists. No such default has occurred. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Credit Facilities and Indentures.”

 

See Item 12. “Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters” for information regarding securities authorized for issuance under equity compensation plans.

 

Issuer Purchases of Equity Securities

 

We did not repurchase any of our common units during the fourth quarter of 2012, and we do not have any announced or existing plans to repurchase any of our common units other than potential repurchases consistent with past practice in providing units for relatively small vestings of phantom units under our long-term incentive plans (“LTIP”).

 

Item 6.  Selected Financial Data

 

The historical financial information below was derived from our audited consolidated financial statements as of December 31, 2012, 2011, 2010, 2009 and 2008 and for the years then ended. The selected financial data should be read in conjunction with the Consolidated Financial Statements, including the notes thereto, and Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

 

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Year Ended December 31,

 

 

 

2012

 

2011

 

2010

 

2009

 

2008

 

 

 

(in millions, except for per unit data)

 

Statement of operations data:

 

 

 

 

 

 

 

 

 

 

 

Total revenues

 

$

37,797

 

$

34,275

 

$

25,893

 

$

18,520

 

$

30,061

 

Net income

 

$

1,127

 

$

994

 

$

514

 

$

580

 

$

437

 

Net income attributable to Plains

 

$

1,094

 

$

966

 

$

505

 

$

579

 

$

437

 

 

 

 

 

 

 

 

 

 

 

 

 

Per unit data:

 

 

 

 

 

 

 

 

 

 

 

Basic net income per limited partner unit

 

$

2.41

 

$

2.46

 

$

1.21

 

$

1.67

 

$

1.33

 

Diluted net income per limited partner unit

 

$

2.40

 

$

2.44

 

$

1.20

 

$

1.66

 

$

1.32

 

Declared distributions per limited partner unit (1)

 

$

2.11

 

$

1.95

 

$

1.88

 

$

1.81

 

$

1.75

 

 

 

 

 

 

 

 

 

 

 

 

 

Balance sheet data (at end of period):

 

 

 

 

 

 

 

 

 

 

 

Total assets

 

$

19,235

 

$

15,381

 

$

13,703

 

$

12,358

 

$

10,032

 

Long-term debt

 

$

6,320

 

$

4,520

 

$

4,631

 

$

4,142

 

$

3,259

 

Total debt

 

$

7,406

 

$

5,199

 

$

5,957

 

$

5,216

 

$

4,286

 

Partners’ capital

 

$

7,146

 

$

5,974

 

$

4,573

 

$

4,159

 

$

3,552

 

 

 

 

 

 

 

 

 

 

 

 

 

Other data:

 

 

 

 

 

 

 

 

 

 

 

Net cash provided by operating activities

 

$

1,240

 

$

2,365

 

$

259

 

$

365

 

$

857

 

Net cash used in investing activities

 

$

(3,392

)

$

(2,020

)

$

(851

)

$

(686

)

$

(1,339

)

Net cash provided by/(used in) financing activities

 

$

2,151

 

$

(345

)

$

604

 

$

338

 

$

464

 

Capital expenditures:

 

 

 

 

 

 

 

 

 

 

 

Acquisitions

 

$

2,286

 

$

1,404

 

$

407

 

$

393

 

$

735

 

Internal growth projects

 

$

1,185

 

$

531

 

$

355

 

$

379

 

$

528

 

Maintenance

 

$

170

 

$

120

 

$

93