PLAINS ALL AMERICAN PIPELINE LP - Annual Report: 2010 (Form 10-K)

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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, 2010

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 (State or other jurisdiction of incorporation or organization)		76-0582150 (I.R.S. Employer Identification No.)

333 Clay Street, Suite 1600, Houston, Texas (Address of principal executive offices)		77002 (Zip Code)

(713) 646-4100

(Registrant’s telephone number, including area code)

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. o

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 $7.0 billion on June 30, 2010, based on $58.70 per unit, the closing price of the Common Units as reported on the New York Stock Exchange on such date.

As of February 22, 2011, there were 141,199,175 Common Units outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

NONE

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

FORM 10-K—2010 ANNUAL REPORT

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		Page
PART I		3
Items 1 and 2.	Business and Properties	3
Item 1A.	Risk Factors	35
Item 1B.	Unresolved Staff Comments	50
Item 3.	Legal Proceedings	50
Item 4.	(Removed and Reserved)	51
PART II		52
Item 5.	Market for Registrant’s Common Units, Related Unitholder Matters and Issuer Purchases of Equity Securities	52
Item 6.	Selected Financial Data	54
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	56
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	78
Item 8.	Financial Statements and Supplementary Data	80
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	80
Item 9A.	Controls and Procedures	80
Item 9B.	Other Information	80
PART III		81
Item 10.	Directors and Executive Officers of Our General Partner and Corporate Governance	81
Item 11.	Executive Compensation	93
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters	115
Item 13.	Certain Relationships and Related Transactions, and Director Independence	119
Item 14.	Principal Accountant Fees and Services	125
PART IV		126
Item 15.	Exhibits and Financial Statement Schedules	126

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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 these words, however, does not mean that the statements are not forward-looking. These 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 to differ materially from the results anticipated in the forward-looking statements. These factors include, but are not limited to:

· failure to implement or capitalize on planned internal growth projects;

· 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;

· abrupt or severe declines or interruptions in outer continental shelf production located offshore California and transported on our pipeline systems;

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

· the availability of adequate third-party production volumes for transportation and marketing in the areas in which we operate and other factors that could cause declines in volumes shipped on our pipelines by us and third-party shippers, such as declines in production from existing oil and gas reserves or failure to develop additional oil and gas reserves;

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

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

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

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

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

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

· the effects of competition;

· interruptions in service on third-party pipelines;

· increased costs or lack of availability of insurance;

· fluctuations in the debt and equity markets, including the price of our units at the time of vesting under our long-term incentive plans;

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· the currency exchange rate of the Canadian dollar;

· weather interference with business operations or project construction;

· risks related to the development and operation of natural gas storage facilities;

· future developments and circumstances at the time distributions are declared;

· 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, refined products and liquefied petroleum gas and other natural gas related petroleum products.

Other factors described herein, or 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, refined products and liquefied petroleum gas and other natural gas-related petroleum products. We refer to liquefied petroleum gas and other natural gas-related petroleum products collectively as “LPG.” Through our general partner interest and majority equity ownership position in PAA Natural Gas Storage, L.P. (NYSE: PNG), we also engage in the acquisition, development and operation of natural gas storage facilities. Our business activities are conducted through three 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 18 holders and their affiliates. 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.”

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.).

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The chart below depicts the current structure and ownership of Plains All American Pipeline, L.P. and certain subsidiaries as of February 22, 2011.

Partnership Structure

(1) Based on Form 4 filings for executive officers and directors, 13D filings for Richard Kayne and other information believed to be reliable for the remaining investors, this group, or affiliates of such investors, owns approximately 9 million limited partner units, representing approximately 7% 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 holds direct and indirect ownership interests in consolidated operating subsidiaries including, but not limited to, Plains Pipeline, L.P., Plains Marketing, L.P., Plains LPG Services, L.P., Pacific Energy Group LLC and Plains Midstream Canada ULC.

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

Business Strategy

Our principal business strategy is to provide competitive and efficient midstream transportation, terminalling, storage 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, refined products, LPG and natural gas storage in the United States and Canada by combining the strategic location and capabilities of our transportation, terminalling and storage assets with our extensive supply, logistics and distribution expertise.

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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;

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

· utilizing our assets along the Gulf, West and East Coasts along with our terminals and leased assets to optimize our presence in the waterborne importation of foreign crude oil;

· 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;

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

· using our terminalling and storage 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.

We intend to utilize PNG as the primary vehicle through which we will participate in the natural gas storage business. We believe PNG’s natural gas storage assets are also well-positioned to benefit from long-term industry trends and opportunities. PNG’s growth strategies are to develop and implement internal growth projects and to selectively pursue strategic and accretive acquisitions of natural gas storage projects and facilities. Through execution of such growth strategies, we intend to expand the scale and scope of our natural gas storage business. We may also prudently and economically leverage our asset base, knowledge base and skill sets to participate in other energy-related businesses that have characteristics and opportunities similar to, or that otherwise complement, our existing activities.

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 our investment grade credit rating. We have targeted a general credit profile with the following attributes:

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

· an adjusted 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 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. In certain market conditions, we also incur short-term debt in connection with supply and logistics activities that involve the simultaneous purchase and forward sale of crude oil, refined products, LPG and natural gas. The crude oil, refined products, LPG and natural gas purchased in these transactions are hedged. We do not consider the working capital borrowings associated with this activity to be part of our long-term capital structure. These borrowings

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are self-liquidating as they are repaid with sales proceeds. We also incur short-term debt for New York Mercantile Exchange (“NYMEX”) and IntercontinentalExchange (“ICE”) margin requirements.

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.

· 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 crude oil supply and logistics activities are balanced. We believe the variety of activities executed within our supply and logistics segment provides us with a balance that generally affords us the flexibility to maintain a base level of margin in a variety of crude oil market conditions and in certain circumstances, to realize incremental margin 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 thirteen years, we have completed and integrated approximately 65 acquisitions with an aggregate purchase price of approximately $6.8 billion. We have also implemented internal expansion capital projects totaling approximately $2.5 billion. In addition, we believe we have resources to finance future strategic expansion and acquisition opportunities. As of December 31, 2010, we had a working capital surplus of approximately $166 million and approximately $841 million 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 26 years industry experience, and an average of 15 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.

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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 objective. Such assets and businesses include crude oil related assets, refined products assets, LPG 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 asset base, knowledge base 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.

			Approximate
Acquisition	Date	Description	Purchase Price
SG Resources Mississippi, LLC (“SG Resources”)	Feb-2011	Southern Pines Energy Center (“Southern Pines”) natural gas storage facility	$	746	(1)

Nexen Holdings U.S.A. Inc. (“Nexen”)	Dec-2010	Crude oil gathering and transportation assets in North Dakota and Montana	$	229

PAA Natural Gas Storage, LLC	Sep-2009	Remaining 50% interest in PNGS	$	215	(2)

Rainbow Pipe Line Company, Ltd	May-2008	Crude oil gathering and transportation assets in Alberta, Canada	$	687

Pacific Energy Partners LP (“Pacific”)	Nov-2006	Merger of Pacific Energy Partners with and into the Partnership	$	2,456

Andrews Petroleum and Lone Star Trucking (“Andrews”)	Apr-2006	Isomerization, fractionation, marketing and transportation services	$	220

(1) Acquisition made by our subsidiary PNG.

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

Southern Pines Acquisition. On February 9, 2011, PNG acquired 100% of the equity interests in SG Resources (the “Southern Pines Acquisition”), which entity owns the Southern Pines Energy Center natural gas storage facility, for total consideration of approximately $746 million, subject to certain post-closing adjustments.

Southern Pines is a Federal Energy Regulatory Commission (“FERC”)-regulated, high-performance, salt-cavern natural gas storage facility located in Greene County, Mississippi. The facility’s current permits allow for 40 billion cubic feet (“Bcf”) of working capacity from four storage caverns. The facility commenced service in 2008 and three caverns have been placed into service, which are serving over 17 Bcf of customer contracts. These caverns are being expanded over time to their permitted capacity of 10 Bcf each. The fourth cavern is currently being drilled and is anticipated to be placed into service in the third quarter of 2012. The facility has the capacity for further expansion beyond 40 Bcf, if warranted by market demand and subject to receipt of required additional permits. Southern Pines is connected directly or indirectly to eight major natural gas pipelines servicing the Gulf Coast, Northeast, Mid-Atlantic and Southeastern U.S. markets.

See “—Recent Developments” for discussion of transactions completed in conjunction with this acquisition.

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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 business lines and enable us to leverage our asset base, knowledge base 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. Even after we have reached agreement on a purchase price with a potential seller, confirmatory due diligence or negotiations regarding other terms of the acquisition can cause discussions to be terminated. Accordingly, we typically do not announce a transaction until after we have executed a definitive acquisition agreement. 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.”

Recent Developments

During early 2011, we completed several noteworthy business transactions such as the completion of the Southern Pines acquisition for total consideration of approximately $746 million, subject to certain post-closing adjustments, as discussed within the preceding “—Acquisitions” section. In conjunction with this acquisition, PNG completed a private placement of 17.4 million common units to third-party purchasers for net proceeds of approximately $370 million. In addition, we purchased approximately 10.2 million PNG common units for approximately $230 million including our proportionate general partner contribution of $12 million. As a result of these transactions, our aggregate ownership interest in PNG decreased from approximately 77% to approximately 64%.

In addition, during early 2011, we also expanded our liquidity through various transactions such as completion of a $600 million senior notes offering and by entering into a $500 million 364-day senior unsecured credit facility. In addition, we redeemed our 7.75% senior notes that were maturing in 2012 for approximately $222 million.

Global Petroleum Market Overview

The United States comprises less than 5% of the world’s population, generates 11% of the world’s petroleum production, and consumes 22% of the world’s petroleum production. The following table sets forth projected world supply and demand for petroleum products (including crude oil, natural gas liquids (“NGL”) and other liquid petroleum products) and is derived from the Energy Information Administration’s (“EIA”) Annual Energy Outlook 2011 Early Release (see EIA website at www.eia.doe.gov).

		Projected
	2010 (1)	2011	2012	2015
	(In millions of barrels per day)
Supply
OECD (2)
U.S.	9.6	9.6	9.8	10.3
Other	11.6	11.3	11.1	10.5
Total OECD	21.2	20.9	20.9	20.8
Organization of the Petroleum Exporting Countries	34.8	35.6	36.5	37.2
Other	30.4	30.9	31.5	32.4
Total World Production	86.4	87.4	88.9	90.4

			Projected
	2010 (1)		2011		2012		2015
	(In millions of barrels per day)
Demand
OECD
U.S.	19.1		19.1		20.0		20.5
Other	26.6		26.6		26.5		26.0
Total OECD	45.7		45.7		46.5		46.5
Other	40.7		41.7		42.4		43.9
Total World Consumption	86.4		87.4		88.9		90.4

U.S. Production as % of World Production	11	%	11	%	11	%	11	%
U.S. Consumption as % of World Consumption	22	%	22	%	22	%	23	%
Net U.S. Consumption	(9.5	)	(9.5	)	(10.2	)	(10.2	)

(1) The 2010 amounts are based on ten months of actual data and two months of data derived from a short-term energy model published by the EIA.

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

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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 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, such as specific gravity (generally referred to as light or heavy), sulfur content (generally referred to as sweet or sour) and metals content, which 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. For the 20-year time period beginning in 1985 through 2004, U.S. refinery demand for crude oil increased 29% from 12.0 million barrels per day to approximately 15.5 million barrels per day. U.S. refinery demand for crude oil demand remained effectively flat from 2005 through 2007 at around 15.5 million barrels per day, after which refinery demand decreased to average approximately 14.6 million barrels per day for the 12 months ended October 2010. Of this amount, only 5.5 million barrels per day was produced domestically. Accordingly, approximately 62% of the crude oil used by U.S. domestic refineries is imported. This imbalance represents a multi-year trend, with foreign imports of crude oil tripling over a 23-year period, from 3.2 million barrels per day in 1985 to approximately 10.1 million barrels per day from 2005-2007. Concurrent with decreased refinery demand and recent increases in domestic production, foreign crude imports have slowed to 9.1 million barrels per day for the 12 months ended October 2010. Reduced demand for petroleum products from end users 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. Since 2000, ethanol production has grown from approximately 100,000 barrels per day to approximately 840,000 barrels per day for the 12 months ended October 2010. Growth in ethanol and other renewable fuel production is expected to continue. The EIA is currently forecasting a continued gradual decline in foreign crude imports from current levels, which is attributable to increased domestic production, increased refined product imports and increase supply from other liquid products, including ethanol and biodiesel. The table below shows the overall domestic petroleum consumption projected out to 2015 and is derived from recent information published by the EIA (see EIA website at www.eia.doe.gov). The amounts in the 2010 column are based on the twelve months from November 2009 to October 2010.

	Actual	Projected
	2010	2011	2012	2015
	(In millions of barrels per day)
Supply
Domestic Crude Oil Production	5.5	5.3	5.4	5.7
Net Imports - Crude Oil	9.1	9.2	9.0	8.8
Crude Oil Input to Domestic Refineries	14.6	14.5	14.4	14.5
Net Product Imports	0.5	0.5	1.1	1.2
Supply from Renewable Sources	0.8	0.9	1.0	1.1
Other - (NGL Production, Refinery Processing Gain)	3.2	3.2	3.5	3.7
Total Domestic Petroleum Consumption	19.1	19.1	20.0	20.5

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 October 2010 and is derived from information published by the EIA (see EIA website at www.eia.doe.gov) (in millions of barrels per day).

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	Regional	Refinery	Supply
Petroleum Administration Defense District	Supply	Demand	Shortfall
PADD I (East Coast)	0.0	1.1	(1.1	)
PADD II (Midwest)	0.7	3.3	(2.6	)
PADD III (South)	3.2	7.3	(4.1	)
PADD IV (Rockies)	0.4	0.6	(0.2	)
PADD V (West Coast)	1.2	2.3	(1.1	)
Total U.S.	5.5	14.6	(9.1	)

Although PADD III has the largest absolute volume supply shortfall, we believe PADD II is the most critical region with respect to supply and transportation logistics because it is the largest, most highly populated area of the U.S. that does not have direct access to oceanborne cargoes.

From 1985 until 2004, crude oil production in PADD II has declined from approximately 1.1 million barrels per day to approximately 440,000 barrels per day. Over this same time period, refinery demand has increased from approximately 2.7 million barrels per day in 1985 to 3.3 million barrels per day in 2004. As a result, the volume of crude oil transported into PADD II has increased approximately 75% in absolute terms or 3.0% annually from 1.7 million barrels per day to 3.0 million barrels per day. This aggregate shortfall was principally supplied by direct imports from Canada to the north and from the Gulf Coast area and the Cushing Interchange to the south.

Starting in 2005, PADD II production began to grow and as of early 2011 is currently estimated to be over 700,000 barrels per day, driven mainly by increased production from the Bakken oil formation in North Dakota. This production growth is in an isolated part of the country, which has created its own infrastructure challenges and opportunities. Both the incremental Canadian oil production growth and the PADD II growth have generally targeted the Cushing & Patoka crude oil hubs. This has resulted in a decline in volumes moved from the Gulf Coast area into PADD II, but an increase in demand for storage at Cushing and Patoka.

Volatility in various aspects of the crude oil market including absolute price, market structure, 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 trend narrowing the gap between supply and demand;

· Temporal increases in the gap related to supply response following price spikes and declines in the rate of demand growth due to worldwide economic slowdown;

· Regional supply and demand imbalances;

· Political instability in critical producing nations;

· Policy decisions made by various governments around the world attempting to navigate energy challenges; and

· Significant fluctuations in absolute price as well as grade and location differentials.

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

Refined Products Market Overview

Once crude oil is transported to a refinery, it 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.

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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 and, to a lesser extent, weather conditions. According to the EIA, consumption of refined products in the United States has risen from approximately 15.7 million barrels per day in 1985 to a peak in 2005 of 20.8 million barrels, yielding an average annual increase of approximately 1.5%. Due to the economic weakness of the last several years, refined product demand decreased to 18.8 million barrels per day in 2009, or an approximate 10% decrease over peak demand levels. Given this decreased demand for refined products and resulting excess refining capacity, a number of U.S. refineries reduced output and, in some cases, indefinitely closed. Demand for refined products has resumed growth in 2010 with consumption reaching approximately 19.1 million barrels per day for the twelve months ended October 2010. The EIA is currently forecasting growth in refined product demand for the next several years. The level of future demand growth will be influenced by the slope of the economic recovery and absolute prices. We believe that this projected demand growth will be met primarily by the increase in mandated alternative fuels, increased utilization of existing refining capacity as well as increased imports of refined products, the combination of which we believe will continue to generate demand for midstream infrastructure, including pipelines and terminals. We believe that demand for refined products pipeline and terminalling infrastructure will also be driven by the following factors:

· multiple specifications of existing products (also referred to as boutique gasoline blends);

· continued specification changes to existing products, such as lower sulfur limits; and

· increased acceptance and mandates of biofuels and other related renewable fuels.

The complexity and volatility of the refined products market creates opportunities to solve the logistical challenges inherent in the business.

LPG Products Market Overview

LPGs are hydrogen-based gases that are derived from crude oil refining and natural gas processing and include propane, butane and isobutane. These gases liquefy at moderate pressures thus allowing transportation and storage opportunities. LPG is produced domestically or imported into the U.S. from Canada and other parts of the world. Individual LPG products have varying uses. For example, propane is used in domestic applications (home heating and cooking), industrial applications, agricultural applications (crop drying) and as an automotive fuel. Normal butane is used as a petrochemical feedstock, as a blendstock for motor gasoline, and to derive isobutane through isomerization. Isobutane is principally used in refinery alkylation to enhance the octane content of motor gasoline or in the production of isooctane or other octane additives. Certain LPGs are also used as diluents in the transportation of heavy oil, particularly in Canada.

The LPG market is driven by:

· seasonal shifts in weather;

· seasonal changes in gasoline specifications affecting demand for butane;

· alternating needs of refineries to store and blend LPG;

· petro-chemical demand;

· diluent requirements for Canadian heavy oil; and

· inefficiencies caused by regional supply and demand imbalances.

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

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Natural Gas 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.

The long-term demand for storage services in the United States is driven primarily by the long-term 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 other basis. In general and on a long term basis, to the extent the overall demand for natural gas increases and such growth includes higher demand from seasonal or weather-sensitive end-users (such as gas-fired power generators and residential and commercial consumers), demand for natural gas storage services should also grow. In addition, 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, should increase the need for and the value of storage services. On a short term basis, storage demand and values are also significantly influenced by operational imbalances, near term seasonal spreads, shorter term spreads and basis differentials.

Natural Gas Demand. During the period from 2001 through 2010, domestic natural gas consumption has grown, albeit unevenly, driven primarily by growth in the seasonal and weather-sensitive electric power generation and commercial sectors, offset by declines in the residential and industrial sectors.

Natural Gas Supply. For a number of years during the last decade, domestic natural gas production was relatively flat and has failed to keep pace with domestic consumption. Over the past few years, however, domestic natural gas production has been growing. This trend reversal is primarily due to increases in production from developing shale resource plays. According to EIA data, domestic production of natural gas increased by an average of approximately 3.7% per annum during the four-year period beginning January 1, 2007 through December 31, 2010. By comparison, EIA data also indicates that 2009 production from shale gas wells was approximately 3.1 trillion cubic feet (“Tcf”), representing an approximate 142% increase over 2007 levels. At the time of this report, 2010 production estimates by component (i.e. shale gas) were not available from EIA.

In addition to the emergence of domestic shale plays as a significant supply source, over the past several years, the U.S. has developed significant infrastructure for the import of liquefied natural gas (“LNG”). Total LNG import capacity of U.S. infrastructure has increased to approximately 14 Bcf per day; however, because LNG suppliers have been able to obtain more favorable prices in global markets outside of the U.S., LNG imports into the U.S. have decreased from a peak of 2.1 Bcf a day in 2007 to less than 1.2 Bcf per day in 2009 and 2010, per EIA and other published daily data sources.

Market Balance and Volatility. The seasonality of natural gas 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. Natural gas storage (and to a lesser extent imported natural gas from Canada and LNG supplies) 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 as a warehouse for gas production in excess of daily demand during low demand periods. This seasonal consumption pattern is a major driver of demand for gas storage and the price difference, or “spread,” between the summer and winter season provides a proxy for the fundamental value of storage.

During most of the past decade, this strong seasonal trend has produced seasonal spreads that have generally moved within a range of approximately $0.50-$4.75 per MMBtu, with the high end of that range occurring during the 2006-2007 timeframe. However, during the past six months, seasonal spreads fell to as low as $0.43, their lowest point since 2004. In addition, lower short-term spreads and basis differentials have reduced overall market volatility, 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) relatively flat natural gas consumption over the last year and projected flat consumption for the next two years, (ii) increased natural gas supplies due to production from shale resources, (iii) lower basis differentials due to expansion of natural gas transportation infrastructure in the U.S. over the last five years, and (iv) abnormal seasonal weather patterns resulting in decreased seasonal price spreads.

Supply of Storage Capacity. Another important factor in determining the value of storage is whether there is a surplus or shortfall of storage capacity relative to the overall demand for storage services in a given market area. In general, on a relative basis, storage values will be lower in markets that are oversupplied with storage than in markets where storage capacity is in short supply. The extent to which markets are oversupplied or undersupplied will fluctuate based on capacity additions and in response to significant variations in natural gas supply and demand.

While it is difficult to predict when, and how much, new capacity will be added to the market in the next few years, we believe that certain of the supply and demand factors contributing to the current softness in the storage market (i.e., robust supply levels, lower natural gas demand levels and reduced price volatility) 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 and crude oil, refined product and LPG transportation corridors in the United States and Canada.

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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 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 Butte, Frontier, Settoon Towing and White Cliffs, in which we own noncontrolling interests.

As of December 31, 2010, we employed a variety of owned or leased long-term physical assets throughout the United States and Canada in this segment, including approximately:

· 16,000 miles of active crude oil and refined products pipelines and gathering systems;

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

· 56 trucks and 352 trailers; and

· 65 transport and storage barges and 39 transport tugs through our interest in Settoon Towing.

The following is a tabular presentation of our active pipeline assets in the United States and Canada as of December 31, 2010, grouped by geographic location:

Region / Pipeline and Gathering Systems (1)	System Miles	2010 Average Net Barrels per Day (2)
		(in thousands)
Southwest US
Basin	519	378
Permian Basin Area Systems	3,085	371
Other	406	141
Southwest US Subtotal	4,010	890
Western US
All American	138	39
Line 63/Line 2000	426	109
Other	148	83
Western US Subtotal	712	231
US Rocky Mountain
Salt Lake City Area Systems	708	135
Other	3,857	280
US Rocky Mountain Subtotal	4,565	415
US Gulf Coast
Capline(3)	631	223
Other	924	322
US Gulf Coast Subtotal	1,555	545
Central US Subtotal	2,462	350
Domestic Total	13,304	2,431

Canada
Rangeland	1,214	52
Rainbow	594	187
Manito	559	61
Other	633	158
Canada Total	3,000	458
Grand Total	16,304	2,889

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

(2) Represents average volume for the entire year of 2010.

(3) Non-operated pipeline.

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Southwest US

Basin Pipeline System. We own an approximate 87% undivided joint interest in and act as 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 is a 519-mile mainline, telescoping crude oil system with a system capacity ranging from approximately 144,000 barrels per day to 400,000 barrels per day depending on the segment. System throughput (as measured by system deliveries) was approximately 378,000 barrels per day (attributable to our interest) during 2010.

The Basin system consists of four primary movements of crude oil: (i) barrels that are shipped from Jal, New Mexico to the West Texas markets of Wink and Midland; (ii) barrels that are shipped from Midland to connecting carriers at Colorado City; (iii) barrels that are shipped from Midland and Colorado City to connecting carriers at either Wichita Falls or Cushing and (iv) foreign and Gulf of Mexico barrels that are delivered into Basin at Wichita Falls and delivered to connecting carriers at Cushing. 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 FERC.

We recently approved an expansion project on the Basin system to increase pipeline capacity on crude oil movements from Colorado City, Texas to Cushing, Oklahoma to approximately 450,000 barrels per day. The project is expected to be completed in the first quarter of 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, Texas. These systems are subject to tariff rates regulated by either the FERC or state regulatory agencies. For 2010, combined throughput on the Permian Basin area systems totaled an average of approximately 371,000 barrels per day.

Western US

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 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 (as reflected in the table below). See Item 1A. “Risk Factors” for discussion of the estimated impact of a decline in volumes.

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The table below sets forth the historical volumes received from both of these fields for the past five years (barrels in thousands):

	For the Year Ended December 31,
	2010	2009	2008	2007	2006
Average daily volumes received from:
Point Arguello (at Gaviota)	6	6	7	8	9
Santa Ynez (at Las Flores)	33	34	38	38	40
Total	39	40	45	46	49

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 26 storage tanks with 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. For 2010, combined throughput on Line 63 totaled an average of approximately 51,000 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 130,000 barrels per day. During 2010, throughput on Line 2000 averaged approximately 58,000 barrels per day.

US Rocky Mountain

Salt Lake City Area Systems. We operate the Salt Lake City Area systems, in which we own between 75% and 100% interests. The Salt Lake City Area 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. The Salt Lake City Area systems consist of 708 miles of pipelines and approximately 1 million barrels of storage capacity. The Salt Lake City Area systems have a combined throughput capacity of approximately 120,000 barrels per day to Salt Lake City and 20,000 barrels per day to Ft. Laramie. For 2010, throughput on the Salt Lake City Area Systems in total averaged approximately 135,000 barrels per day.

US Gulf Coast

Capline Pipeline System. The Capline Pipeline system is a 631-mile, 40-inch mainline crude oil pipeline originating in St. James, Louisiana, and terminating in Patoka, Illinois. In October 2010, we purchased an additional undivided 11% interest in the Capline Pipeline System which increased our aggregate undivided joint interest to approximately 54%. We also own a 100% interest in 720,000 barrels of tankage located at Patoka, Illinois.

The Capline Pipeline system is one of the primary transportation routes for crude oil shipped into the Midwestern U.S., serving approximately 3 million barrels of refining capacity in PADD II. Shell Pipeline Company LP is the operator of this system through August 2013. Capline has direct connections to a significant amount of crude production in the Gulf of Mexico. In addition, with its two active docks capable of handling approximately 600,000-barrel tankers as well as access to

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the Louisiana Offshore Oil Port and our St. James terminal, it is a key transporter of sweet and light sour foreign crude to PADD II. Total designed operating capacity is approximately 1 million barrels per day of crude oil. In connection with the purchase of our additional undivided interest in the system, our attributable interest in this operating capacity has increased from approximately 470,000 barrels per day to approximately 600,000 barrels per day. Throughput on our interest averaged approximately 223,000 barrels per day during 2010.

Canada

Rangeland System. We own a 100% interest in the Rangeland system, which includes the Mid Alberta Pipeline (“MAPL”) and the Rangeland Pipeline. The Rangeland system consists of a 554 mile, 8-inch to16-inch mainline pipeline and 660 miles of 3-inch to 8-inch gathering pipelines. Rangeland transports butane, condensate, light sweet crude and light sour crude either north to Edmonton, Alberta by MAPL or south to the U.S./Canadian border near Cutbank, Montana, where it connects to our Western Corridor system. On April 1, 2010, we successfully reversed MAPL allowing for flow from Rangeland’s Sundre, Alberta terminal directly to Edmonton, Alberta. During 2010, Plains built and commissioned 80,000 barrels of tankage bringing our storage capability at Edmonton to 400,000 barrels. Total average throughput during 2010 on the Rangeland system was approximately 52,000 barrels per day.

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 located in Zama, Alberta to Edmonton, Alberta and 114 miles of gathering pipelines. During 2009, we added a heavy oil truck terminal at Nipisi, Alberta to provide producers with additional access to Rainbow. The system has a throughput capacity of approximately 220,000 barrels per day and transported approximately 187,000 barrels per day during 2010.

Manito. We own a 100% interest in the Manito heavy oil system. This 559-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 339 miles of pipeline, the mainline segment originates at Dulwich and terminates at Kerrobert, Saskatchewan. The Bodo/Cactus Lake pipeline is 136 miles long 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. At the end of 2009, Plains made the necessary changes to the Kerrobert terminal to expand the flexibility whereby we can now both receive and deliver heavy crude from and to the Enbridge pipeline system. For 2010, approximately 61,000 barrels per day of crude oil were transported on the Manito system.

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, LPG and natural gas, as well as LPG fractionation and isomerization 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) terminalling fees, or throughput fees, that are generated when we receive crude oil, refined products, LPG or natural gas from one connecting pipeline and redeliver the applicable product to another connecting carrier, (iii) hub service fees for the movement of natural gas across our header systems, and (iv) fees from LPG fractionation and isomerization services.

As of December 31, 2010, we owned, operated and employed a variety of long-term physical assets throughout the United States and Canada in this segment, including:

· approximately 59 million barrels of crude oil and refined products capacity primarily at our terminalling and storage locations;

· approximately 6 million barrels of LPG storage capacity;

· approximately 50 Bcf of natural gas storage working capacity;

· approximately 11 Bcf of base gas in storage facilities owned by us; and

· a fractionation plant in Canada with a processing capacity of 4,400 barrels per day, and a fractionation and isomerization facility in California with an aggregate processing capacity of 26,000 barrels per day.

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As of December 31, 2010, we were in the process of constructing approximately 4 million barrels of additional above-ground crude oil and refined product terminalling and storage capacities and an additional 18 Bcf of high-deliverability salt-cavern natural gas storage capacity.

The following is a tabular presentation of our active facilities segment storage assets in the United States and Canada as of December 31, 2010, grouped by product type:

Facility		Capacity (in millions of barrels, except where noted)
Crude Oil and Refined Products
Cushing		14
Kerrobert		1
LA Basin		8
Martinez and Richmond		5
Mobile and Ten Mile		3
Patoka		5
Philadelphia Area		4
St. James		7
Other		12
Subtotal		59
LPG
Bumstead		2
Tirzah		1
Other		3
Subtotal		6
Natural Gas
Pine Prairie		24 Bcf
Bluewater		26 Bcf
Subtotal		50 Bcf

The discussion below contains a detailed description of our more significant facilities segment assets.

Major Facilities Assets

Crude Oil and Refined Products

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. Our Cushing Terminal was constructed in 1993, with an initial tankage capacity of 2 million barrels, to capitalize on the crude oil supply and demand imbalance in the Midwest. 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. The facility also incorporates numerous environmental and operational safeguards that distinguish it from other facilities at the Cushing Interchange.

Since 1999, we have completed multiple expansions, which increased the capacity of the Cushing Terminal to a total of approximately 14 million barrels. During the first quarter of 2010, we placed into service four 570,000-barrel tanks, and during the fourth quarter of 2010 completed construction on four additional 270,000-barrel tanks. See “Crude Oil Storage Facilities Under Construction and Under Development” below for discussion of ongoing expansion activities at this facility.

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.

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L.A. Basin. We own five crude oil and refined product storage facilities in the Los Angeles area with a total of 8 million barrels of useable storage capacity and a distribution pipeline system of approximately 70 miles of pipeline in the Los Angeles Basin. Approximately 7 million barrels of the storage capacity are used for commercial service and 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, our Line 2000 pipeline, 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 train.

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 through a 36-inch pipeline connecting the two facilities, of which approximately two-thirds of the storage capacity is included within the 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 5 million barrels of storage capacity and the associated manifold and header system at the Patoka Interchange located in southern Illinois. During 2010, we completed Phase II and III storage capacity expansion projects adding 600,000 barrels and 800,000 barrels, respectively. Patoka is a growing regional hub with access to domestic and foreign crude oil volumes moving north on the Capline system as well as Canadian barrels moving south. See “Crude Oil Storage Facilities Under Construction and Under Development” below for discussion of ongoing expansion activities at this facility.

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 7 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 also includes a manifold and header system that allows for receipts and deliveries with connecting pipelines at their maximum operating capacity. Over the past two years, we completed the construction of a marine dock that is able to receive both barges and tankers, as well as Phase II of our expansion project adding approximately 900,000 barrels of storage capacity.

Crude Oil Storage Facilities Under Construction and Under Development

Cushing Terminal & Mid-Continent Area. Late in 2010, we began construction on additional crude oil tankage at our Cushing Terminal at an estimated cost of $85 million. The project, which consists of three phases, includes adding a new pipeline interconnect and approximately 4 million barrels of storage capacity through the construction of sixteen 270,000 barrel tanks. Construction of Phases IX, X and XI are supported by long-term customer commitments and are expected to be placed in service by the end of 2011.

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Patoka Terminal. Early in 2011, we approved construction of Phase IV at our Patoka Terminal. This project will include the construction of two 300,000 barrel crude oil tanks and will increase the total storage capacity at Patoka to approximately 5 million barrels. This new tankage is expected to be completed in the first quarter of 2012 at an approximate cost of $18 million.

Pier 400. This is a project to develop a deepwater petroleum import terminal at Pier 400 and Terminal Island in the Port of Los Angeles to handle marine receipts of crude oil and refinery feedstocks. As currently envisioned, the project would include a deep water berth, high capacity transfer infrastructure and storage tanks, with a pipeline distribution system that will connect to various customers.

The project Environmental Impact Report (“EIR”) was approved by the Board of Harbor Commissioners of the Port of Los Angeles on November 20, 2008. The EIR was challenged and on January 19, 2010, a final court ruling was issued in our favor. Construction of the Pier 400 project is still subject to the completion and execution of a land lease with the Port of Los Angeles and the receipt of certain other regulatory approvals, as well as the completion of commercial arrangements with potential customers. Currently, future costs to develop this project are estimated to be in the $450 to $550 million range. We currently have approximately $45 million of capitalized project costs on our balance sheet as of December 31, 2010. We expect to be in a position in 2011 to determine whether or not we will move forward with the Pier 400 project.

LPG Storage Facilities

Bumstead. The Bumstead facility is located at a major rail transit point near Phoenix, Arizona. With 133 million gallons of working capacity (approximately 100 million gallons, or approximately 2 million barrels, of useable capacity), the facility’s primary assets include three salt-dome storage caverns, a 24-car rail rack and six truck racks.

During 2010, we began upgrading and improving our Bumstead LPG storage facility, which will increase the useable capacity by approximately 700,000 barrels. This project is expected to be completed late in 2011 at a total cost of approximately $19 million.

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 and is connected to the Dixie Pipeline System (a third-party system) via our 62-mile pipeline.

LPG Processing

Shafter. Our Shafter facility located near Bakersfield, California provides isomerization and fractionation services to producers and customers of NGL. The primary assets consist of 200,000 barrels of NGL storage and a processing facility with butane isomerization capacity of 14,000 barrels per day and NGL fractionation capacity of 12,000 barrels per day. During the first quarter of 2011, we approved our Shafter Expansion Project. This project will include the construction of a 15-mile LPG pipeline system that will be capable of delivering up to 10,000 barrels per day from Occidental Petroleum Corporations’s Elk Hills Gas plant to our Shafter facility. It will also include enhancements to our storage and rail facilities. The project is expected to be placed into service in the third quarter of 2012 at an anticipated investment of approximately $50 million. We expect to invest approximately $30 million during 2011.

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Natural Gas Storage Facilities

Pine Prairie. As a strategically located, high-deliverability storage facility, Pine Prairie has attracted a diverse group of customers, including utilities, pipelines, producers, power generators, marketers and LNG importers, whose storage needs include both traditional seasonal storage services and short-term storage services. Pine Prairie is strategically positioned relative to several major market hub.

Additionally, in January 2011, the CME Group, which is the owner of the NYMEX, announced the introduction of three new natural gas futures contracts for physical delivery at Pine Prairie. The contracts began trading in February 2011 on the NYMEX floor and electronically through CME Globex and will be available for clearing services through CME ClearPort.

Pine Prairie’s pipeline header system, which includes an aggregate of 74 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 Gulf of Mexico production and LNG imports. 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 has a total current working gas storage capacity of 24 Bcf in three caverns, and planned expansions that will increase Pine Prairie’s total capacity to 42 Bcf by mid-2012 and 45 Bcf by mid-2016. Subject to market demand, project execution, sufficient pipeline capacity, available financing and receipt of future permits, we have the property rights and operational capacity to expand our Pine Prairie facility significantly beyond our current permitted capacity of 48 Bcf. Taking these considerations into account and with certain infrastructure modifications, we currently estimate that Pine Prairie could support in excess of 15 salt caverns and an aggregate storage capacity of over 150 Bcf.

In October 2010, we filed an application for a permit from the FERC to expand Pine Prairie’s working capacity up to 80 Bcf. The incremental 32 Bcf would be comprised of expanding four existing caverns by an aggregate 8 Bcf through low-cost fill and dewater operations and adding two additional caverns of 12 Bcf each, increasing the total caverns at Pine Prairie to seven caverns.

Bluewater. Bluewater is located in the State of Michigan which contains more underground natural gas storage capacity than any other state in the U.S. according to EIA data, and primarily services seasonal storage needs throughout 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 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 has total working gas storage capacity of approximately 26 Bcf in two depleted reservoirs and we expect to increase Bluewater’s working gas capacity by 2 Bcf ratably over a 9 to 10-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.

Recent Acquisition

During February 2011, we closed the Southern Pines Acquisition. See “— Acquisitions” and “— Recent Developments” above for further information regarding the Southern Pines Acquisition and related transactions.

Supply and Logistics Segment

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

· the purchase of U.S. and Canadian crude oil at the wellhead and the bulk purchase of crude oil at pipeline and terminal facilities, as well as the purchase of foreign cargoes at their load port and various other locations in transit;

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

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· the purchase of refined products and LPG from producers, refiners and other marketers;

· the resale or exchange of crude oil, refined products and LPG at various points along the distribution chain to refiners or other resellers to maximize profits; and

· the transportation of crude oil, refined products and LPG on trucks, barges, railcars, pipelines and ocean-going vessels to our terminals and third-party terminals.

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 providing upside potential associated with opportunities inherent in volatile market conditions. 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, 2010, our supply and logistics segment also owned significant volumes of crude oil and LPG 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:

· 9 million barrels of crude oil and LPG linefill in pipelines owned by us;

· 2 million barrels of crude oil and LPG linefill in pipelines owned by third parties and other long-term inventory;

· 530 trucks and 607 trailers; and

· 1,395 railcars.

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.

The following table shows the average daily volume of our supply and logistics activities for the year ended December 31, 2010 (in thousands of barrels per day):

		Volumes
Crude oil lease gathering purchases		620
LPG sales		96
Waterborne foreign crude oil imported		68
Supply & Logistics activities total		784

Crude Oil and LPG Purchases. We purchase crude oil and LPG from multiple producers under contracts and believe that we have established long-term, broad-based relationships with the crude oil and LPG producers in our areas of operations. These contracts generally range in term from a thirty-day evergreen to five years. The majority of these contracts, however, range in term from thirty-days to one year. We utilize our truck fleet and gathering pipelines as well as 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.

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We purchase LPG from producers, refiners, and other LPG 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 and third-party tank trucks or pipelines to transport LPG.

In addition to purchasing crude oil from producers, we purchase both domestic and foreign crude oil in bulk at major pipeline terminal locations and barge facilities. We also purchase LPG in bulk at major pipeline terminal points and storage facilities from major integrated oil companies, large independent producers or other LPG marketing companies. Crude oil and LPG is purchased in bulk when we believe additional opportunities exist to realize margins further downstream in the crude oil or LPG 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 LPG Sales. The activities involved in the supply, logistics and distribution of crude oil and LPG are complex and require current detailed knowledge of crude oil and LPG sources and end markets and 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 LPG 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 LPG primarily to retailers and refiners, and limited volumes to other marketers. The contracts generally range in term from a thirty-day evergreen to four years. The majority of these contracts are at market price and have terms ranging from one month to one year. We establish a margin for the crude oil and LPG 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 LPG-related futures contracts as hedging devices.

Crude Oil and LPG 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 LPG that more closely matches our physical delivery requirement, location or the preferences of our customers, we exchange physical crude oil or LPG, 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 LPG that differs in terms of geographic location, grade of crude oil or type of LPG, or physical delivery schedule from crude oil or LPG we have available for sale. Generally, we enter into exchanges to acquire crude oil or LPG 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, LPG and refined products 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 senior unsecured revolving credit facility.

When we sell crude oil, LPG, natural gas and refined products, 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 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 LPG, natural gas and refined products; 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 LPG on a forward basis, as well as to sell LPG on a current basis to local distributors and retailers. In certain cases our LPG customers prepay for their purchases, in

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amounts ranging from approximately $1 per barrel to 100% of their contracted amounts. Generally, sales of LPG and refined products settle within 10 days of the invoice date.

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

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, LPG 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, LPG, refined products and natural gas commodity prices have historically been very volatile. For example, over the last 24 years, 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. More recently, crude oil prices traded as low as $33 per barrel in early 2009, before increasing to a range of $85 to $95 per barrel in February 2011.

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 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 75% 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 LPG 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 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 line loss allowance barrels, and if crude oil prices are low relative to historical prices, we may hedge part of the fuel needed to operate our trucks and barges. Also, during periods when supply exceeds the demand for crude oil, LPG 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, LPG 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, LPG 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.

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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. 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 of whether there is value 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 risk 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. 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 (i) to purchase only product for which we have a market, (ii) to structure our sales contracts so that price fluctuations do not materially affect the segment profit we receive, and (iii) not to acquire and hold physical inventory, futures contracts or other derivative products 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, LPG 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 15 to our Consolidated Financial Statements.

Customers

Marathon Oil Corporation and its affiliates accounted for 14% of our revenues for each of the three years ended December 31, 2010, 2009 and 2008. ConocoPhillips Company accounted for 10%, 12% and 12% of our revenues for the years ended December 31, 2010, 2009 and 2008, respectively. No other customers accounted for 10% or more of our revenues during any of the three years ended December 31, 2010. The majority of revenues from these customers pertain to our supply and logistics operations. 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 8 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.

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 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. 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 injunctive remedies, the effect of which would subject us to operational requirements and constraints that would not apply to our competitors. See Item 3. “Legal Proceedings.”

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 (“the 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.

The HLPSA was amended by the Pipeline Safety Improvement Act of 2002 and the Pipeline Inspection, Protection, Enforcement and Safety Act (“PIPES 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. Costs associated with the inspection, testing and correction of identified anomalies were approximately $31 million in 2010, $25 million in 2009 and $23 million in 2008. Based on currently available information, our preliminary estimate for 2011 is that we will incur approximately $12 million in operational expenditures and approximately $25 million in capital expenditures associated with our pipeline integrity management program. The acquisitions we have completed over the last several years have included pipeline assets of varying ages and maintenance and operational histories. Accordingly, we will continue to focus on pipeline integrity management as a primary operational emphasis. 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.

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In 2010, Congress began hearings on the reauthorization of the PIPES Act, which expired in September 2010. Congress did not complete the reauthorization process in 2010, so it will be deferred to 2011 for the new 112th Congress to consider. However, a lapse has no real effect on PHMSA regulation or programs as the pipeline safety program will continue at its previous funding levels. As part of the reauthorization process, on October 18, 2010, PHMSA issued an Advance Notice of Proposed Rulemaking (“ANPRM”). Within the ANPRM, PHMSA stated that it is considering whether changes are needed to the regulations covering hazardous liquid pipelines and is seeking public comment on six specific topic areas. The six topics include, (1) the scope of the pipeline safety regulations and existing regulatory exceptions, (2) the criteria for designation as a High Consequence Area (“HCA”), (3) leak detection and Emergency Flow Restricting Devices, (4) valve spacing, (5) repair criteria for non-HCA areas, and (6) Stress Corrosion Cracking. At this point we cannot predict what new requirements, if any, may come about as a result of reauthorization of the PIPES Act and PHMSA’s ANPRM. Significant additional operating expenses could be incurred if new or more stringently interpreted pipeline safety requirements are implemented.

Effective July 2008, PHMSA amended its pipeline safety regulations to extend protection to designated unusually sensitive areas or “USAs” that could be damaged by failure of certain rural onshore hazardous liquid gathering lines or low-stress pipelines. These USAs include locations containing sole-source drinking water, endangered species, or other ecological resources. Operators of rural onshore hazardous liquid gathering lines located within a defined “buffer” area around a USA must comply with safety requirements to address threats of corrosion and third-party damage to their lines by developing a damage prevention program, complying with specified corrosion control requirements, and monitoring and mitigating conditions that could lead to internal corrosion. The amended rules narrow the regulatory exception for rural onshore low-stress hazardous liquid pipelines by extending existing safety regulations (including integrity management requirements) to certain low-stress pipelines within a defined “buffer” area around a USA. In June 2010, PHMSA proposed to extend the amended requirements to all remaining rural low-stress hazardous liquid pipelines that were not covered by the initial rulemaking. We have less than 300 miles of pipeline subject to the amended rules and do not expect compliance to have a material effect on our operating expenses.

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 must be written by August 1, 2011 and implemented by February 1, 2013. In November 2010, PHMSA proposed to expedite program implementation for most of the rule’s requirements to August 2011. We have already incorporated many of the new rule’s requirements into our control room operations and we anticipate completing the revisions to our management plan and fully implementing the new provisions prior to the deadlines established in this new rule or prior to the proposed expedited deadline.

We have an internal review process in which we examine the condition and operating history of certain pipelines 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 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. Initial compliance, subject to an applicable waiver or stay, was required in May 2009. Costs associated with this program were approximately $25 million, $22 million and $41 million in 2010, 2009 and 2008, respectively. For 2011, we have budgeted approximately $26 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

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tankage may be constructed.

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 $23 million in 2010, $20 million in 2009 and $8 million in 2008 on these types of costs. Our preliminary estimate for 2011 is approximately $28 million.

Although we believe that our pipeline operations are in substantial compliance with currently applicable regulatory requirements, 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 in the U.S. and Canada.

Occupational Safety and Health

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. 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.

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.

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.

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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, 2010, we had incurred approximately $19 million of remediation costs associated with these sites, while SOP’s share has been approximately $8 million.

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

Air Emissions

Our operations are subject to the U.S. Clean Air Act (“Clean Air Act”) and comparable state and provincial laws. 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 state and regional air emissions control 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. For example, EPA has recently proposed a significant tightening of the national ambient air quality standards for ozone which, if adopted, could require significant reductions in emissions of volatile organic compounds and nitrogen oxides in regions of the U.S. that have not previously been subject to the most stringent emissions limitations.

Climate Change Initiatives

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 United Nations Framework Convention on Climate Change, also known as the “Kyoto Protocol.” The Kyoto Protocol requires Canada to reduce its emissions of GHG to 6% below 1990 levels by 2012.

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 tonnes per year (“kt/y”) of CO2 equivalent 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 operations of Plains Midstream Canada (“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 will require 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.

Draft regulations to reduce GHGs from the electricity sector are expected to be published in Canada Gazette early in 2011 and final regulations published later this year. This will allow sufficient time for consultations and outreach with industry and other stakeholders. Regulations are scheduled to come into effect on July 1, 2015. 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.

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The United States is not participating in the Kyoto Protocol, and, as a result of the November 2010 elections, it appears unlikely that the U.S. Congress will adopt significant climate change legislation within the next two years. However, numerous states already have begun implementing either GHG reporting requirements or actual measures to reduce GHG emissions through mechanisms such as regional cap-and-trade programs. There has also been considerable regulatory activity at the federal level even in the absence of new legislation. Some of the more notable federal actions are:

· In October 2009, EPA issued a rule requiring annual reporting of GHG emissions from stationary facilities.

· On December 15, 2009, EPA published a formal endangerment finding that sets the groundwork for GHG’s to be regulated pollutants under the Clean Air Act.

· In May 2010, EPA and the National Highway Transportation Safety Administration (NHTSA) jointly issued rules setting GHG standards for light-duty vehicles.

· In June 2010, EPA issued a rule establishing major source thresholds and permitting requirements for large emitters of GHG’s.

· In December 2010, EPA and NHTSA announced they would be proposing GHG standards for medium and heavy-duty vehicles.

· In January 2011, EPA began requiring state environmental agencies to specify GHG emission control requirements in permits for new or substantially modified sources of significant GHG emissions.

We anticipate that a small number of our facilities (less than ten) will be subject to the GHG reporting requirements in 2011 and 2012. These include facilities with combustion GHG emissions and potential fugitive emissions above the reporting thresholds, and we expect to report entity-wide GHG emissions on the basis of finished fuels that we import from outside of the U.S. 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.

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 11 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.

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

State Regulation. Our intrastate 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 Commission (“CPUC”). The CPUC prohibits certain of our subsidiaries from acting as guarantors of our senior notes and credit facilities. See Note 12 to our Consolidated Financial Statements. The TRRC is subject to a sunset condition. If the Texas Legislature does not continue the TRRC, the TRRC will be abolished effective September 1, 2011 and will begin a one-year wind-down process. The Sunset Advisory Commission has recommended certain organizational changes be made to the TRRC. We cannot tell what, if any, changes will be made to the TRRC as a result of the pending regular session or any called sessions of the Texas Legislature in 2011, but we do not believe that any such changes would affect our business in a way that would be materially different from the way such changes would affect our competitors.

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.

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 (“BOEMRE”)) 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. The current methodology (the producer price index for finished goods plus an adjustment factor of 1.3 percent) will remain in place through June 30, 2011. Effective July 1, 2011, the index for the next five year period will be the producer price index for finished goods plus an adjustment factor of 2.65 percent. Pipelines are allowed to raise their rates to the rate ceiling level generated by application of the index. If the methodology 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 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, agreement with an unaffiliated shipper, and settlement 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 that 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.

Our Pipelines. The FERC generally has not investigated rates 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

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, driver operations, log book maintenance, truck manifest preparations, safety placard placement on the trucks and trailer vehicles, drug and alcohol testing, operation and equipment safety, and many other aspects of truck operations. We are also subject to OSHA with respect to our trucking operations.

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.

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Cross Border Regulation

As a result of our cross border activities, including importation of crude oil, LPG 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

Interstate Regulation. Our natural gas storage facilities are classified as “natural-gas companies” under the Natural Gas Act of 1938 (“NGA”), and are therefore subject to regulation by the FERC. The NGA requires that tariff rates for gas storage facilities be just and reasonable and non-discriminatory. The FERC has authority to regulate rates and charges for natural gas transported and stored in U.S. interstate commerce or sold by a natural gas company in interstate commerce for resale. The FERC has granted our natural gas storage facilities market-based rate authority. Market-based rate authorization allows us to negotiate rates with individual customers based on market demand, which Pine Prairie, Bluewater and Southern Pines then make public via postings on their respective websites.

The FERC also has authority over the construction and operation of U.S. pipeline transportation and storage facilities and related facilities used in the transportation, storage and sale of natural gas in interstate commerce, including the extension, enlargement or abandonment of such facilities. In addition, the FERC’s authority extends to maintenance of accounts and records, terms and conditions of service, depreciation and amortization policies, 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.

Standards of Conduct for Transmission Providers. Historically, the FERC’s standards of conduct regulations (now vacated) generally restricted access to U.S. interstate natural gas storage customer data by marketing and other energy affiliates, and placed certain conditions on services provided by U.S. storage facility operators to their affiliated gas marketing entities. The standards of conduct did not apply, however, to natural gas storage providers authorized to charge market-based rates that (i) were not interconnected with the jurisdictional facilities of any affiliated interstate natural gas pipeline and (ii) had no exclusive franchise area, no captive ratepayers, and no market power. The FERC found that Pine Prairie qualified for this exemption from the standards of conduct in January 2006 and Bluewater qualified for this exemption in October 2006.

In November 2006, the D.C. Circuit vacated the standards of conduct regulations with respect to natural gas pipelines and storage companies, and remanded the matter to the FERC. Following a notice of proposed rulemaking, in October 2008, the FERC issued revised Standards of Conduct for Transmission Providers (“Standards of Conduct”). The Standards of Conduct continue to exempt natural gas storage providers like Pine Prairie and Bluewater. The FERC has since issued three Orders on Rehearing and Clarification in October and November 2009 and April 2010. However, one request for rehearing of the April 2010 order is pending with the FERC. Accordingly, there may be further modifications to the Standards of Conduct upon rehearing.

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Natural Gas Price Transparency. In April 2007, the FERC issued a notice of proposed rulemaking (“NOPR”) regarding price transparency provisions of the NGA and the Energy Policy Act of 2005 (the “EPAct 2005”). In the notice, the FERC proposed to revise its regulations to, among other things, 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. In December 2007, the FERC issued Order No. 704 implementing the annual reporting provisions of the NOPR with minimal changes to the original proposal. The order became effective in February 2008. The FERC issued two orders on rehearing in 2008, and following a technical conference in March 2010, the FERC issued an order clarifying the reporting requirements in April 2010. Pine Prairie, Bluewater and Southern Pines are subject to these annual reporting requirements.

In November 2008, the FERC issued Order No. 720 requiring interstate pipelines and certain non-interstate facilities to post certain daily capacity and volume information. The rule extends to storage facilities (such as Bluewater) that provide no-notice service. The rule has been appealed, but pending the results of that appeal, Bluewater will be subject to a requirement to post volumes with respect to no-notice service flows at each receipt and delivery point.

Energy Policy Act of 2005. Under the 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 also gives the FERC authority to impose civil penalties for violations of the NGA up to $1 million per day per violation for violations occurring after August 8, 2005. The anti-manipulation rule and enhanced civil penalty authority reflect an expansion of the FERC’s NGA enforcement authority.

Other Proposed Regulation. Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, the FERC, state commissions and the courts. The natural gas industry historically has been heavily regulated. Accordingly, we cannot provide assurances that the less stringent and pro-competition regulatory approach recently pursued by the FERC and Congress will continue.

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 2,200% 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.

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.

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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 3,500 employees at December 31, 2010. None of the employees of our general partner are subject to a collective bargaining agreement, except for nine employees covered by an agreement scheduled for renegotiation in September 2012 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, including the Canadian provinces and Canada, 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.

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 distributions to our unitholders. Unitholders may be eligible for foreign tax credits with respect to allocable Canadian 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 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.

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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. 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 (or liabilities for which no partner bears the economic risk of loss). 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 limitation described above, in the case of taxpayers subject to the passive loss rules (generally, individuals and certain closely held corporations), any partnership losses generated by us are only available to offset future income generated by us and cannot be used to offset income from other activities, including passive activities or investments. Any losses unused or suspended by virtue of the passive loss rules may be fully deducted if the unitholder disposes of all of the unitholder’s common units in a taxable transaction with an unrelated party.

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.

Non-U.S., State, Local and Other Tax Considerations

In addition to federal income taxes, unitholders will likely be subject to other taxes, such as non-U.S., state and local income taxes, unincorporated business taxes, 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 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. As a result of recent 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 is 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. Payments of interest and dividends from Canada to other Plains entities will be subject to Canadian withholding tax that is treated as a distribution.

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

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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 (http://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.

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 require the expenditure of significant amounts of capital. Many of these projects involve numerous regulatory, environmental, commercial, weather-related, political and legal uncertainties that will be beyond our control. As these projects are undertaken, required approvals may not be obtained, may be delayed or may be obtained with conditions that materially alter the expected return associated with the underlying projects. Moreover, revenues associated with these organic growth projects will not increase immediately upon the expenditures of funds with respect to a particular project and these projects may be completed behind schedule or in excess of budgeted cost. We may construct pipelines, facilities or other assets in anticipation of market demand that dissipates or market growth that never materializes. As a result of these uncertainties, the anticipated benefits associated with our capital projects may not be achieved.

Loss of credit rating or the ability to receive open credit could negatively affect our ability to purchase crude oil and LPG 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 market. Our ability to capture that benefit, however, is subject to numerous risks and uncertainties, including our maintaining an attractive credit rating and continuing to receive open credit from our suppliers and trade counterparties. For example, our ability to utilize our crude oil storage capacity for merchant activities to capture contango market opportunities is dependent upon having adequate credit facilities, including 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 supply and logistics activities.

There can be no assurance that we have adequately assessed the creditworthiness of our existing or future counterparties or that there will not be an unanticipated deterioration in their creditworthiness, which could have an adverse impact on us.

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 other parties.

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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 we purchase by selling crude oil for physical delivery to third party users, such as independent refiners or major oil companies, 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, futures contracts 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 could expose us to risk of loss resulting from price changes. We are also exposed to basis risk when crude oil is 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 810,000 barrels of crude oil, refined products and LPG. 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 our processes and procedures designed to detect unauthorized trading. We cannot assure you, however, that these steps will detect and prevent all violations of our risk policies and procedures, particularly if deception or other intentional misconduct is involved.

The nature of our business and assets exposes us to significant compliance costs and liabilities. As we add assets, we historically have experienced a corresponding increase in the absolute number of releases of crude oil into the environment. Although we believe we have reduced the trend, additional assets acquired in the future could again result in increased frequency of releases. Substantial expenditures may be required to maintain the integrity of our pipelines and terminals at acceptable levels.

Our operations involving the storage, treatment, processing, and transportation of liquid hydrocarbons, including crude oil 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, operational safety 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. 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. Any such change or interpretation adverse to us could have a material adverse effect on our operations, revenues and profitability.

We have a history of incremental additions to the miles of pipelines we own. We have also increased our terminalling 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. During 2006 and 2007, we acquired refined products pipeline and terminalling assets. These 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.

We currently devote substantial resources to comply with DOT-mandated pipeline integrity rules. The 2006 Pipeline Safety Act, enacted in December 2006, requires the DOT to issue regulations for certain pipelines that were not previously subject to regulation. These new regulations, adopted in July 2008, include requirements for the establishment of additional pipeline integrity management programs. We have also developed and implemented certain integrity measures that go beyond regulatory mandate. A portion of these measures are now incorporated into the September 2010 Consent Decree. See Items 1 and 2. “Business and Properties—Regulation—Environmental, Health and Safety Regulation—Pipeline Safety/Pipeline and Storage Tank Integrity Management” and “Legal Proceedings — United States Environmental Protection Agency v. Plains All American Pipeline, L.P.”

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The acquisitions we have completed over the last several years have included pipeline assets of varying ages and maintenance and operational histories. Accordingly, for 2011 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 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 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. See Item 3. “Legal Proceedings—Environmental.”

The level of our profitability is dependent upon an adequate supply of crude oil from fields located offshore and onshore California. A shut-in of this production due to economic limitations, a significant event or restrictive regulation could adversely affect our profitability. In addition, these offshore fields have experienced substantial production declines since 1995.

A portion of our transportation segment profit is derived from pipeline transportation tariff 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. We estimate that a 5,000 barrel per day decline in volumes shipped from these OCS fields would result in a decrease in annual transportation segment profit of approximately $7 million. A similar decline in volumes shipped from the San Joaquin Valley would result in an estimated $3 million decrease in annual transportation segment profit.

In addition, the recent explosion and sinking of the Deepwater Horizon drilling rig in the Gulf of Mexico, as well as the resulting oil spill, may 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. For example, new legislation has been proposed which would revamp federal oversight of offshore drilling, set new safety standards for drilling equipment and well design, and increase liability limits for offshore drilling companies, among other provisions. Other governmental responses may include deep-water drilling moratoria or other potentially major restrictions on drilling and production. Although we currently have no assets that would directly be affected by such regulation, we cannot predict with any certainty whether such regulation if enacted, might indirectly affect our business.

Our profitability depends on the volume of crude oil, refined product and LPG shipped, purchased and gathered.

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 can negatively affect our operating results.

Demand for crude oil is dependent upon the impact of future economic conditions, fuel conservation measures, alternative fuel requirements, governmental regulation or technological advances in fuel economy and energy generation devices, all of which could reduce demand. 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.

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Fluctuations in demand for crude oil, such as caused by refinery downtime or shutdown, 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.

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 timely and effectively to integrate the underlying assets and such assets perform at or near the levels anticipated in our acquisition projections.

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 internal growth. These transactions can be effected quickly, may occur at any time and may be significant in size relative to our existing assets and operations. Any material acquisition or internal growth project will require access to capital. 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.

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.

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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 (meaning that the price of crude oil for future deliveries is higher than current prices) is favorable to commercial strategies that are associated with storage tankage as it allows a party to simultaneously purchase production 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.

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 system may reduce the amount of cash we generate.

Our U.S. interstate common carrier pipelines are subject to regulation by the FERC under the ICA. The ICA requires that tariff rates for petroleum 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 pipelines subject to FERC regulation under the ICA, shippers may protest our pipeline tariff filings, 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 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, NGLs 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, NGLs or other energy commodities, and any related transportation and/or hedging activities that we undertake, we are

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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 use of such capacity. Any failure on our part to comply with the FERC’s regulations and policies, or with an interstate pipeline’s tariff, 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.

We face competition in our transportation, facilities and supply and logistics activities.

Our competitors include other crude oil pipelines, the major integrated oil companies, their marketing affiliates, and independent gatherers, investment banks, 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.

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. We can give no assurance that we will be able to maintain adequate insurance in the future at rates we consider reasonable. The occurrence of a significant event not fully insured could materially and adversely affect our operations and financial condition.

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, 2010, our consolidated debt outstanding was approximately $6.0 billion, consisting of approximately $4.6 billion principal amount of long-term debt (including senior notes) and approximately $1.3 billion of short-term borrowings. As of December 31, 2010, we had approximately $841 million of available borrowing capacity under our senior unsecured revolving credit facility and our senior secured hedged inventory facility.

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

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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 debt maturing in the next several years and current maturities, 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. 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.

Marine transportation of crude oil and refined product has inherent operating risks.

Our supply and logistics operations include purchasing crude oil that is carried on third-party tankers. Our waterborne cargoes of crude oil 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 cargoes.

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. We are currently a hold-over tenant with respect to such facilities. If we are unable to renew the agreement that allows us to utilize these dock facilities, and if other alternative dock access cannot be arranged, the volumes 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.

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

We use both fixed and variable rate debt, and we are exposed to market risk due to the floating interest rates on our credit facilities. As of December 31, 2010, we had approximately $6.0 billion of consolidated debt, of which approximately $4.1 billion was at fixed interest rates and approximately $1.9 billion was at variable interest rates (including $300 million of interest rate derivatives that swap fixed-rate debt for floating). From time to time we use interest rate derivatives to hedge interest obligations on specific debt issuances, including anticipated debt issuances. 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

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associated with the storage of hedged crude oil and LPG 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.

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

Because we conduct operations in Canada, we are exposed to currency fluctuations and exchange rate risks that may adversely affect our results of operations.

Terrorist attacks aimed at our facilities could adversely affect our business.

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. These developments will subject our operations to increased risks. Any future terrorist attack that may target our facilities, those of our customers and, in some cases, those of other pipelines, could have a material adverse effect on our business.

An impairment of goodwill could reduce our earnings.

At December 31, 2010, we had $1.4 billion of goodwill. 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. If we were to determine that any of our goodwill was 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 are new and have limited operating history. The 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, the facilities are new and have a limited operating history. If 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.

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.

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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.

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 will 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 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

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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:

· 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 and subsidiary guarantees is unsecured and will be effectively subordinated to our existing and future secured indebtedness as well as to any existing and future indebtedness of our subsidiaries that do not guarantee the notes.

Our debt securities are effectively subordinated to claims of our secured creditors and the guarantees are effectively subordinated to the claims of our secured creditors as well as the secured creditors of our subsidiary guarantors. Although many of our operating subsidiaries have guaranteed such debt securities, the guarantees are subject to release under certain circumstances, and we may have subsidiaries that are not guarantors. In that case, the debt securities would be effectively subordinated to the claims of all creditors, including trade creditors and tort claimants, of our subsidiaries that are not

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guarantors. In the event of the insolvency, bankruptcy, liquidation, reorganization, dissolution or winding up of the business of a subsidiary that is not a guarantor, 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 the 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, 2010, our total outstanding debt was approximately $6.0 billion. We will be prohibited from making cash distributions during an event of default under any of our indebtedness. Various limitations in our credit facilities 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. However, a significant downturn in the energy industry or other development adversely affecting our cash 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 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.

A court may use fraudulent conveyance considerations to avoid or subordinate the subsidiary guarantees.

Various applicable fraudulent conveyance laws have been enacted for the protection of creditors. A court may use fraudulent conveyance laws to subordinate or avoid the subsidiary guarantees of our debt securities issued by any of our subsidiary guarantors. It is also possible that under certain circumstances a court could hold that the direct obligations of a subsidiary guaranteeing our debt securities could be superior to the obligations under that guarantee.

A court could avoid or subordinate the guarantee of our debt securities by any of our subsidiaries in favor of that subsidiary’s other debts or liabilities to the extent that the court determined either of the following were true at the time the subsidiary issued the guarantee:

· that subsidiary incurred the guarantee with the intent to hinder, delay or defraud any of its present or future creditors or that subsidiary contemplated insolvency with a design to favor one or more creditors to the total or partial exclusion of others; or

· that subsidiary did not receive fair consideration or reasonable equivalent value for issuing the guarantee and, at the time it issued the guarantee, that subsidiary:

· was insolvent or rendered insolvent by reason of the issuance of the guarantee;

· was engaged or about to engage in a business or transaction for which the remaining assets of that subsidiary constituted unreasonably small capital; or

· intended to incur, or believed that it would incur, debts beyond its ability to pay such debts as they matured.

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The measure of insolvency for purposes of the foregoing will vary depending upon the law of the relevant jurisdiction. Generally, however, an entity would be considered insolvent for purposes of the foregoing if the sum of its debts, including contingent liabilities, were greater than the fair saleable value of all of its assets at a fair valuation, or if the present fair saleable value of its assets were less than the amount that would be required to pay its probable liability on its existing debts, including contingent liabilities, as they become absolute and matured.

Among other things, a legal challenge of a subsidiary’s guarantee of our debt securities on fraudulent conveyance grounds may focus on the benefits, if any, realized by that subsidiary as a result of our issuance of our debt securities. To the extent a subsidiary’s guarantee of our debt securities is avoided as a result of fraudulent conveyance or held unenforceable for any other reason, the holders of our debt securities would cease to have any claim in respect of that guarantee.

The ability to transfer our debt securities may be limited by the absence of a 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 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 the 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 the debt securities, or to repurchase the 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 the debt securities. We cannot assure you that we would be able to refinance the 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.

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 by individual states. 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 additional amounts of entity-level taxation for state or foreign tax purposes, it would reduce the amount of cash available to pay distributions and our debt obligations.

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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 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 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.

Recent changes in Canadian tax law will subject our Canadian subsidiaries to entity-level tax, which will reduce the amount of cash available to pay distributions and our debt obligations.

In response to changes in Canadian tax legislation and the Fifth Protocol to the U.S./Canada Income Tax Convention, on January 1, 2011, we restructured our Canadian investment. All Canadian operations are now carried on in entities that are treated as corporations for Canadian tax purposes and subject to Canadian federal and provincial income tax. Dividend and interest payments from Canada are subject to withholding taxes that are reduced from the applicable statutory withholding tax rate through the application of a tax treaty. If the Canadian tax authorities were to challenge the application of the tax treaty, it could result in a reduction of available cash.

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 been technically terminated 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 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 contests the federal income tax positions we take, the market for our common units may be adversely impacted and the cost of any IRS 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 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 positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the

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price at which they trade. In addition, our costs of any contest with the IRS 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. 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.

To maintain the uniformity of the economic and tax characteristics 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.

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 federal income taxes, our unitholders will likely be subject to other taxes, including state, local and non-U.S. 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 a result of the Canadian restructuring, 2010 is the last year that non-Canadian unitholders will be required to file Canadian tax returns with respect to an investment in our units.

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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 loaned 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 is no tax concept of loaning a partnership interest, a unitholder whose common units are loaned to a “short seller” to cover a short sale of common units may be considered as having disposed of the loaned units, he may no longer be treated for tax purposes as a partner with respect to those common units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, 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 could 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.

The tax treatment of (i) publicly traded partnerships or (ii) 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 (i) publicly traded partnerships, including us, or (ii) an investment in our common units may be modified by administrative, legislative or judicial interpretation at any time. For example, members of Congress have recently considered substantive changes to the existing federal income tax laws that affect publicly traded partnerships. Any modification to the U.S. federal income tax laws and interpretations thereof may or may not 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. Although the considered legislation would not have appeared to have affected our treatment as a partnership, we are unable to predict whether any of these changes, or other proposals will be reintroduced or will ultimately be enacted. Any such changes could negatively impact the value of an investment in our 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 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

United States Environmental Protection Agency v. Plains All American Pipeline, L.P. In September 2010, the United States District Court for the Southern District of Texas entered an order approving a Consent Decree that represented our settlement agreement with the U.S. Environmental Protection Agency (“EPA”) and the U.S. Department of Justice (“DOJ”) regarding a 2004 crude oil release that reached the Pecos River and a 2005 crude oil release that reached the Sabine River, as well as eight smaller releases. Pursuant to the Consent Decree, we paid $3.25 million in civil penalties, which we had fully reserved in our contingency accrual. Over the last several years we have proactively developed and implemented risk assessment, pipeline integrity and leak detection procedures that are incremental to those mandated by regulation. As a result of this effort and the ongoing process with EPA and DOJ, many of the operational requirements contained in the Consent Decree have already been incorporated into our operating practices, and the anticipated costs of compliance have been incorporated into our planning.

SemCrude L.P., et al — Debtors/Samson Resources Company (U.S. Bankruptcy Court — Delaware). We will from time to time have claims relating to insolvent suppliers, customers or counterparties, such as the bankruptcy proceedings of SemCrude, which commenced in July 2008. Statutory protections and our contractual rights of setoff covered substantially all of our pre-petition claims against SemCrude and such claims have now been resolved. In separate actions, certain creditors of SemCrude, led by Samson Resources Company, have also filed state court actions alleging a producer’s lien on crude oil sold to SemCrude and its affiliates, and the continuation of such lien when SemCrude and its affiliates subsequently sold the oil to purchasers such as us. On May 29, 2009, we filed a complaint for declaratory relief to resolve these claims. Fourteen state court actions have been consolidated in Bankruptcy Court. One action is in Federal Court in New Mexico. We intend to vigorously defend our contractual and statutory rights.

ExxonMobil Corp. v. GATX Corp. (Superior Court of New Jersey — Gloucester County). This Pacific legacy matter was filed by ExxonMobil in April 2003 and involves the allocation of responsibility for remediation of MTBE and other petroleum product contamination at our terminal facility in Paulsboro, New Jersey, which we acquired in the Pacific merger. We estimate that the cost to effectively remediate will be approximately $3.5 million, which amount may be higher or lower depending on the nature and extent of the cleanup. Both ExxonMobil and GATX were prior owners of the terminal. We contend that ExxonMobil and/or GATX are primarily responsible for the majority of the remediation costs. We are in dispute with Kinder Morgan (as successor in interest to GATX) regarding the indemnity by GATX in favor of Pacific in connection with Pacific’s purchase of the facility. We are vigorously defending against any claim that Plains Products Terminals LLC (formerly known as Pacific Atlantic Terminals LLC, referred to here as “PPT”) is directly or indirectly liable for damages or costs associated with the MTBE contamination.

New Jersey Department of Environmental Protection v. ExxonMobil Corp. et al. In a matter related to ExxonMobil v. GATX, in June 2007, the NJDEP brought suit against GATX, ExxonMobil and PPT to recover natural resources damages associated with, and to require remediation of, the contamination. ExxonMobil and GATX have filed third-party demands against PPT, seeking indemnity and contribution. The natural resources damages have been settled and set at $1.1 million payable to the State of New Jersey; however, PPT’s allocated share of this liability is being disputed by PPT with GATX. Court approval of the settlement is pending.

EPA v. Rocky Mountain Pipeline System. In February 2009, we received a request for information from EPA regarding aspects of the fuel handling activities of RMPS, a subsidiary acquired in the Pacific merger, at two truck terminals in Colorado. These activities included the mixture of certain blendstocks with gasoline. We provided the information requested, and cooperated in EPA’s investigation of such activities. In January 2010, we received a notice of violations from EPA, alleging failure of RMPS to comply with provisions of the Clean Air Act related to registration, sampling, recording and reporting in connection with such activities. EPA further alleges that the violations occurred on an ongoing basis from October 2006 through February 2009. EPA has referred the matter to the DOJ. We continue to engage in discussion with EPA, and to emphasize those factors that should mitigate the severity of any penalties imposed. In December 2009, RMPS self-reported late filing of certain reports required under Clean Air Act Diesel Fuel Regulations. All reports have now been filed.

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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 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.

Environmental

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.

As we expand our pipeline assets through acquisitions, we typically improve on (reduce) the releases from such assets (in terms of frequency or volume) as we implement our integrity management procedures, remove selected assets from service and spend capital to upgrade the assets. However, the inclusion of additional miles of pipe in our operations may result in an increase in the absolute number of releases company-wide compared to prior periods.

At December 31, 2010, our reserve for environmental liabilities totaled approximately $66 million, of which approximately $10 million is classified as short-term and $56 million is classified as long-term. At December 31, 2010, we have recorded receivables totaling approximately $5 million for amounts that are 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.

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 insurance of various types 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 to others with respect to our operations. With respect to all of our coverage, we may not be able to maintain adequate insurance in the future at rates we consider reasonable. As a result, we may elect to self-insure or utilize higher deductibles in certain insurance programs. In addition, although we believe that we have established adequate reserves to the extent that 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. (Removed and Reserved)

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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.” As of February 22, 2011, the closing market price for our common units was $63.79 per unit and there were approximately 125,000 record holders and beneficial owners (held in street name). As of February 22, 2011, there were 141,199,175 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)
2010
4th Quarter	$	65.20	$	60.91	$	0.9575
3rd Quarter	$	64.21	$	57.33	$	0.9500
2nd Quarter	$	60.06	$	44.12	$	0.9425
1st Quarter	$	57.11	$	49.82	$	0.9350

2009
4th Quarter	$	53.37	$	45.45	$	0.9275
3rd Quarter	$	50.33	$	42.50	$	0.9200
2nd Quarter	$	45.52	$	36.25	$	0.9050
1st Quarter	$	40.98	$	34.00	$	0.9050

(1) Cash distributions for a quarter are declared and paid in the following calendar quarter. See the “Cash Distribution Policy” below for a discussion of our policy regarding distribution payments.

Our common units are 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

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, 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 $0.450 per unit, 25% of the amounts we distribute in excess of $0.495 per unit and 50% of amounts we distribute in excess of $0.675 per unit.

In order to enhance our distribution coverage ratio and liquidity following a significant acquisition, our general partner may agree to reduce the amounts due to it as incentive distributions. Upon closing the acquisitions of Pacific Energy Partners LP (“Pacific”) in November 2006, Rainbow Pipe Line Company, Ltd. (“Rainbow”) in May 2008 and PAA Natural Gas Storage, LLC (“PNGS”) in September 2009, our general partner agreed to reduce the amounts due to it as incentive

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distributions. The total reduction in incentive distributions related to the Pacific, Rainbow and PNGS acquisitions was $83 million as displayed on an annual basis in the following table (in millions):

Acquisition	2007		2008		2009		2010		2011		Total
Pacific	$	20	$	15	$	15	$	10	$	5	$	65
Rainbow	—		3		6		1		—		10
PNGS	—		—		1		5		2		8
Total	$	20	$	18	$	22	$	16	$	7	$	83

Following the distribution in February 2011 (as discussed below), the aggregate remaining incentive distribution reductions are approximately $5 million.

We paid $160 million to the general partner in incentive distributions in 2010. Additionally, on February 14, 2011, we paid a quarterly distribution of $0.9575 per unit applicable to the fourth quarter of 2010, of which approximately $46 million was paid to the general partner in incentive distributions. 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 2010, 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”).

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Item 6. Selected Financial Data

The historical financial information below was derived from our audited consolidated financial statements as of December 31, 2010, 2009, 2008, 2007 and 2006 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.”

	Year Ended December 31,
	2010			2009			2008			2007			2006
	(in millions, except for per unit data)
Statement of operations data:
Total revenues (1)	$	25,893		$	18,520		$	30,061		$	20,394		$	22,445
Income before cumulative effect of change in accounting principle (2)	$	514		$	580		$	437		$	365		$	279
Net income	$	514		$	580		$	437		$	365		$	285
Net income attributable to Plains	$	505		$	579		$	437		$	365		$	285

Per unit data:
Basic net income before cumulative effect of change in accounting principle (2)	$	2.41		$	3.34		$	2.66		$	2.47		$	2.85
Basic net income after cumulative effect of change in accounting principle	$	2.41		$	3.34		$	2.66		$	2.47		$	2.93
Diluted net income before cumulative effect of change in accounting principle (2)	$	2.40		$	3.32		$	2.64		$	2.45		$	2.82
Diluted net income after cumulative effect of change in accounting principle	$	2.40		$	3.32		$	2.64		$	2.45		$	2.90
Declared distributions per limited partner unit (3)	$	3.76		$	3.62		$	3.50		$	3.28		$	2.87

Balance sheet data (at end of period):
Total assets	$	13,703		$	12,358		$	10,032		$	9,906		$	8,715
Long-term debt	$	4,631		$	4,142		$	3,259		$	2,624		$	2,626
Total debt	$	5,957		$	5,216		$	4,286		$	3,584		$	3,627
Partners’ capital	$	4,573		$	4,159		$	3,552		$	3,424		$	2,977

Other data:
Net cash provided by (used in) operating activities	$	259		$	365		$	857		$	796		$	(276	)
Net cash used in investing activities	$	(583	)	$	(660	)	$	(1,339	)	$	(663	)	$	(1,651	)
Net cash provided by (used in) financing activities	$	336		$	312		$	464		$	(124	)	$	1,927
Capital expenditures:
Acquisitions	$	407		$	393		$	735		$	125		$	3,021
Internal growth projects	$	355		$	364		$	491		$	525		$	332
Maintenance	$	93		$	81		$	81		$	50		$	28
Investments in unconsolidated subsidiaries	$	—		$	15		$	37		$	9		$	44

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	Year Ended December 31,
	2010	2009	2008	2007	2006
Volumes (4) (5) (6)
Transportation segment (average daily volumes in thousands of barrels):
Tariff activities	2,889	2,836	2,851	2,712	2,106
Trucking	97	85	97	105	101
Transportation segment total	2,986	2,921	2,948	2,817	2,207

Facilities segment:
Crude oil, refined products and LPG storage (average monthly capacity in millions of barrels)	61	56	53	46	25
Natural gas storage (average monthly capacity in bcf)	47	26	14	13	13
LPG processing (average daily throughput in thousands of barrels)	14	15	17	18	12
Facilities segment total (average monthly capacity in millions of barrels)	70	61	56	48	27

Supply & Logistics segment (average daily volumes in thousands of barrels):
Crude oil lease gathering purchases	620	612	658	685	650
LPG sales	96	105	103	90	70
Waterborne foreign crude oil imported	68	55	80	71	63
Supply & Logistics segment total	784	772	841	846	783

(1) Includes gross presentation of buy/sell transactions for all periods prior to the second quarter of 2006. See Note 2 to our Consolidated Financial Statements for further discussion of buy/sell transactions.

(2) Due to the January 1, 2006 change in our method of accounting for unit-based payment transactions, we recognized a cumulative effect of change in accounting principle of approximately $6 million.

(3) Our general partner is entitled, directly or indirectly, to receive 2% proportional distributions, and also incentive distributions if the amount we distribute with respect to any quarter exceeds levels specified in our partnership agreement. See Note 5 to our Consolidated Financial Statements.

(4) Volumes associated with acquisitions represent total volumes for the number of days or months we actually owned the assets divided by the number of days or months in the year.

(5) In September 2009, we acquired the remaining 50% indirect interest in PNGS, which resulted in our 100% ownership of the natural gas storage business and related operating entities. Natural gas storage volumes for January 2006 through August 2009 are netted to our 50% interest in PNGS. Beginning in September 2009, volumes represent our 100% interest in PNGS. See Note 3 to our Consolidated Financial Statements for additional discussion regarding the PNGS acquisition.

(6) Facilities total is calculated as the sum of: (i) crude oil, refined products and liquefied petroleum gas and other natural gas-related petroleum products (“LPG”) storage capacity; (ii) natural gas storage capacity divided by 6 to account for the 6:1 mcf of gas to crude British thermal unit (“Btu”) equivalent ratio and further divided by 1,000 to convert to monthly volumes in millions; and (iii) LPG processing volumes multiplied by the number of days in the year and divided by the number of months in the year.

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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Introduction

The following discussion is intended to provide investors with an understanding of our financial condition and results of our operations and should be read in conjunction with our historical consolidated financial statements and accompanying notes.

Our discussion and analysis includes the following:

· Executive Summary

· Company Overview

· Overview of Operating Results, Capital Spending and Significant Activities

· Acquisitions and Internal Growth Projects

· Critical Accounting Policies and Estimates

· Recent Accounting Pronouncements

· Results of Operations

· Outlook

· Liquidity and Capital Resources

Executive Summary

Company Overview

We provide transportation, storage, terminalling and supply and logistics services with respect to crude oil, refined products and LPG. Through our general partner interest and majority equity ownership position in PAA Natural Gas Storage, L.P. (NYSE: PNG), we also engage in the development and operation of natural gas storage facilities. We were formed in 1998, and our operations are conducted directly and indirectly through our operating subsidiaries and are managed through three operating segments: (i) Transportation, (ii) Facilities and (iii) Supply and Logistics. See “—Results of Operations—Analysis of Operating Segments” for further discussion.

Overview of Operating Results, Capital Spending and Significant Activities

During 2010, our net income attributable to Plains was $505 million, which was a $74 million year-over-year decrease as compared to that recognized during 2009. The major items impacting comparability between periods are:

· The unfavorable results experienced within our supply and logistics segment, which were impacted by:

· lower LPG margins;

· our derivative activities; and

· less favorable crude oil quality differentials and market structure.

· The negative impact to all segments resulting from our equity compensation expense that increased by approximately $30 million during 2010 compared to 2009.

· The favorable results experienced within:

· our facilities segment, which primarily resulted from expansions in our asset base through acquisitions and our ongoing internal growth projects; and

· our transportation segment, which primarily reflects impacts of favorable foreign currency exchange rates, increased tariff rates and other various net favorable effects.

· The negative impact of increased depreciation and amortization expense and interest expense associated with our expanded asset base and related financing costs.

See the “Results of Operations” section below for further discussion and analysis of our operating segments.

Other key items impacting 2010 include (i) the completion of debt and equity offerings for net proceeds of approximately $692 million, (ii) the completion of PNG’s initial public offering (“IPO”) for net proceeds of $268 million received from the sale of 13,478,000 PNG common units and (iii) approximately $509 million of net borrowings under our credit facilities, including $260 million of borrowings under PNG’s credit facility that was entered into in conjunction with the IPO. These net proceeds were used for (i) the repayment of our $175

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million, 6.25% senior notes, (ii) funding of our ongoing expansion capital program and acquisitions (as further discussed in the following sections) and (iii) other general partnership purposes.

Acquisitions and Internal Growth Projects

We completed a number of acquisitions and capital expansion projects in 2010, 2009 and 2008 that have impacted our results of operations. The following table summarizes our capital expenditures for acquisitions, internal growth projects, maintenance capital and investments in unconsolidated entities for the periods indicated (in millions):

	For the Year Ended December 31,
	2010		2009		2008
Acquisition capital (1)	$	407	$	393	$	735
Internal growth projects	355		364		491
Maintenance capital	93		81		81
Investment in unconsolidated entities (1)	—		15		37
	$	855	$	853	$	1,344

(1) Initial investments in unconsolidated entities are included within “Acquisition capital,” whereas additional subsequent investments in unconsolidated entities are recognized within “Investment in unconsolidated entities.”

Acquisitions

Acquisitions are financed using a combination of equity and debt, including borrowings under our credit facilities and the issuance of senior notes. Businesses acquired impact our results of operations commencing on the effective date of each acquisition. Our acquisition and capital expansion activities are discussed further in “—Liquidity and Capital Resources” and in Note 3 to our Consolidated Financial Statements. Information regarding acquisitions completed in 2010, 2009 and 2008 is set forth in the table below (in millions):

	Effective	Acquisition
Acquisition	Date	Price		Operating Segment
Nexen Holdings U.S.A. Inc.	12/30/2010	$	229	Supply & Logistics and Transportation
Other	Various	178		Transportation and Facilities
2010 Total		$	407

PNGS	09/03/2009	$	215	Facilities
Other	Various	178		Transportation and Facilities
2009 Total		$	393

Rainbow	05/01/2008	$	687	Transportation
Other	Various	48		Facilities
2008 Total		$	735

Internal Growth Projects

Our 2010 projects included the construction and expansion of pipeline systems and storage and terminal facilities. The following table summarizes our 2010, 2009 and 2008 projects (in millions):

Projects	2010		2009		2008
PNGS (1) (2)	$	85	$	26	$	—
Cushing - Phases VII and VIII	25		25		—
Cushing - Phases IX through XI (1)	21		—		—
St. James - Phases I through IV (1)	21		73		44
Patoka tankage - Phases I through III	20		22		56
Edmonton land	17		—		—
West Texas gathering lines	15		—		—
Pier 400 (1)	11		18		10
Wichita Falls tanks	9		—		—
Nipisi storage and truck terminal	6		18		—
Kerrobert pumping project	1		33		9
Rangeland tankage	—		36		12
Paulsboro tankage	—		11		30
Salt Lake City expansion	—		8		154
Fort Laramie tank expansion	—		2		20
Other projects (3)	124		92		156
Total	$	355	$	364	$	491

(1) These projects will continue into 2011. See “—Liquidity and Capital Resources—Capital Expenditures and Distributions Paid to Our Unitholders, General Partner and Noncontrolling Interests—2011 Capital Expansion Projects.”

(2) Expenditures shown for 2009 for PNGS include only those expenditures made subsequent to the acquisition in September 2009 of the remaining 50% interest in PNGS.

(3) Primarily consists of pipeline connections, upgrades and truck stations, and new tank construction and refurbishing.

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Critical Accounting Policies and Estimates

Critical Accounting Policies

We have adopted various accounting policies to prepare our consolidated financial statements in accordance with generally accepted accounting principles in the United States (“GAAP”). These critical accounting policies are discussed in Note 2 to our Consolidated Financial Statements.

Critical Accounting Estimates

The preparation of financial statements in conformity with GAAP and rules and regulations of the United States Securities and Exchange Commission (“SEC”) requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities, as well as the disclosure of contingent assets and liabilities, at the date of the financial statements. Such estimates and assumptions also affect the reported amounts of revenues and expenses during the reporting period. Although we believe these estimates are reasonable, actual results could differ from these estimates. On a regular basis, we evaluate our assumptions, judgments and estimates. We also discuss our critical accounting policies and estimates with the Audit Committee of the Board of Directors.

We believe that the assumptions, judgments and estimates involved in the accounting for our (i) purchase and sales accruals, (ii) fair value of assets and liabilities acquired and identification of associated goodwill and intangible assets, (iii) fair value of derivatives, (iv) accruals and contingent liabilities, including our equity compensation plan accruals, (v) property and equipment and depreciation expense and (vi) allowance for doubtful accounts have the greatest potential impact on our consolidated financial statements. These areas are key components of our results of operations and are based on complex rules which require us to make judgments and estimates, so we consider these to be our critical accounting policies. Such critical accounting estimates are discussed further as follows:

Purchase and Sales Accruals. We routinely make accruals based on estimates for certain components of our revenues and cost of sales due to the timing of compiling billing information, receiving third-party information and reconciling our records with those of third parties. Where applicable, these accruals are based on nominated volumes expected to be purchased, transported and subsequently sold. Uncertainties involved in these estimates include levels of production at the wellhead, access to certain qualities of crude oil, pipeline capacities and delivery times, utilization of truck fleets to transport volumes to their destinations, weather, market conditions and other forces beyond our control. These estimates are generally associated with a portion of the last month of each reporting period. For the year ended December 31, 2010, we estimate that approximately 3% of both annual revenues and cost of sales were recorded using purchase and sales estimates. Accordingly, a 10% variance from this estimate would impact annual revenues, cost of sales, operating income and net income attributable to Plains line items by approximately 1% or less on an annual basis. Although the resolution of these uncertainties has not historically had a material impact on our reported results of operations or financial condition, because of the high volume, low margin nature of our business, we cannot provide assurance that actual amounts will not vary significantly from estimated amounts. Variances from estimates are reflected in the period actual results become known, typically in the month following the estimate.

Fair Value of Assets and Liabilities Acquired and Identification of Associated Goodwill and Intangible Assets. In accordance with Financial Accounting Standards Board (“FASB”) guidance regarding business combinations, with each acquisition, we allocate the cost of the acquired entity to the assets and liabilities assumed based on their estimated fair values at the date of acquisition. If the initial accounting for the business combination is incomplete when the combination occurs, an estimate will be recorded. Any subsequent adjustments to this estimate, if material, will be recognized retroactive to the date of acquisition. With exception to our equity method investments, we also expense the transaction costs as incurred in connection with each acquisition. In addition, we are required to recognize intangible assets separately from goodwill. Intangible assets with finite lives are amortized over their estimated useful life as determined by management. Goodwill and intangible assets with indefinite lives are not amortized but instead are periodically assessed for impairment.

Impairment testing entails estimating future net cash flows relating to the asset, based on management’s estimate of future revenues, future cash flows and market conditions including pricing, demand, competition, operating costs and other factors. Determining the fair value of assets and liabilities acquired, as well as intangible assets that relate to such items as customer relationships, contracts, and industry expertise, involves professional judgment and is ultimately based on acquisition models and management’s assessment of the value of the assets acquired and, to the extent available, third party

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assessments. Uncertainties associated with these estimates include changes in production decline rates, production interruptions, fluctuations in refinery capacity or product slates, economic obsolescence factors in the area and potential future sources of cash flow. Although the resolution of these uncertainties has not historically had a material impact on our results of operations or financial condition, we cannot provide assurance that actual amounts will not vary significantly from estimated amounts. We perform our goodwill impairment test annually (as of June 30) and when events or changes in circumstances indicate that the carrying value may not be recoverable.

We also compare our market capitalization to our book equity on a quarterly basis, to determine if there may be an indicator of impairment. As of December 31, 2010, our market capitalization exceeded the book value of our equity; therefore, since there were no events or changes in circumstances indicating impairment issues, we determined that it was not necessary to perform our goodwill impairment test as of December 31, 2010. We will continue to monitor the market and any changes in circumstances to determine if a triggering event occurs and will perform a goodwill impairment analysis if deemed necessary. We did not have any goodwill impairments in 2010, 2009 or 2008. See Note 2 to our Consolidated Financial Statements for a further discussion of goodwill.

Fair Value of Derivatives. Our derivatives are reported at fair value as either assets or liabilities with changes in fair value recognized in either earnings or accumulated other comprehensive income (“AOCI”). The fair value of a derivative at a particular period end does not reflect the end results of a particular transaction, and will most likely not reflect the realized gain or loss at the conclusion of a transaction. We reflect estimates for these items based on our internal records and information from third parties. For our derivatives that are not exchange traded, the estimates we use are based on indicative broker quotations or an internal valuation model. Our valuation models utilize market observable inputs such as price, volatility, correlation and other factors and may not be reflective of the price at which they can be settled due to the lack of a liquid market. Less than 1% of total annual revenues are based on estimates derived from internal valuation models. Although the resolution of these uncertainties has not historically had a material impact on our results of operations or financial condition, we cannot provide assurance that actual amounts will not vary significantly from estimated amounts.

Accruals and Contingent Liabilities. We record accruals or liabilities including, but not limited to, environmental remediation and governmental penalties, asset retirement obligations, equity compensation plan accruals (as further discussed below) and potential legal claims. Accruals are made when our assessment indicates that it is probable that a liability has occurred and the amount of liability can be reasonably estimated. Our estimates are based on all known facts at the time 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 environmental 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. Our estimates for contingent liability accruals are increased or decreased as additional information is obtained or resolution is achieved. A variance of 5% in our aggregate estimate for the accruals and contingent liabilities discussed above would have an impact on earnings of up to approximately $12 million. Although the resolution of these uncertainties has not historically had a material impact on our results of operations or financial condition, we cannot provide assurance that actual amounts will not vary significantly from estimated amounts.

Equity Compensation Plan Accruals. We accrue compensation expense for outstanding equity compensation awards. Under GAAP, we are required to estimate the fair value of our outstanding equity awards and recognize that fair value as compensation expense over the service period. For equity awards that contain a performance condition, the fair value of the equity award is recognized as compensation expense only if the attainment of the performance condition is considered probable. Uncertainties involved in this estimate include the actual unit price at time of vesting, whether or not a performance condition will be attained and the continued employment of personnel with outstanding equity awards.

We recognized total compensation expense of approximately $98 million, $68 million and $24 million in 2010, 2009 and 2008, respectively, related to equity awards granted under our various equity compensation plans. We cannot provide assurance that the actual fair value of our equity compensation awards will not vary significantly from estimated amounts. See Note 10 to our Consolidated Financial Statements.

Property and Equipment and Depreciation Expense. We compute depreciation using the straight-line method based on estimated useful lives. These estimates are based on various factors including condition, manufacturing specifications, technological advances and historical data concerning useful lives of similar assets. Uncertainties that impact these estimates include changes in laws and regulations relating to restoration and abandonment requirements, economic conditions and supply and demand in the area. When assets are put into service, we make estimates with respect to useful lives and salvage values that we believe are reasonable. However, subsequent events could cause us to change our estimates, thus impacting the future calculation of depreciation and amortization. During 2010, we conducted a review to assess the useful lives of our property and equipment. See Note 2 to our Consolidated Financial Statements.

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We periodically evaluate property and equipment for impairment when events or circumstances indicate that the carrying value of these assets may not be recoverable. The evaluation is highly dependent on the underlying assumptions of related cash flows. We consider the fair value estimate used to calculate impairment of property and equipment a critical accounting estimate. In determining the existence of an impairment of carrying value, we make a number of subjective assumptions as to:

· whether there is an event or circumstance that may be indicative of an impairment;

· the grouping of assets;

· the intention of “holding” versus “selling” an asset;

· the forecast of undiscounted expected future cash flow over the asset’s estimated useful life; and

· if an impairment exists, the fair value of the asset or asset group.

During 2010, we recognized impairments of approximately $13 million for assets taken out of service. Impairments of less than $1 million and approximately $5 million were recognized during 2009 and 2008, respectively, and were predominantly related to assets that were taken out of service. These assets did not support spending the capital necessary to continue service and we utilized other assets to handle these activities.

Allowance for Doubtful Accounts. We perform credit evaluations of our customers and grant credit based on past payment history, financial conditions and anticipated industry conditions. Customer payments are regularly monitored and a provision for doubtful accounts is established based on specific situations and overall industry conditions. Our history of bad debt losses has been minimal and generally limited to specific customer circumstances; however, credit risks can change suddenly and without notice. See Note 2 to our Consolidated Financial Statements for additional discussion.

Recent Accounting Pronouncements

See Note 2 to our Consolidated Financial Statements for information regarding the effect of recent accounting pronouncements on our financial statements.

Results of Operations

Analysis of Operating Segments

We manage our operations through three operating segments: (i) Transportation, (ii) Facilities and (iii) Supply and Logistics. Our Chief Operating Decision Maker (our Chief Executive Officer) evaluates such segment performance based on a variety of measures including segment profit, segment volumes, segment profit per barrel and maintenance capital investment. See Note 15 to our Consolidated Financial Statements for a definition of segment profit (including an explanation of why this is a performance measure) and a reconciliation of segment profit to net income attributable to Plains.

Our segment analysis involves an element of judgment relating to the allocations between segments. In connection with its operations, the supply and logistics segment secures transportation and facilities services from the Partnership’s other two segments as well as third-party service providers under month-to-month and multi-year arrangements. Intersegment transportation service rates are conducted at posted tariff rates, rates similar to those charged to third parties or rates that we believe approximate market rates. Facilities segment services are also obtained at rates generally consistent with rates charged to third parties for similar services; however, certain terminalling and storage rates 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. Intersegment activities are eliminated in consolidation and we believe that the estimates with respect to these rates are reasonable. Also, our segment operating and general and administrative expenses reflect direct costs attributable to each segment; however, we also allocate certain operating expense and general and administrative overhead expenses between segments based on management’s assessment of the business activities for the period. The proportional allocations by segment require judgment by management and may be adjusted in the future based on the business activities that exist during each period. We believe that the estimates with respect to these allocations are reasonable.

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Non-GAAP Financial Measures

To supplement our financial information presented in accordance with GAAP, management uses additional measures that are known as “non-GAAP financial measures” in its evaluation of past performance and prospects for the future. The primary measures used by management are adjusted earnings before interest, taxes, depreciation and amortization (“adjusted EBITDA”) and distributable cash flow (“DCF”).

Management believes that the presentation of such additional financial measures provides useful information to investors regarding our performance and results of operations because these measures, when used in conjunction with related GAAP financial measures, (i) provide additional information about our core operating performance and ability to generate and distribute cash flow, (ii) provide investors with the financial analytical framework upon which management bases financial, operational, compensation and planning decisions and (iii) present measurements that investors, rating agencies and debt holders have indicated are useful in assessing us and our results of operations. These measures may exclude, for example, (i) charges for obligations that are expected to be settled with the issuance of equity instruments, (ii) the mark-to-market of derivative instruments that are related to underlying activities in another period (or the reversal of such adjustments from a prior period), (iii) items that are not indicative of our core operating results and business outlook and/or (iv) other items that we believe should be excluded in understanding our core operating performance. We have defined all such items hereinafter as “Selected Items Impacting Comparability.” These additional financial measures are reconciled from the most directly comparable measures as reported in accordance within GAAP, and should be viewed in addition to, and not in lieu of, our consolidated financial statements and footnotes.

The following table sets forth an overview of our consolidated financial results calculated in accordance with GAAP:

	For the Twelve Months									Favorable/(Unfavorable)
	Ended December 31,									2010-2009					2009-2008
	2010			2009			2008			$			%		$			%
	(In millions, except per unit data)
Transportation segment profit	$	516		$	477		$	445		$	39		8	%	$	32		7	%
Facilities segment profit	270			208			153			62			30	%	55			36	%
Supply & Logistics segment profit	240			345			221			(105		)	(30	)%	124			56	%
Total segment profit	1,026			1,030			819			(4		)	(0	)%	211			26	%
Depreciation and amortization	(256		)	(236		)	(211		)	(20		)	(8	)%	(25		)	(12	)%
Interest expense	(248		)	(224		)	(196		)	(24		)	(11	)%	(28		)	(14	)%
Other income/(expense), net	(9		)	16			33			(25		)	(156	)%	(17		)	(52	)%
Income tax benefit/(expense)	1			(6		)	(8		)	7			117	%	2			25	%
Net income	514			580			437			(66		)	(11	)%	143			33	%
Less: Net income attributable to noncontrolling interests	(9		)	(1		)	—			(8		)	(800	)%	(1		)	N/A
Net income attributable to Plains	$	505		$	579		$	437		$	(74	)	(13	)%	$	142		32	%

Net income attributable to Plains:
Earnings per basic limited partner unit	$	2.41		$	3.34		$	2.66		$	(0.93	)	(28	)%	$	0.68		26	%
Earnings per diluted limited partner unit	$	2.40		$	3.32		$	2.64		$	(0.92	)	(28	)%	$	0.68		26	%
Basic weighted average units outstanding	137			130			120			7			5	%	10			8	%
Diluted weighted average units outstanding	138			131			121			7			5	%	10			8	%

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The following table sets forth additional non-GAAP financial measures that are reconciled from the most directly comparable measures as reported in accordance with GAAP:

	For the Twelve Months									Favorable/(Unfavorable)
	Ended December 31,									2010-2009					2009-2008
	2010			2009			2008			$			%		$			%
	(In millions, except per unit data)
Net income	$	514		$	580		$	437		$	(66	)	(11	)%	$	143		33	%
Add:
Depreciation and amortization	256			236			211			(20		)	(8	)%	(25		)	(12	)%
Income tax (benefit)/expense	(1		)	6			8			7			117	%	2			25	%
Interest expense	248			224			196			(24		)	(11	)%	(28		)	(14	)%
EBITDA	$	1,017		$	1,046		$	852		$	(29	)	(3	)%	$	194		23	%

Selected Items Impacting Comparability - Income/(Loss):
Inventory valuation adjustments net of gains/(losses) from related derivative activities (1)	$	—		$	24		$	(11	)	$	(24	)	(100	)%	$	35		318	%
Gains/(losses) from other derivative activities (1)	(14		)	34			7			(48		)	(141	)%	27			(386	)%
Equity compensation expense (2)	(67		)	(50		)	(21		)	(17		)	34	%	(29		)	(138	)%
Gains on Rainbow acquisition-related foreign currency and linefill hedges (3)	—			—			11			—			0	%	(11		)	100	%
Net gain/(loss) on foreign currency revaluation (4)	—			12			(21		)	(12		)	(100	)%	33			157	%
Other(5)	(8		)	4			—			(12		)	(300	)%	4			0	%
Selected Items Impacting Comparability	$	(89	)	$	24		$	(35	)	$	(113	)	(471	)%	$	59		169	%

EBITDA	$	1,017		$	1,046		$	852		$	(29	)	(3	)%	$	194		23	%
Selected Items Impacting Comparability	89			(24		)	35			113			471	%	(59		)	(169	)%
Adjusted EBITDA	$	1,106		$	1,022		$	887		$	84		8	%	$	135		15	%

Adjusted EBITDA	$	1,106		$	1,022		$	887		$	84		8	%	$	135		15	%
Interest expense	(248		)	(224		)	(196		)	(24		)	(11	)%	(28		)	(14	)%
Maintenance capital	(93		)	(81		)	(81		)	(12		)	(15	)%	—			0	%
Current income tax (expense)/benefit	1			(15		)	(9		)	16			107	%	(6		)	(67	)%
Equity earnings in unconsolidated entities, net of distributions	6			(8		)	(4		)	14			175	%	(4		)	(100	)%
Distributions to noncontrolling interests (6)	(15		)	(2		)	—			(13		)	(650	)%	(2		)	N/A
DCF	$	757		$	692		$	597		$	65		9	%	$	95		(16	)%

(1) Includes mark-to-market gains and losses resulting from derivative instruments that are related to underlying activities in future periods or the reversal of mark-to-market gains and losses from the prior period. When applicable, inventory valuation adjustments are presented with related derivative activity. See Note 6 to our Consolidated Financial Statements for a comprehensive discussion regarding our derivatives and hedging activities.

(2) Our total equity compensation expense includes expense associated with awards that will or may be settled in units and awards that will or may be settled in cash. The awards that will or may be settled in units are included in our diluted earnings per unit calculation when the applicable performance criteria have been met. We consider the compensation expense associated with these awards as a selected item impacting comparability as the dilutive impact of the outstanding awards are included in our diluted earnings per unit calculation and the majority of the awards are expected to be settled in units. The compensation expense associated with these awards is shown in the table above. The portion of compensation expense associated with awards that are certain to be settled in cash are not considered a selected item impacting comparability. The equity compensation expense attributable to the awards not considered a selected item impacting comparability is approximately $31 million, $18 million and $3 million for the twelve-month periods ended December 31, 2010, 2009 and 2008, respectively. See Note 10 to our Consolidated Financial Statements for a comprehensive discussion regarding our Equity Compensation Plans.

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(3) Represents a gain on the foreign currency hedge and commodity price risk hedge that we entered into in connection with the Rainbow acquisition. We classified this gain as a selected item impacting comparability as it was specific to this acquisition and not indicative of our core operating activities. See Note 3 to our Consolidated Financial Statements for further discussion regarding the Rainbow acquisition.

(4) During 2009 and 2008, there were significant fluctuations in the value of the Canadian dollar (“CAD”) to the U.S. dollar (“USD”), resulting in gains and losses that were not related to our core operating results of such periods and were thus classified as selected items impacting comparability. See Note 6 to our Consolidated Financial Statements for further discussion regarding our currency exchange rate risk hedging activities.

(5) Other includes (i) a net loss on the early repayment of senior notes of $6 million and $4 million for 2010 and 2009, respectively, (ii) PNGS contingent consideration fair value adjustment of $2 million and $1 million for 2010 and 2009, respectively and (iii) a net gain on the purchase of the remaining 50% interest in PNGS of $9 million in 2009.

(6) Includes distributions that pertain to the current quarter’s net income and are to be paid in the subsequent quarter.

Transportation Segment

The following table sets forth our operating results from our transportation segment for the periods indicated:

											Favorable/(Unfavorable)
Operating Results (1)	Year Ended December 31,									2010-2009						2009-2008
(in millions, except per barrel amounts)	2010			2009			2008			$				%		$			%
Revenues (1)
Tariff activities	$	937		$	867		$	800		$		70		8	%	$	67		8	%
Trucking	108			94			127			14				15	%	(33		)	(26	)%
Total transportation revenues	1,045			961			927			84				9	%	34			4	%
Cost and Expenses (1)
Trucking costs	(73		)	(63		)	(88		)	(10			)	(16	)%	25			28	%
Field operating costs (excluding equity compensation expense)	(346		)	(333		)	(331		)	(13			)	(4	)%	(2		)	(1	)%
Equity compensation expense - operations (2)	(12		)	(9		)	(1		)	(3			)	(33	)%	(8		)	(800	)%
Segment general and administrative expenses (excluding equity compensation expense)	(65		)	(61		)	(56		)	(4			)	(7	)%	(5		)	(9	)%
Equity compensation expense - general and administrative (2)	(36		)	(25		)	(11		)	(11			)	(44	)%	(14		)	(127	)%
Equity earnings in unconsolidated entities	3			7			5			(4			)	(57	)%	2			40	%
Segment profit	$	516		$	477		$	445		$		39		8	%	$	32		7	%
Maintenance capital	$	67		$	57		$	54		$		(10	)	(18	)%	$	(3	)	(6	)%
Segment profit per barrel	$	0.47		$	0.45		$	0.41		$		0.02		4	%	$	0.04		10	%

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				Favorable/(Unfavorable)
Average Daily Volumes	Year Ended December 31,			2010-2009				2009-2008
(in thousands of barrels per day) (3)	2010	2009	2008	Volumes		%		Volumes		%
Tariff activities
All American	39	40	45	(1	)	(3	)%	(5	)	(11	)%
Basin	378	394	377	(16	)	(4	)%	17		5	%
Capline	223	193	219	30		16	%	(26	)	(12	)%
Line 63/Line 2000	109	131	147	(22	)	(17	)%	(16	)	(11	)%
Salt Lake City Area Systems	135	131	93	4		3	%	38		41	%
Permian Basin Area Systems	371	368	372	3		1	%	(4	)	(1	)%
Manito	61	63	70	(2	)	(3	)%	(7	)	(10	)%
Rainbow	187	183	129	4		2	%	54		42	%
Rangeland	52	53	58	(1	)	(2	)%	(5	)	(9	)%
Refined products	116	100	109	16		16	%	(9	)	(8	)%
Other	1,218	1,180	1,232	38		3	%	(52	)	(4	)%
Tariff activities total	2,889	2,836	2,851	53		2	%	(15	)	(1	)%
Trucking	97	85	97	12		14	%	(12	)	(12	)%
Transportation segment total	2,986	2,921	2,948	65		2	%	(27	)	(1	)%

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

(2) The equity compensation expense presented within the reconciliation to segment profit above includes the portion of the equity compensation expense represented by outstanding awards under the LTIP Plans that, pursuant to the terms of the award, will be settled in cash only and have no impact on diluted units. The equity compensation expense presented within the “Selected Items Impacting Comparability” section of the table as shown within the “Results of Operations-Non-GAAP Financial Measures” discussion above excludes this portion of the equity compensation expense. See Note 10 to our Consolidated Financial Statements for additional discussion regarding our equity compensation plans.

(3) Volumes associated with acquisitions represent total volumes for the number of days we actually owned the assets divided by the number of days in the period.

Tariffs and other fees on our pipeline systems vary by receipt point and delivery point. The segment profit generated by our tariff and other fee-related activities depends on the volumes transported on the pipeline and the level of the tariff and other fees charged as well as the fixed and variable field costs of operating the pipeline. Segment profit from our pipeline capacity leases generally reflects a negotiated amount.

Transportation segment profit and segment profit per barrel were impacted by the following for the periods indicated:

Operating Revenues and Volumes. As noted in the table above, our total transportation segment revenues, net of trucking costs, increased year-over-year for each comparative period presented. Our volumes increased during 2010 compared to 2009 and declined slightly during 2009 compared to 2008. The most noteworthy favorable volume variance for 2010 compared to 2009 is primarily the increase of volumes on our Capline pipeline system that resulted from the additional 21% undivided joint interest that we purchased in this pipeline system during December 2009. Volumes were further favorably impacted by increased trucking volumes related to increased short-haul shipments and the addition of a heavy oil truck terminal at Nipisi, Alberta.

Revenues, net of trucking costs, for the years ended December 31, 2010, 2009 and 2008 were positively impacted by the net effect of a number of factors including:

· Foreign Exchange Impact — Revenues and expenses from our Canadian based subsidiaries, which use the Canadian dollar as their functional currency, are translated at the prevailing average exchange rates for each month. The average CAD to USD exchange rates for 2010, 2009 and 2008 were $1.03 CAD: $1.00 USD, $1.14 CAD: $1.00 USD and $1.07 CAD: $1.00 USD, respectively. Therefore, revenues from our Canadian pipeline systems and trucking operations were favorably impacted for 2010 compared to 2009 by approximately $24 million due to the appreciation of the Canadian dollar relative to the U.S. dollar. In turn, such revenues for 2009 compared to 2008 were unfavorably impacted by approximately $11 million due to the depreciation of the Canadian dollar relative to the U.S. dollar.

· Rate Increases — Revenues were favorably impacted by increasing tariff rates on our intrastate and Canadian pipelines as well as on our pipelines regulated by the Federal Energy Regulatory Commission.

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· Loss Allowance Revenue — As is common in the industry, our tariffs incorporate a loss allowance factor that is intended to, among other things, offset losses due to evaporation, measurement and other losses in transit. We value the variance of allowance volumes to actual losses at the estimated net realizable value (including the impact of gains and losses from derivative-related activities) at the time the variance occurred and the result is recorded as either an increase or decrease to tariff revenues. Loss allowance revenues increased by approximately $9 million for 2010 compared to 2009 and $22 million for 2009 compared to 2008. These increases were primarily due to a higher average realized price per barrel during each of the comparative periods (including the impact of gains from derivative activities).

· Trucking Business Activity — Trucking revenues, net of costs, increased by approximately $4 million for 2010 compared to 2009 primarily due to volume increases from increased short-haul shipments and the addition of a heavy oil truck terminal at Nipisi, Alberta during December 2009, partially offset by higher fuel costs. In contrast, trucking revenues, net of costs, decreased by approximately $8 million for 2009 compared to 2008 primarily due to volume decreases resulting from decreased demand, as well as an effort to eliminate lower margin activities. Such unfavorable variances were partially offset by lower fuel costs.

· Rainbow Acquisition — The Rainbow acquisition, completed in May 2008, contributed approximately $16 million of incremental revenue to 2009 compared to 2008.

· Salt Lake City Area Expansion — During the fourth quarter of 2008, we completed a 94-mile expansion of our Salt Lake Area system. Incremental revenues from completion of the Salt Lake City Area expansion added approximately $7 million to revenues in 2009 relative to 2008 associated with volume increases.

Costs and Expenses. In general, our overall transportation costs and expenses have remained relatively consistent on a per barrel basis during 2010, 2009 and 2008. Included in these results are the impacts of foreign exchange rates, which had an unfavorable impact of approximately $10 million in 2010 as compared to 2009 and a favorable impact of approximately $5 million in 2009 as compared to 2008. In addition, our equity compensation expense increased in 2010 compared to 2009. A significant component of this increase is associated with the determination that a PAA distribution level of $4.00 per limited partner (“LP”) unit is probable of occurring. A majority of our equity compensation awards contain performance conditions contingent upon achieving certain distribution levels. For awards with performance conditions (such as distribution targets), expense is accrued over the service period only if the performance condition is considered to be probable of occurring. When awards with performance conditions that were previously considered improbable become probable (such as a $4.00 distribution per LP unit becoming probable), we incur additional expense in the period that our probability assessment changes. This is necessary to bring the accrued liability associated with these awards up to the level it would be as if we had been accruing for these awards since the grant date. During 2009, equity compensation expense increased by $22 million as compared to 2008 primarily due to an increase in PAA unit price for 2009 relative to 2008. At the end of 2009, our unit price was $52.85 per common unit as compared to $34.69 per common unit at the end of 2008, which increases the fair value of our outstanding liability classified LTIPs. In addition to probability and price fluctuations, our equity compensation expense is impacted by additional equity compensation grants and forfeitures during each period (including the Class B grants and forfeitures). See Note 10 to our Consolidated Financial Statements for additional information on our equity compensation plans.

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· Maintenance Capital. Maintenance capital consists of capital investments for the replacement of partially or fully depreciated assets in order to maintain the service capability, level of production and/or functionality of our existing assets. The increase in maintenance capital in 2010 compared to 2009 is primarily due to increased spending on various pipeline integrity projects as well as timing of repairs between years.

Facilities Segment

The following table sets forth our operating results from our facilities segment for the periods indicated:

	For the Year Ended									Favorable/(Unfavorable)
Operating Results (1)	December 31,									2010-2009					2009-2008
(in millions, except per barrel amounts)	2010			2009			2008			$			%		$			%
Storage and terminalling revenues (1)	$	490		$	362		$	270		$	128		35	%	$	92		34	%
Storage related costs (natural gas related)	(23		)	(5		)	—			(18		)	(360	)%	(5		)	N/A
Field operating costs (excluding equity compensation expense)	(140		)	(120		)	(104		)	(20		)	(17	)%	(16		)	(15	)%
Equity compensation expense - operations (2)	(2		)	(1		)	—			(1		)	(100	)%	(1		)	N/A
Segment general and administrative expenses (excluding equity compensation expense)	(39		)	(26		)	(18		)	(13		)	(50	)%	(8		)	(44	)%
Equity compensation expense - general and administrative (2)	(16		)	(10		)	(4		)	(6		)	(60	)%	(6		)	(150	)%
Equity earnings in unconsolidated entities	—			8			9			(8		)	(100	)%	(1		)	(11	)%
Segment profit	$	270		$	208		$	153		$	62		30	%	$	55		36	%
Maintenance capital	$	17		$	16		$	23		$	(1	)	(6	)%	$	7		30	%
Segment profit per barrel	$	0.32		$	0.29		$	0.23		$	0.03		10	%	$	0.06		26	%

	For the Year Ended									Favorable/(Unfavorable)
	December 31,									2010-2009					2009-2008
Volumes (3) (4) (5)	2010			2009			2008			Volumes			%		Volumes			%
Crude oil, refined products and LPG storage (average monthly capacity in millions of barrels)	61			56			53			5			9	%	3			6	%
Natural gas storage (average monthly capacity in billions of cubic feet)	47			26			14			21			81	%	12			86	%
LPG processing (average throughput in thousands of barrels per day)	14			15			17			(1		)	(7	)%	(2		)	(12	)%
Facilities segment total (average monthly capacity in millions of barrels)	70			61			56			9			15	%	5			9	%

(1) Includes intersegment amounts.

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(3) Volumes associated with acquisitions represent total volumes for the number of months we actually owned the assets divided by the number of months in the period.

(4) In September 2009, we acquired the remaining 50% indirect interest in PNGS, which resulted in our 100% ownership of the natural gas storage business and related operating entities. Therefore, natural gas storage volumes for January 2008 through August 2009 are netted to our 50% interest in PNGS. Beginning in September 2009, volumes represent our 100% interest in PNGS. See Note 3 to our Consolidated Financial Statements for additional discussion regarding the PNGS acquisition.

(5) Facilities total calculated as the sum of: (i) crude oil, refined products and LPG storage capacity; (ii) natural gas capacity divided by 6 to account for the 6:1 mcf of gas to crude Btu equivalent ratio and further divided by 1,000 to convert to monthly volumes in millions; and (iii) LPG processing volumes multiplied by the number of days in the year and divided by the number of months in the year.

Facilities segment profit and segment profit per barrel were impacted by the following for the periods indicated:

Operating Revenues and Volumes. As noted in the table above, our facilities segment revenues (less storage related costs) and volumes increased year-over-year for each comparative year presented. Revenues and volumes for the comparative periods were positively impacted primarily by the net effect of factors discussed below:

· Acquisitions — Revenues and volumes for 2010 compared to 2009 were impacted by the PNGS acquisition, which closed during the third quarter of 2009. This acquisition and ongoing expansion activities at PNG contributed approximately $58 million of additional net revenue and approximately 22 billion cubic feet (“Bcf”) of additional natural gas storage capacity for the year ended December 31, 2010. This net revenue amount includes the applicable storage related costs that are primarily due to increased volume of leased assets. Revenues were also favorably impacted by the acquisition of a natural gas processing business, which closed during the second quarter of 2009. This acquisition contributed approximately $9 million in additional revenue for the year ended December 31, 2010.

Revenues and volumes for 2009 compared to 2008 were impacted by the PNGS acquisition and the acquisition of a natural gas processing business as mentioned above. Revenues and volumes for 2009 compared to 2008 were also impacted by the San Pedro acquisition, which closed during the fourth quarter of 2008. Such acquisitions contributed approximately $36 million in additional revenue for the year ended December 31, 2009.

· Expansion Projects — Expansion projects that were completed in phases throughout recent years also favorably impacted revenues and volumes. These expansion projects, which were completed at some of our major terminal locations, increased revenues by a combined $14 million for the year ended December 31, 2010 compared to the year ended December 31, 2009 and by a combined $31 million for the year ended December 31, 2009 compared to the year ended December 31, 2008. Aggregate volumes at these facilities increased by approximately 5 million barrels for 2010 compared to 2009 and by approximately 5 million barrels for 2009 compared to 2008.

· Leased Tankage — Revenues for the year ended December 31, 2010 and December 31, 2009 also increased as a result of general escalations on existing leases.

Costs and Expenses. In general, our overall facilities costs and expenses have remained relatively constant on a per barrel basis during 2010, 2009 and 2008. We have experienced a small increase in field operating costs and general and administrative costs on a per barrel basis and the absolute amount of expense has increased for 2010 compared to 2009 and 2009 compared to 2008 primarily due to (i) continued growth through additional tankage placed into service over the last few years at some of our major terminal locations and (ii) acquisitions such as the PNGS and natural gas processing acquisitions completed in the second and third quarters of 2009. Our equity compensation expense increased for the comparative periods presented. See a discussion regarding such increases within the Transportation Segment above. Also, see Note 10 to our Consolidated Financial Statements for additional information on our equity compensation plans.

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Equity Earnings in Unconsolidated Entities. Equity earnings in unconsolidated entities decreased during 2010 compared to 2009 due to the PNGS acquisition in September 2009 that increased our interest from 50% to 100%. See Note 3 to our Consolidated Financial Statements for additional discussion regarding this acquisition.

Maintenance Capital. The decrease in maintenance capital from 2009 compared to 2008 is primarily due to a decrease in API 653 repairs required to meet our May 2009 compliance deadline.

Supply and Logistics Segment

Our revenues from supply and logistics activities reflect the sale of gathered and bulk-purchased crude oil, refined products and LPG volumes. These revenues also include the sale of additional barrels exchanged through buy/sell arrangements entered into to supplement the margins of the gathered and bulk-purchased volumes. We do not anticipate that future changes in revenues will be a primary driver of segment profit. Generally, we expect our segment profit to increase or decrease directionally with increases or decreases in our supply and logistics segment volumes (which consist of (i) lease gathered crude oil purchase volumes, (ii) LPG sales volumes and (iii) waterborne foreign crude oil imported) as well as the overall volatility and strength or weakness of market conditions and the allocation of our assets among our various risk management strategies. In addition, the execution of our risk management strategies in conjunction with our assets can provide upside in certain markets. Although we believe that the combination of our lease gathered business and our risk management activities provides a balance that provides general stability in our margins, these margins are not fixed and will vary from period to period.

The following table sets forth our operating results from our supply and logistics segment for the periods indicated:

	For the Year Ended									Favorable/(Unfavorable)
Operating Results (1)	December 31,									2010-2009					2009-2008
(in millions, except per barrel amounts)	2010			2009			2008			Revenues			%		Revenues			%
Revenues	$	24,990		$	17,759		$	29,350		$	7,231		41	%	$	(11,591	)	(39	)%
Purchases and related costs (2)	(24,448		)	(17,141		)	(28,873		)	(7,307		)	(43	)%	11,732			41	%
Field operating costs (excluding equity compensation expense)	(195		)	(183		)	(185		)	(12		)	(7	)%	2			1	%
Equity compensation expense - operations (3)	(3		)	(1		)	—			(2		)	(200	)%	(1		)	N/A
Segment general and administrative expenses (excluding equity compensation expense)	(75		)	(67		)	(63		)	(8		)	(12	)%	(4		)	(6	)%
Equity compensation expense - general and administrative (3)	(29		)	(22		)	(8		)	(7		)	(32	)%	(14		)	(175	)%
Segment profit	$	240		$	345		$	221		$	(105	)	(30	)%	$	124		56	%
Maintenance capital	$	9		$	8		$	4		$	(1	)	(13	)%	$	(4	)	(100	)%
Segment profit per barrel	$	0.84		$	1.22		$	0.72		$	(0.38	)	(31	)%	$	0.50		69	%

	For the Year Ended									Favorable (Unfavorable)
Average Daily Volumes (4)	December 31,									2010-2009					2009-2008
(in thousands of barrels per day)	2010			2009			2008			Volume			%		Volume			%
Crude oil lease gathering purchases	620			612			658			8			1	%	(46		)	(7	)%
LPG sales	96			105			103			(9		)	(9	)%	2			2	%
Waterborne foreign crude oil imported	68			55			80			13			24	%	(25		)	(31	)%
Supply & Logistics segment total	784			772			841			12			2	%	(69		)	(8	)%

(1) Revenues and costs include intersegment amounts.

(2) Purchases and related costs include interest expense (related to hedged inventory purchases) of approximately $17 million, $11 million and $21 million for the years ended December 31, 2010, 2009 and 2008, respectively.

(3) The equity compensation expense presented within the reconciliation to segment profit above includes the portion of the equity compensation expense represented by outstanding awards under the LTIP Plans that, pursuant to the terms of the award,

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will be settled in cash only and have no impact on diluted units. The equity compensation expense presented within the “Selected Items Impacting Comparability” section of the table as shown within the “Results of Operations-Non-GAAP Financial Measures” discussion above excludes this portion of the equity compensation expense. See Note 10 to our Consolidated Financial Statements for additional discussion regarding our equity compensation plans.

(4) Calculated based on crude oil lease gathered volumes, LPG sales volumes and waterborne foreign crude oil imported volumes.

The New York Mercantile Exchange (“NYMEX”) benchmark price of crude oil ranged from approximately $64 to $92 per barrel, $33 to $82 per barrel and $32 to $147 per barrel during 2010, 2009 and 2008, respectively. Because the commodities that we buy and sell are generally indexed to the same pricing indices for both the purchase and sale, the absolute amount of revenues and costs related to purchases will fluctuate with market prices. However, the margins related to those purchases and sales will not necessarily have a corresponding increase or decrease.

Generally, we expect a base level of earnings from our supply and logistics segment that may be optimized and enhanced when there is a high level of market volatility, favorable basis differentials and/or a steep contango or backwardated market structure. A contango market is favorable to our commercial strategies that are associated with storage as it allows us to simultaneously purchase production at current prices for storage and sell at higher prices for future delivery. A backwardated market can have a positive impact on our lease gathering margins because crude oil gatherers can capture a premium for prompt deliveries. However, in a backwardated market, there is little incentive to store crude oil as current prices are above future delivery prices. Our supply and logistics segment operating results are further impacted by foreign currency translation adjustments as certain of our subsidiaries are based in Canada and use the Canadian dollar as their functional currency. Revenues and expenses are translated at average exchange rates prevailing for each month and comparison between periods may be impacted by changes in the average exchange rates. Also, our LPG marketing operations are weather-sensitive, particularly during the approximate five-month peak heating season of November through March, and temperature differences from year-to-year may have a significant effect on financial performance.

Operating Revenues and Volumes. Revenues, net of purchases and related costs, decreased by approximately $76 million or 12% in 2010 compared to 2009 despite our relatively consistent volumetric activity primarily due to (i) decreased LPG margins and (ii) our derivative activities. LPG margins for 2010 were negatively impacted by lower demand. In addition, 2009 margins were higher than expected due to the liquidation of lower valued inventory following a write-down of inventory values during 2008. As for our derivative activities, we recognized net mark-to-market losses of approximately $17 million during 2010. The 2010 period was also unfavorably impacted compared to 2009 by (i) less favorable crude oil quality differentials and (ii) a less favorable market structure. These unfavorable variances were partially offset by improved margins within our lease gathering activities.

Revenues, net of purchases and related costs, increased by approximately $141 million or 30% in 2009 compared to 2008. The primary reasons for the stronger performance in 2009 were (i) strong crude oil contango margins in the first four months of the year (during this period the contango market was as wide as $8.49 per barrel); (ii) strong LPG margins in the fourth quarter of the year due to strong crop drying demand in the quarter and colder than normal weather the latter half of the quarter; (iii) the negative impacts of Hurricanes Gustav and Ike in 2008; and (iv) derivative activities, net of inventory valuation adjustments, were a net gain of $62 million in 2009 compared to a net loss of $7 million in 2008. The derivative gains in 2009 are generally offset by future physical positions that are not included in the mark-to-market calculation for various reasons including that they qualify for the normal purchase and normal sale scope exception under FASB guidance. These items more than offset a lower net margin from our lease gathering activities, which was primarily due to lower volumes as we eliminated some of our less profitable purchases.

Field Operating Costs. Field operating costs (excluding equity compensation expenses) increased in 2010 compared to 2009 primarily due to an increase in truck-hauled lease volumes which resulted in increased driver commissions, transport fuel costs and third party trucking fees. Additionally, transport fuel costs were negatively impacted in 2010 by higher diesel fuel prices.

General and Administrative Expenses. General and administrative expenses (excluding equity compensation expenses as discussed below) increased in 2010 compared to 2009 and in 2009 compared to 2008 primarily due to increased salary and benefit costs consistent with the overall growth of the segment and changes in allocation methodology among segments.

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Equity Compensation Expense. Equity compensation expense increased for the comparative periods presented. See a discussion regarding such increases within the Transportation Segment above. Also, see Note 10 to our Consolidated Financial Statements for additional information on our equity compensation plans.

Maintenance Capital. The increase in maintenance capital for the year ended December 31, 2009 compared to the year ended December 31, 2008 is primarily due to truck and trailer fleet replacements and rebuilds.

Other Income and Expenses

Depreciation and Amortization

Depreciation and amortization expense was $256 million for the year ended December 31, 2010 compared to $236 million and $211 million for the years ended December 31, 2009 and 2008, respectively. The increases in 2010, 2009 and 2008 related primarily to an increased amount of depreciable assets stemming from our acquisition activities and internal growth projects. The increase in depreciation expense in 2010 was partially offset by a $23 million reduction related to the extension of the depreciable lives of several of our crude oil and other storage facilities and pipeline systems. The extension of depreciable lives is based on an internal review to assess the useful lives of our property and equipment and to adjust those lives, if appropriate, to reflect current expectations given actual experience and current technology. Amortization of debt issue costs was $7 million, $6 million and $4 million in 2010, 2009 and 2008, respectively.

Included in depreciation expense for the years ended December 31, 2010, 2009 and 2008 is a net loss of approximately $13 million, a net loss of approximately $1 million and a net gain of approximately $1 million, respectively, recognized upon disposition of certain inactive assets and impairments for assets taken out of service.

Interest Expense

Interest expense was $248 million for the year ended December 31, 2010, compared to $224 million and $196 million for the years ended December 31, 2009 and 2008, respectively. Interest expense is primarily impacted by:

· our weighted average debt balances;

· the level and maturity of fixed rate debt and interest rates associated therewith;

· market interest rates and our interest rate hedging activities on floating rate debt; and

· interest capitalized on capital projects.

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The following table summarizes the components impacting the interest expense variance for the years ended December 31, 2010 and 2009 (in millions, except for percentages):

	$			Average LIBOR Rate		Weighted Average Interest Rate (1)

Interest expense for the year ended December 31, 2008	$	196		2.7	%	5.9	%
Impact of retirement of senior notes (2)		(7	)
Impact of issuance of senior notes (3)	53
Impact of decreased borrowings under credit facilities (4)	(15		)
Impact of decreased capitalized interest	2
Other	(5		)
Interest expense for the year ended December 31, 2009	$	224		0.3	%	6.0	%
Impact of retirement of senior notes (5)	(21		)
Impact of issuance of senior notes (6)	48
Other	(3		)
Interest expense for the year ended December 31, 2010	$	248		0.3	%	5.3	%

(1) Excludes commitment and other fees.

(2) In August 2009, our outstanding $175 million 4.75% senior notes due 2009 matured and were paid. In October 2009, we redeemed our outstanding $250 million 7.13% senior notes due 2014.

(3) In April, July and September 2009 we completed the issuances of $350 million of 8.75% senior notes due 2019, $500 million of 4.25% senior notes due 2012 and $500 million of 5.75% senior notes due 2020, respectively. A fluctuating portion of the 4.25% senior notes due 2012 is utilized to fund hedged inventory and would be classified as short-term debt if such activities were funded through our credit facilities. Interest costs attributable to borrowings for inventory stored in a contango market are included in “Purchases and related costs” in our supply and logistics segment profits as we consider interest on these borrowings a direct cost to storing the inventory. The costs applicable to the portion of the $500 million of 4.25% senior notes that was recognized within purchases and related costs was approximately $4 million and $1 million for the years ended December 31, 2010 and 2009, respectively.

(4) The change primarily reflects varying borrowing requirements for inventory-related borrowings and other working capital items and changes in London Interbank Offered Rate (“LIBOR”). As further discussed below, we utilized a portion of our $500 million 4.25% senior notes due 2012 in 2009 to fund our hedged inventory requirements. Therefore, we were able to reduce our short-term debt borrowing since such activities were not solely funded on our credit facilities.

(5) In September 2010, we redeemed our outstanding $175 million 6.25% senior notes due 2015.

(6) In July 2010, we completed the issuance of $400 million of 3.95% senior notes due 2015.

Interest costs attributable to borrowings for inventory stored in a contango market are included in purchases and related costs in our supply and logistics segment profit as we consider interest on these borrowings a direct cost to storing the inventory. These borrowings are primarily under our senior secured hedged inventory facility. These costs were approximately $17 million, $11 million and $21 million for the years ended December 31, 2010, 2009 and 2008, respectively.

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Other Income, Net

Other income, net for the year ended December 31, 2010, primarily included (i) a loss of approximately $6 million recognized in connection with the early redemption of our $175 million 6.25% senior notes, (ii) the revaluation of contingent consideration related to our PNGS acquisition of approximately $2 million and (iii) a net loss of approximately $2 million related to the foreign currency revaluation of a CAD-denominated interest receivable associated with an intercompany note and the impact of related foreign currency hedges.

Other income, net for the year ended December 31, 2009, primarily included (i) a net gain of approximately $9 million recognized in connection with the PNGS acquisition (see Note 3 to our Consolidated Financial Statements for further discussion), (ii) a net gain of approximately $11 million related to the foreign currency revaluation of a CAD-denominated interest receivable associated with an intercompany note and the impact of related foreign currency hedges and (iii) a loss of approximately $4 million recognized in conjunction with the early redemption of our $250 million 7.13% senior notes.

Income Tax Expense

Our income tax expense/benefit decreased by $7 million from an expense of $6 million in 2009 to a benefit of $1 million in 2010. In the years prior to 2010, our Canadian operations were operated through a combination of corporate entities subject to Canadian federal and provincial taxes and a limited partnership which was treated as a flow-through entity for tax purposes. The fluctuations in income tax expense for each of the three years in the period ended December 31, 2010, has primarily been driven by the level of taxable earnings in our entities subject to Canadian federal and provincial taxes. We restructured our Canadian investment on January 1, 2011 and as of this date, all of our Canadian operations are conducted within corporate entities and are subject to Canadian federal and provincial taxes. As a result of this change, we expect that our income tax expense will increase in 2011 as compared to historical periods. See Note 7 to our Consolidated Financial Statements for further discussion.

Outlook

During 2008 and 2009, worldwide financial markets were extremely volatile and the global economy substantially weakened. The U.S. government and governments around the world took significant actions in response, including an attempt to provide liquidity and stability to the financial markets by providing government assistance to some of the largest financial institutions in the world. Although it appears that these collective actions have been successful in stabilizing the financial markets, we continue to maintain a cautious outlook for the overall economic environment. Certain data points observed in 2010 and recently signal improvements in the health of the economy have started to occur, while other data points indicate that we have yet to begin a sustainable recovery. For example, one indicator of the strength and velocity of the economy that also has an influence on our business is energy consumption. U.S. demand for petroleum has increased slightly from an average of 18.7 million barrels per day during 2009 to an average of 19.1 million barrels per day for the twelve months ended October 2010; however, it remains approximately 8% below the levels experienced during the 2005 to 2007 time period. Natural gas demand, which in 2009 had declined approximately 2% relative to 2008, has increased from an average of 62.6 Bcf per day in 2009 to an average of 64.9 Bcf per day for the twelve months ended October 2010.

Although we have seen a slight increase in U.S. energy consumption (i.e., demand), we believe the U.S. economy will remain relatively weak and that the pace of an economic recovery will be slow. We expect that the U.S. economy will ultimately rebound and energy demand will return to a growth profile; however, uncertainty around the timing of these events remains and the potential exists for further weakness in the economy or capital markets. Our business strategy is designed to manage a volatile environment and we believe that our asset base strategically positions us to benefit from certain of these developments.

On the supply side of our business, we are currently experiencing favorable fundamentals related to increasing crude oil production as well as changing crude oil flows, which has led to increased demand for our services across our operating segments. We believe that the continued development of major resource plays and the impact such production will have on the liquids distribution system will create additional opportunities for us to optimize the use of our existing assets as well as develop additional infrastructure to meet the needs of our customers.

There can be no assurance that these opportunities will come to fruition or that we will not be negatively affected by potential volatility or challenging capital markets conditions, or that our acquisition and expansion efforts will be successful. See Item 1A. “Risk Factors - Risks Related to Our Business.”

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Liquidity and Capital Resources

General

The primary sources of liquidity are our cash flow from operations as further discussed below in the section entitled “—Cash Flow from Operations” and borrowings under our credit facilities. Our primary cash requirements include, but are not limited to (i) ordinary course of business uses, such as the payment of amounts related to the purchase of crude oil and other products and other expenses, interest payments on our outstanding debt and distributions to our unitholders and General Partner, (ii) maintenance and expansion activities, (iii) acquisitions of assets or businesses and (iv) repayment of principal on our long-term debt. We generally expect to fund our short-term cash requirements through our primary sources of liquidity. In addition, we generally expect to fund our long-term needs, such as those resulting from expansion activities or acquisitions, through a variety of sources (either separately or in combination), which may include cash flows from operations, borrowings under our credit facilities, and/or the issuance of additional equity or debt securities. As of December 31, 2010, we had a working capital surplus of approximately $166 million, including cash and cash equivalents of $36 million and restricted cash of $20 million. We had approximately $877 million of liquidity available to meet our ongoing operational, investing and finance needs as of December 31, 2010 as noted below (in millions):

	As of December 31, 2010
Availability under PAA senior unsecured revolving credit facility	$	701
Availability under PAA senior secured hedged inventory facility	—
Availability under PNG senior unsecured revolving credit facility (1)	140
Cash and cash equivalents	36
Total	$	877

(1) In April 2010, PNG entered into a three year, $400 million senior unsecured revolving credit facility that matures in May 2013. Borrowing capacity under this facility may be limited from time to time due to covenant limitations. See Note 4 to our Consolidated Financial Statements for additional discussion of this credit facility and the “Noncontrolling Interests in a Subsidiary” section of Note 5 for additional discussion regarding PNG.

We entered into a number of transactions in the first quarter of 2011 that impacted our liquidity. In January 2011, we expanded our liquidity through a $600 million senior note offering and by entering into a $500 million 364-day senior unsecured credit facility (See “—Credit Facilities and Indentures” below). In addition, we redeemed our 7.75% senior notes that were maturing in 2012 for approximately $222 million. PNG also completed the $746 million acquisition of SG Resources Mississippi, LLC (“the Southern Pines Acquisition”) and issued approximately 17.4 million PNG common units to third parties for net proceeds of approximately $370 million (See Notes 3 and 5 of our Consolidated Financial Statements). The net impact of these transactions increased our liquidity by approximately $500 million. Giving effect to these transactions, our available liquidity as of December 31, 2010 of approximately $877 million would have increased to approximately $1.4 billion.

We believe that we have and will continue to have the ability to access our credit facilities, which we use to meet our short-term cash needs. We believe that our financial position remains strong and we have sufficient liquidity; however, extended disruptions in the financial markets and/or energy price volatility that adversely affect our business may have a materially adverse effect on our financial condition, results of operations or cash flows. Also, see Item 1A. “Risk Factors” for further discussion regarding such risks that may impact our liquidity and capital resources. Usage of the credit facilities is subject to ongoing compliance with covenants. We are currently in compliance with all covenants.

Congress recently enacted the Dodd-Frank Wall Street Reform and Consumer Protection Act (“Dodd-Frank Act”), which includes provisions regarding the use of derivative financial instruments. The scope and applicability of these provisions is not entirely clear and regulations implementing all the various aspects of the Dodd-Frank Act have not yet been issued. Our current assessment is that we may have additional documentation requirements. We will continue to monitor the final rules and regulations as they develop.

Cash Flow from Operations

The primary drivers of cash flow from our operations are (i) the collection of amounts related to the sale of crude oil and other products, the transportation of crude oil and other products for a fee, and storage and terminalling services provided for a fee and (ii) the payment of amounts related to the purchase of crude oil and other products and other expenses, principally field operating costs, general and administrative expenses and interest expense. The cash settlement from the purchase and sale of crude oil during any particular month typically occurs within thirty days from the end of the month, except (i) in the months that we store the purchased crude oil and hedge it by selling it forward for delivery in a subsequent month because of contango market conditions or (ii) in months in which we increase our share of linefill or long-term inventory. In addition, our cash flow from operations may be impacted by the timing of settlement of our derivative activities. Gains and losses from settled instruments that qualify as effective cash flow hedges are deferred in AOCI, but may impact operating cash flow in the period settled.

The storage of crude oil in periods of a contango market, when the price of crude oil for future deliveries is higher than current prices, can have a material impact on our cash flows from operating activities. In the month we pay for the stored crude oil, we borrow under our credit facilities (or pay from cash on hand) to pay for the crude oil, which negatively impacts our operating cash flow. Conversely, cash flow from operating activities increases during the period in which we collect the

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cash from the sale of the stored crude oil. Similarly, the level of LPG and other product inventory stored and held for resale at period end affects our cash flow from operating activities.

In periods when the market is not in contango, we typically sell our crude oil during the same month in which we purchase it and we do not rely on borrowings under our credit facilities to pay for the crude oil. During such market conditions, our accounts payable and accounts receivable generally move in tandem as we make payments and receive payments for the purchase and sale of crude oil in the same month, which is the month following such activity. In periods during which we build inventory or linefill, regardless of market structure, we may rely on our credit facilities to pay for the inventory or linefill.

Net cash flow provided by operating activities for the twelve months ended December 31, 2010 was approximately $259 million. The cash provided by operating activities reflects cash generated by our recurring operations, and is also significantly impacted in periods when we are increasing or decreasing the amount of inventory in storage as discussed above. During 2010, we increased the amount of our inventory. The increase in inventory was due to both increased volumes and prices and was primarily related to (i) our crude oil contango market storage activities and (ii) our LPG activities. The net increased levels of inventory were financed through borrowings under our credit facilities as well as through our $500 million senior notes that are being used to supplement capital available from our hedged inventory facility resulting in a negative impact to our operating cash flow for the period.

Net cash flows provided by operating activities for the twelve months ended December 31, 2009 and 2008 were approximately $365 million and $857 million, respectively. During 2009, we increased the amount of our inventory. The increase was due to both increased volumes and prices and was primarily related to our crude oil storage activities. The net increased levels of inventory were financed through borrowings under our credit facilities and senior notes issuances resulting in a negative impact to our operating cash flow for the period. During 2008, we also increased the amount of our inventory; however, these volumetric increases were offset by lower prices for our inventory stored at the end of the year compared to prior years. The net proceeds received during the year were used to repay borrowings under our credit facilities and favorably impacted our cash flow from operating activities.

Credit Facilities and Indentures

PAA Senior Unsecured Revolving Credit Facility. At December 31, 2010, we had approximately $701 million of available borrowing capacity under our $1.6 billion committed revolving credit facility. Of the capacity we utilized at December 31, 2010, approximately $75 million was associated with outstanding letters of credit and the remainder was borrowed. The majority of these borrowings relate to funding short term inventory purchases of LPG and crude oil. This credit facility has a maturity date of July 2012, contains no material adverse change language, and can be expanded to $2.0 billion, subject to additional lender commitments.

PAA Senior Secured Hedged Inventory Facility. In October 2010, we renewed our 364-day committed hedged inventory credit facility, which matures in October 2011. The facility has a borrowing capacity of $500 million, which may be increased to $1.2 billion, subject to obtaining additional lender commitments. This facility is a committed working capital facility, which is used to finance (i) the purchase of hedged crude oil inventory for storage activities and (ii) foreign import activities. Borrowings under the hedged inventory facility are collateralized by the inventory purchased under the facility and the associated accounts receivable, and will be repaid with the proceeds from the sale of such inventory. At December 31, 2010, we had no availability under our $500 million committed hedged inventory facility.

PNG Senior Unsecured Revolving Credit Facility. In April 2010, our consolidated subsidiary PNG entered into a three year, $400 million senior unsecured revolving credit facility that matures in May 2013. This credit facility, which bears interest based on LIBOR plus an applicable margin (as defined by the credit agreement), may be expanded to $600 million, subject to additional lender commitments and with approval of the administrative agent for the credit facility. At December 31, 2010, borrowings of approximately $260 million were outstanding under this facility. This credit facility restricts, among other things, PNG’s ability to make distributions of available cash to unitholders if any default or event of default, as defined in the credit agreement, exists or would result therefrom. In addition, the credit facility contains certain financial and other restrictive covenants.

PAA 364-Day Credit Agreement. In January 2011, we entered into a 364-day senior unsecured credit facility with

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an aggregate borrowing capacity of $500 million. This credit facility has a maximum debt coverage ratio of 4.75 to 1.00 (5.50 to 1.00 during an acquisition period) and matures in January 2012. Borrowings under this facility may be used for any partnership purpose, including financing the Southern Pines Acquisition. See Notes 3 and 5 to our Consolidated Financial Statements for discussion regarding this acquisition.

Indentures. In January 2011, we issued $600 million of 5.00% senior notes due 2021 for net proceeds of approximately $592 million. Including these notes, we have several issues of senior debt outstanding at December 31, 2010 that total approximately $5.0 billion, excluding premium or discount, and range in size from $150 million to $600 million and mature at various dates beginning in 2012 through 2037.

Our credit agreements and the indentures governing our senior notes contain cross-default provisions. A default under our credit facilities would permit the lenders to accelerate the maturity of the outstanding debt. As long as we are in compliance with the provisions in our credit agreements, our ability to make distributions of available cash is not restricted. We are currently in compliance with the covenants contained in our credit agreements and indentures. See Note 4 to our Consolidated Financial Statements for additional discussion regarding our credit facilities and long-term debt.

Equity and Debt Financing Activities

Our financing activities primarily relate to funding acquisitions and internal capital projects, and short-term working capital and hedged inventory borrowings related to our LPG business, contango market activities, foreign import activities as well as refinancing of our debt maturities. Our financing activities have primarily consisted of equity offerings, senior notes offerings and borrowings and repayments under our credit facilities.

Registration Statements. We periodically access the capital markets for both equity and debt financing. We have filed with the SEC a universal shelf registration statement that, subject to effectiveness at the time of use, allows us to issue up to an aggregate of $2.0 billion of debt or equity securities (“Traditional Shelf”). As of December 31, 2010, we have $2.0 billion of unsold securities available under the Traditional Shelf. We also have access to a universal shelf registration statement (“WKSI Shelf”), which provides us with the ability to offer and sell an unlimited amount of debt and equity securities, subject to market conditions and our capital needs. Our July 2010 offering of our $400 million senior notes due September 15, 2015 and our November 2010 equity offering for net proceeds of approximately $296 million were both conducted under the WKSI Shelf. Also, our more recent debt offering completed in January 2011 for net proceeds of approximately $592 million was also conducted under the WKSI Shelf.

PAA Equity Offerings. We completed equity offerings during 2010, 2009 and 2008 as summarized in the table below (net proceeds in millions). These offerings include our general partner’s proportionate capital contributions and are net of costs associated with the offerings.

Year	Units	Net Proceeds
2010	4,780,000	$	296
2009	11,040,000	$	456
2008	6,900,000	$	315

PNG Equity Offerings. On May 5, 2010, PNG completed its IPO of 13.5 million common units representing limited partner interests at $21.50 per common unit for total proceeds of approximately $268 million. PNG additionally completed a private placement of 17.4 million common units to third parties for net proceeds of approximately $370 million in conjunction with the Southern Pines Acquisition in February 2011. In addition, we purchased approximately 10.2 million PNG common units for approximately $230 million, including our proportionate general partner contribution of $12 million. As a result of these transactions, our aggregate ownership interest in PNG is approximately 64%. See Note 5 to our Consolidated Financial Statements.

Senior Notes. During the last three years we issued senior unsecured notes as summarized in the table below (in millions).

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Year	Description	Maturity	Face Value		Net Proceeds(1)
2011	5.00% Senior Notes issued at 99.521% of face value (2)	February 2021	$	600	$	597

2010	3.95% Senior Notes issued at 99.889% of face value (3)	September 2015	$	400	$	400

2009	5.75% Senior Notes issued at 99.523% of face value (4)	January 2020	$	500	$	499
	4.25% Senior Notes issued at 99.802% of face value	September 2012	$	500	$	497
	8.75% Senior Notes issued at 99.994% of face value	May 2019	$	350	$	350

2008	6.5% Senior Notes issued at 99.424% of face value	May 2018	$	600	$	597

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

(2) We used the net proceeds from this offering to repay outstanding borrowings under our credit facilities and for general partnership purposes. In addition, we used a portion of the proceeds to redeem all of our outstanding $200 million 7.75% senior notes due 2012 (in conjunction with the early redemption of these notes, we recognized a loss of $23 million).

(3) We used the net proceeds from this offering to repay outstanding borrowings under our credit facilities. In addition, we used a portion of the proceeds to redeem all of our outstanding $175 million 6.25% senior notes due 2015 (in conjunction with the early redemption of these notes, we recognized a loss of approximately $6 million).

(4) We used the net proceeds from this offering to repay outstanding borrowings under our credit facilities, a portion of which was used to fund the cash requirements of the PNGS acquisition (which included repayment of all of PNGS’s debt). In addition, we used a portion of the proceeds to redeem all of our outstanding $250 million 7.13% senior notes due 2014 (in conjunction with the early redemption of these notes, we recognized a loss of approximately $4 million).

In February, 2011, our $200 million 7.75% senior notes due 2012 were redeemed in full. In conjunction with the early redemption, we recognized a loss of approximately $23 million. We utilized cash on hand and available capacity under our credit facilities to redeem these notes.

In September 2010, we repaid our $175 million 6.25% senior notes and recognized a loss of approximately $6 million in conjunction with the early redemption of these notes. We utilized net proceeds from our July 2010 issuance of $400 million 3.95% senior notes to retire these senior notes.

In August 2009, our $175 million 4.75% senior notes matured. We utilized cash on hand and available capacity under our credit facilities to retire these senior notes.

Capital Expenditures and Distributions Paid to Our Unitholders, General Partner and Noncontrolling Interests

We use cash primarily for our acquisition activities, internal growth projects and distributions paid to our unitholders, general partner and noncontrolling interests. We have made and will continue to make capital expenditures for acquisitions, expansion capital and maintenance capital. Historically, we have financed these expenditures primarily with cash generated by operations and the financing activities discussed above. See “—Acquisitions and Internal Growth Projects” for further discussion for such capital expenditures.

Acquisitions. The price of the acquisitions includes cash paid, assumed liabilities and net working capital items. Because of the non-cash items included in the total price of the acquisition and the timing of certain cash payments, the net cash paid may differ significantly from the total price of the acquisitions completed during the year.

2011 Capital Expansion Projects. We expect the majority of funding for our 2011 capital program will be provided by revolver borrowings and cash flow in excess of partnership distributions as well as through our access to the capital markets for equity and debt as we deem necessary. Our 2011 capital expansion program includes the following projects with the estimated cost for the entire year (in millions):

Projects	2011
PAA Natural Gas Storage (multiple projects)	$	103
Cushing Terminal Phases IX - XI	62
Basile gas processing facility	36
Shafter Expansion	30
Stanley Rail Project	25
Bumstead Facility	21
Mid-Continent project	17
Nipisi Treater	17
Patoka Phase IV	17
Undisclosed	17
Sidney Propane Storage	13
Basin System expansion	11
Other projects (1)	181
Total Projected Capital Expansion Projects	$	550

(1) Primarily pipeline connections, upgrades and truck stations, new tank construction and refurbishing, and carry-over of projects started in 2010.

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Distributions to unitholders, general partner and noncontrolling interests. We distribute 100% of our available cash within 45 days after the end of each quarter to unitholders of record and to our general partner. Available cash is generally defined as all of our cash and cash equivalents on hand at the end of each quarter less reserves established in the discretion of our general partner for future requirements. On February 14, 2011, we paid a quarterly distribution of $0.9575 per limited partner unit. This distribution represented a year-over-year distribution increase of approximately 3.2%. Additionally, we have paid $10 million and $2 million for distributions to our noncontrolling interests for December 31, 2010 and 2009, respectively. See Note 5 to our Consolidated Financial Statements for details of distributions paid. Also, see Item 5. “Market for Registrant’s Common Units, Related Unitholder Matters and Issuer Purchases of Equity Securities—Cash Distribution Policy” for additional discussion on distribution thresholds.

Upon closing of the Pacific, Rainbow and PNGS acquisitions, our general partner agreed to reduce the amounts due it as incentive distributions. See Note 5 to our Consolidated Financial Statements for details related to the general partner’s incentive distribution reductions.

We believe that we have sufficient liquid assets, cash flow from operations and borrowing capacity under our credit agreements to meet our financial commitments, debt service obligations, contingencies and anticipated capital expenditures. We are subject to business and operational risks; however, that could adversely affect our cash flow. A material decrease in our cash flows would likely produce an adverse effect on our borrowing capacity.

Contingencies

For a discussion of contingencies that may impact us, see Note 11 to our Consolidated Financial Statements.

Commitments

Contractual Obligations. In the ordinary course of doing business, we purchase crude oil and LPG from third parties under contracts, the majority of which range in term from thirty-day evergreen to five years. We establish a margin for these purchases by entering into various types of physical and financial sale and exchange transactions through which we seek to maintain a position that is substantially balanced between purchases on the one hand and sales and future delivery obligations on the other. The table below includes purchase obligations related to these activities. Where applicable, the amounts presented represent the net obligations associated with buy/sell contracts and those subject to a net settlement arrangement with the counterparty. We do not expect to use a significant amount of internal capital to meet these obligations, as the obligations will be funded by corresponding sales to entities that we deem creditworthy.

The following table includes our best estimate of the amount and timing of these payments as well as others due under the specified contractual obligations as of December 31, 2010 (in millions):

											2016 and
	2011		2012		2013		2014		2015		Thereafter		Total
Long-term debt and interest payments (1)	$	274	$	963	$	740	$	214	$	754	$	4,398	$	7,343
Leases (2)	77		62		40		27		20		277		503
Other obligations (3)	69		66		29		4		3		46		217
Subtotal	420		1,091		809		245		777		4,721		8,063
Crude oil, refined products and LPG purchases (4)	4,070		383		278		227		182		132		5,272
Total	$	4,490	$	1,474	$	1,087	$	472	$	959	$	4,853	$	13,335

(1) Includes debt service payments, interest payments due on our senior notes and the commitment fee on our revolving credit facilities. Although there is an outstanding balance on our revolving credit facilities at December 31, 2010, we historically repay and borrow at varying amounts. As such, we have included only the maximum commitment fee (as if no amounts were outstanding on the facility) in the amounts above.

(2) Leases are primarily for (i) storage, (ii) rights-of-way, (iii) office rent, (iv) pipeline assets and (v) trucks used in our gathering activities.

(3) Excludes a non-current liability of less than $1 million related to derivative activity included in crude oil and LPG purchases.

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(4) Amounts are based on estimated volumes and market prices based on average activity during December 2010. The actual physical volume purchased and actual settlement prices will vary from the assumptions used in the table. Uncertainties involved in these estimates include levels of production at the wellhead, weather conditions, changes in market prices and other conditions beyond our control.

Letters of Credit. In connection with our crude oil supply and logistics activities, we provide certain suppliers with irrevocable standby letters of credit to secure our obligation for the purchase of crude oil. Our liabilities with respect to these purchase obligations are recorded in accounts payable on our balance sheet in the month the crude oil is purchased. Generally, these letters of credit are issued for periods of up to seventy days and are terminated upon completion of each transaction. At December 31, 2010 and 2009, we had outstanding letters of credit of approximately $75 million and $76 million, respectively. The change in the value of outstanding letters of credit is impacted primarily by the fluctuation of market prices and the timing of foreign cargo purchases.

Off-Balance Sheet Arrangements

We have no off-balance sheet arrangements as defined by Item 303 of Regulation S-K.

Investments in Unconsolidated Entities

We have invested in entities that are not consolidated in our financial statements. Certain of these entities are borrowers under credit facilities. We are neither a co-borrower nor a guarantor under any such facilities. We may elect at any time to make additional capital contributions to any of these entities. The following table sets forth selected information regarding these entities as of December 31, 2010 (unaudited, dollars in millions):

Entity	Type of Operation	Our Ownership Interest		Total Entity Assets		Total Cash and Restricted Cash		Total Entity Debt
Settoon Towing, LLC	Barge Transportation Services	50	%	$	103	$	—	$	59
White Cliffs Pipeline, LLC	Crude Oil Pipeline	34	%	$	302	$	5	$	—
Frontier Pipeline Company	Crude Oil Pipeline	22	%	$	28	$	4	$	—
Butte Pipe Line Company	Crude Oil Pipeline	22	%	$	14	$	2	$	—

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

We are exposed to various market risks, including volatility in (i) commodity prices for crude oil, refined products, natural gas and LPG, (ii) interest rates and (iii) currency exchange rates. Our policy is to use derivative instruments only for risk management purposes. We use various derivative instruments to manage such risks and, in certain circumstances, to realize incremental margin during volatile market conditions. Our risk management policies and procedures are designed to help ensure that our hedging activities address our risks by monitoring NYMEX, IntercontinentalExchange (“ICE”) and over-the-counter positions, as well as physical volumes, grades, locations, delivery schedules and storage capacity. 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 aspects of corporate risk management. Our risk management function also approves all new risk management strategies through a formal process. The following discussion addresses each category of risk.

Commodity Price Risk

We use derivative instruments to hedge our exposure to price fluctuations with respect to crude oil, refined products, natural gas and LPG in storage, and anticipated purchases and sales of these commodities. The derivative instruments utilized to manage our commodity price risk consist primarily of futures, options and swaps traded on the NYMEX and ICE and in over-the-counter transactions. Our policy is (i) to purchase only product for which we have a market, (ii) to structure our sales contracts so that price fluctuations do not materially affect our operating income and (iii) not to acquire and hold physical inventory, futures contracts or other derivatives products for the purpose of speculating on outright commodity price changes, as these activities could expose us to significant losses.

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Although we seek to maintain positions that are substantially balanced, we purchase crude oil, refined products and LPG from thousands of locations and may experience net unbalanced positions as a result of production, transportation and delivery variances as well as logistical issues associated with inclement weather conditions and other uncontrollable events. 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.

The fair value of our commodity derivatives and the change in fair value that would be expected from a 10% price increase or decrease is shown in the table below (in millions):

				Effect of 10%			Effect of 10%
	Fair Value			Price Increase			Price Decrease
Crude oil:
Futures contracts	$	(14	)	$	(107	)	$	107
Swaps and options contracts	(1		)	$	(12	)	$	14

LPG and other:
Futures contracts	(6		)	$	(2	)	$	2
Swaps and options contracts (1)	(25		)	$	(11	)	$	12
Total Fair Value	$	(46	)

(1) Amount includes a liability of approximately $2 million associated with LPG physical contracts not eligible for the normal purchase and normal sale scope exception under FASB guidance.

The fair value of our exchange-traded derivatives is based on quoted market prices obtained from the NYMEX or ICE. The fair value of our over-the-counter swaps and options contracts is estimated based on quoted prices from various sources such as independent reporting services, industry publications and brokers. The assumptions used in these estimates as well as the source for the estimates are maintained by the independent risk control function. See Note 6 to our Consolidated Financial Statements for further discussion. Price-risk sensitivities were calculated by assuming an across-the-board 10% increase or decrease in price regardless of term or historical relationships between the contractual price of the instruments and the underlying commodity price. In the event of an actual 10% change in near-term crude prices, the fair value of our derivative portfolio would typically change less than that shown in the table as changes in near-term prices are not typically mirrored in delivery months further out.

Interest Rate Risk

We use both fixed and variable rate debt, and are exposed to market risk due to the floating interest rates on our credit facilities. Therefore, from time to time we use interest rate derivatives to hedge interest rate risk associated with anticipated debt issuances and, in certain cases, outstanding debt instruments. All of our senior notes are fixed rate notes and thus not subject to market risk. The majority of our variable rate debt at December 31, 2010, approximately $1.9 billion (including $300 million of interest rate derivatives that swap fixed rate debt for floating), is short-term debt and is subject to interest rate re-sets, which range from a week to three months. The average interest rate of 1.4% is based upon rates in effect at December 31, 2010. The fair value of our interest rate derivatives is an unrealized gain of approximately $15 million as of December 31, 2010. A 10% increase in the forward LIBOR curve as of December 31, 2010 would result in a decrease of less than $1 million to the fair value of our interest rate derivatives. The carrying values of the variable rate instruments in our credit facilities approximate fair value primarily because interest rates fluctuate with prevailing market rates. See Note 6 to our Consolidated Financial Statements for a discussion of our interest rate risk hedging activities.

Currency Exchange Rate Risk

We use foreign currency derivatives to hedge foreign currency risk associated with our exposure to fluctuations in the USD-to-CAD exchange rate. Because a significant portion of our Canadian business is conducted in CAD and, at times, a portion of our debt is denominated in CAD, we use certain financial instruments to minimize the risks of unfavorable changes in exchange rates. These instruments include foreign currency exchange contracts, forwards and options. The fair value of these instruments is an unrealized gain of approximately $1 million as of December 31, 2010. A 10% increase in the exchange rate (CAD-to-USD) would result in an decrease of approximately $4 million to the fair value of our foreign currency derivatives. See Note 6 to our Consolidated Financial Statements for a discussion of our currency exchange rate risk hedging.

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Item 8. Financial Statements and Supplementary Data

See “Index to the Consolidated Financial Statements” on page F-1.

Item 9. Changes In and Disagreements With Accountants on Accounting and Financial Disclosure

None.

Item 9A. Controls and Procedures

Disclosure Controls and Procedures

We maintain written “disclosure controls and procedures,” which we refer to as our “DCP.” Our DCP is designed to ensure that (i) information required to be disclosed by us in reports that we file under the Securities Exchange Act of 1934 (the “Exchange Act”) is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and (ii) such information is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, to allow for timely decisions regarding required disclosure.

Applicable SEC rules require an evaluation of the effectiveness of the design and operation of our DCP. Management, under the supervision and with the participation of our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the design and operation of our DCP as of the end of the period covered by this report, and has found our DCP to be effective in providing reasonable assurance of the timely recording, processing, summarization and reporting of information, and in accumulation and communication of information to management to allow for timely decisions with regard to required disclosure.

Internal Control over Financial Reporting

Management is responsible for establishing and maintaining adequate internal control over financial reporting. “Internal control over financial reporting” is a process designed by, or under the supervision of, our Chief Executive Officer and our Chief Financial Officer, and effected by our Board of Directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP. Our management, including our Chief Executive Officer and our Chief Financial Officer, has evaluated the effectiveness of our internal control over financial reporting as of December 31, 2010. See Management’s Report on Internal Control Over Financial Reporting on page F-2 of our Consolidated Financial Statements.

Although we have made various enhancements to our controls, there have been no changes in our internal control over financial reporting during the period covered by this report that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Certifications

The certifications of our Chief Executive Officer and Chief Financial Officer pursuant to Exchange Act rules 13a-14(a) and 15d-14(a) are filed with this report as Exhibits 31.1 and 31.2. The certifications of our Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. 1350 are furnished with this report as Exhibits 32.1 and 32.2.

Item 9B. Other Information

There was no information that was required to be disclosed in a report on Form 8-K during the fourth quarter of 2010 that has not previously been reported.

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PART III

Item 10. Directors and Executive Officers of Our General Partner and Corporate Governance

Partnership Management and Governance

As with many publicly traded partnerships, we do not directly have officers, directors or employees. Our operations and activities are managed by Plains All American GP LLC (“GP LLC”), which employs our management and operational personnel (other than our Canadian personnel, who are employed by Plains Midstream Canada ULC (“PMC” or “Plains Midstream Canada”)). GP LLC is the general partner of Plains AAP, L.P. (“AAP LP”), which is the sole member of PAA GP LLC, our general partner. References to our general partner, as the context requires, include any or all of GP LLC, AAP LP and PAA GP LLC. References to our officers, directors and employees are references to the officers, directors and employees of GP LLC (or, in the case of our Canadian operations, Plains Midstream Canada).

Our general partner manages our operations and activities. Unitholders are limited partners and do not directly or indirectly participate in our management or operation. Our partnership agreement limits any fiduciary duties our general partner might owe to our unitholders. As a general partner, our general partner is liable for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made specifically non-recourse to it. Our general partner has the sole discretion to incur indebtedness or other obligations on our behalf on a non-recourse basis to the general partner. Our general partner has in the past exercised such discretion, in most instances involving payment liability, and intends to exercise such discretion in the future.

Our partnership agreement provides that our general partner will manage and operate us and that unitholders, unlike holders of common stock in a corporation, will have only limited voting rights on matters affecting our business or governance. The corporate governance of GP LLC is, in effect, the corporate governance of our partnership, subject in all cases to any specific unitholder rights contained in our partnership agreement. References to our “Board of Directors” mean the board of directors of GP LLC, which consists of eight directors elected by the members of GP LLC, and not by our unitholders. Under the Fifth Amended and Restated Limited Liability Company Agreement of GP LLC (the “GP LLC Agreement”), three of the members of GP LLC have the right to designate one director each, and our CEO is a director by virtue of holding the office. The remaining four seats are elected, and may be removed, by a majority of the membership interest. Directors filling three of these four “at large” seats must be independent. Under our current ownership profile, any member that accumulates an interest greater than 25% and does not otherwise have a designation right may designate a director. In the event a member of GP LLC ceases to have the right to designate a director, the individual designated by such member is automatically removed as a director. For so long as Vulcan Inc. and its affiliates (“Vulcan”) hold in excess of 12 million of our common units, Vulcan Energy Corporation (“Vulcan Energy”) may send an individual (who must be a senior member of Vulcan’s management) to attend board meetings in an observer capacity. If at any time after December 23, 2015 the number of common units held by Vulcan is less than 5% of our outstanding common units, we have the right to terminate Vulcan Energy’s board observer rights.

Voting rights agreements previously entered into by Vulcan Energy and Lynx Holdings I, LLC were terminated in December 2010 in connection with the sale by Vulcan Energy of its 50.1% interest in our general partner. Vulcan Energy and its affiliates retained a substantial investment in PAA through their common unit holdings. Vulcan Energy has agreed that prior to the earlier of December 23, 2015 and the date, if any, of certain changes in our senior-most management, it will not vote any of its limited partner interests in favor of any proposal to remove GP LLC as our general partner.

Board Leadership Structure and Role in Risk Oversight

Our CEO also serves as Chairman of the Board. The board has no policy with respect to the separation of the offices of chairman and CEO; rather, that relationship is currently defined and governed by the GP LLC Agreement and the employment agreement with the CEO, which require coincidence of the offices. We do not have a lead independent director. The chairmanship of non-management executive

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sessions of the board rotates among the non-management directors, sequenced alphabetically by last name. Directors of GP LLC are designated or elected by the members of GP LLC. Accordingly, unlike holders of common stock in a corporation, our unitholders have only limited voting rights on matters affecting our business or governance, subject in all cases to any specific unitholder rights contained in our partnership agreement.

The management of enterprise level risk (ELR) may be defined as the process of identification, management and monitoring of events that present opportunities and risks with respect to creation of value for our unitholders. The board has delegated to management the primary responsibility for ELR management, while the board has retained responsibility for oversight of management in that regard. Management provides an enterprise-level risk assessment to the Board at least once every year.

Non-Management Executive Sessions and Shareholder Communications

Non-management directors meet in executive session in connection with each regular board meeting. Each non-management director acts as presiding director at the regularly scheduled executive sessions, rotating alphabetically by last name.

Interested parties can communicate directly with non-management directors by mail in care of the General Counsel and Secretary or in care of the Managing Director of Internal Audit at Plains All American Pipeline, L.P., 333 Clay Street, Suite 1600, Houston, Texas 77002. Such communications should specify the intended recipient or recipients. Commercial solicitations or communications will not be forwarded.

Independence Determinations and Audit Committee

Because we are a limited partnership, the listing standards of the NYSE do not require that we or our general partner have a majority of independent directors on the board, nor that we establish or maintain a nominating or compensation committee of the board. We are, however, required to have an audit committee consisting of at least three members, all of whom are required to be “independent” as defined by the NYSE.

To be considered independent under NYSE listing standards, our board of directors must determine that a director has no material relationship with us other than as a director. The standards specify the criteria by which the independence of directors will be determined, including guidelines for directors and their immediate family members with respect to employment or affiliation with us or with our independent public accountants. The board of directors has determined that Messrs. Goyanes, Petersen, Symonds and Temple are independent under applicable NYSE rules.

We have an audit committee that reviews our external financial reporting, engages our independent auditors, and reviews the adequacy of our internal accounting controls. The charter of our audit committee is available on our website. See “—Meetings and Other Information” for information on how to access or obtain copies of this charter. The board of directors has determined that each member of our audit committee (Messrs. Goyanes, Symonds and Temple) is (i) “independent” under applicable NYSE rules and (ii) an “Audit Committee Financial Expert,” as that term is defined in Item 407 of Regulation S-K.

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In determining the independence of the members of our audit committee, the board of directors considered the relationships described below:

Everardo Goyanes, the chairman of our audit committee, is Chairman of Liberty Natural Resources for Liberty Mutual Insurance Company, which is the parent of Liberty Energy Holdings, LLC (“LEH”). LEH makes investments in producing properties, from some of which Plains Marketing, L.P. buys the production. LEH does not operate the properties in which it invests. Plains Marketing pays the same amount per barrel to LEH that it pays to other interest owners in the properties. In 2010, the amount paid to LEH by Plains Marketing was approximately $1.3 million (net of severance taxes). The board has determined that the transactions with LEH do not compromise Mr. Goyanes’ independence.

J. Taft Symonds, a member of our audit committee, has no relationships with either GP LLC or us, other than as a director and unitholder.

Christopher M. Temple, a member of our audit committee, has no relationships with either GP LLC or us, other than as a director and unitholder.

For additional information regarding the experience and qualifications of our directors, please read the biographical descriptions under “—Directors, Executive Officers and Other Officers” below.

Compensation Committee

Although not required by NYSE listing standards, we have a compensation committee that reviews and makes recommendations to the board regarding the compensation for the executive officers and administers our equity compensation plans for officers and key employees. The charter of our compensation committee is available on our website. See “—Meetings and Other Information” for information on how to access or obtain copies of this charter. The compensation committee currently consists of Messrs. Petersen, Raymond and Sinnott and Ms. Sutil. Under applicable stock exchange rules, none of the members of our compensation committee is required to be “independent.” The compensation committee has the sole authority to retain any compensation consultants to be used to assist the committee, but did not retain any consultants in 2010. The compensation committee has delegated limited authority to the CEO to administer our long-term incentive plans with respect to employees other than executive officers.

Governance and Other Committees

Although not required by the NYSE listing standards, we also have a governance committee that periodically reviews our governance guidelines. The charter of our governance committee is available on our website. See “—Meetings and Other Information” for information on how to access or obtain copies of this charter. The governance committee currently consists of Messrs. Petersen and Symonds, both of whom (although not required in this context) are independent under the NYSE’s listing standards. As a limited partnership, we are not required by the listing standards of the NYSE to have a nominating committee. As discussed above, three of the owners of our general partner each have the right to appoint a director, and Mr. Armstrong is a director by virtue of his office. In the event of a vacancy in the three required independent director seats, the governance committee will assist in identifying and screening potential candidates. Upon request of the owners of the general partner, the governance committee is also available to assist in identifying and screening potential candidates for any vacant “at large” seats. The governance committee will base its recommendations on an assessment of the skills, experience and characteristics of the candidate in the context of the needs of the board. The governance committee does not have a policy with regard to the consideration of diversity in identifying director nominees; therefore, diversity may or may not be considered in connection with the assessment process. As a minimum requirement for the three required independent board seats, any candidate must be “independent” and qualify for service on the audit committee under applicable SEC and NYSE rules, the GP LLC Agreement and our partnership agreement.

In addition, our partnership agreement provides for the establishment or activation of a conflicts committee as circumstances warrant to review conflicts of interest between us and our general partner or

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the owners of our general partner. Such a committee will typically consist of a minimum of two members, none of whom can be (i) officers or employees of our general partner, (ii) directors, officers or employees of its affiliates or (iii) owners of the general partner interest. Any matters approved by the conflicts committee will be conclusively deemed to be fair and reasonable to us, approved by all of our partners, and not a breach by our general partner of any duties owed to us or our unitholders. See Item 13. “Certain Relationships and Related Transactions, and Director Independence—Transactions with Related Persons—Review, Approval or Ratification of Transactions with Related Persons.”

Meetings and Other Information

During the last fiscal year, our board of directors had seven meetings, our audit committee had nine meetings, our compensation committee had two meetings and our governance committee had one meeting. All committee members have access to members of management, and a substantial amount of information transfer and informal communication occurs between meetings. None of our directors attended fewer than 75% of the aggregate number of meetings of the board of directors and committees of the board on which the director served.

As discussed above, the corporate governance of GP LLC is, in effect, the corporate governance of our company, and directors of GP LLC are designated or elected by the members of GP LLC. Accordingly, unlike holders of common stock in a corporation, our unitholders have only limited voting rights on matters affecting our business or governance, subject in all cases to any specific unitholder rights contained in our partnership agreement. As a result, we do not hold annual meetings of unitholders.

All of our standing committees have charters. Our committee charters and governance guidelines, as well as our Code of Business Conduct and our Code of Ethics for Senior Financial Officers, which apply to our principal executive officer, principal financial officer and principal accounting officer, are available on our Internet website at http://www.paalp.com. Print versions of the foregoing are available to any person without charge, upon request by writing to our Secretary, Plains All American Pipeline, L.P., 333 Clay Street, Suite 1600, Houston, Texas 77002. We intend to disclose any amendment to or waiver of the Code of Ethics for Senior Financial Officers and any waiver of our Code of Business Conduct on behalf of an executive officer or director either on our Internet website or in an 8-K filing. Our Chief Executive Officer submitted to the NYSE the most recent annual certification, without qualification, as required by Section 303A.12(a) of the NYSE’s Listed Company Manual.

Audit Committee Report

The audit committee of Plains All American GP LLC oversees the Partnership’s financial reporting process on behalf of the board of directors. Management has the primary responsibility for the financial statements and the reporting process including the systems of internal controls.

In fulfilling its oversight responsibilities, the audit committee reviewed and discussed with management the audited financial statements contained in this Annual Report on Form 10-K.

The Partnership’s independent registered public accounting firm, PricewaterhouseCoopers LLP, is responsible for expressing an opinion on the conformity of the audited financial statements with accounting principles generally accepted in the United States of America. The audit committee reviewed with PricewaterhouseCoopers LLP the firm’s judgment as to the quality, not just the acceptability, of the Partnership’s accounting principles and such other matters as are required to be discussed with the audit committee under generally accepted auditing standards.

The audit committee discussed with PricewaterhouseCoopers LLP the matters required to be discussed by Statement of Auditing Standards No. 61, as amended, as adopted by the Public Company Accounting Oversight Board. The committee received written disclosures and the letter from PricewaterhouseCoopers LLP required by applicable requirements of the Public Company Accounting Oversight Board regarding PricewaterhouseCoopers LLP’s communications with the audit committee

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concerning independence, and has discussed with PricewaterhouseCoopers LLP its independence from management and the Partnership.

Based on the reviews and discussions referred to above, the audit committee recommended to the board of directors that the audited financial statements be included in the Annual Report on Form 10-K for the year ended December 31, 2010 for filing with the SEC.

	Everardo Goyanes, Chairman
	J. Taft Symonds
	Christopher M. Temple

Directors, Executive Officers and Other Officers

The following table sets forth certain information with respect to the members of our board of directors, our executive officers (for purposes of Item 401(b) of Regulation S-K) and certain other officers of us and our subsidiaries. Directors are elected annually and all executive officers are appointed by the board of directors. There is no family relationship between any executive officer and director. Three of the owners of our general partner each have the right to separately designate a member of our board. Such designees are indicated in footnote 2 to the following table.

Name	Age (as of 12/31/10)	Position(1)
Greg L. Armstrong*(2)	52	Chairman of the Board, Chief Executive Officer and Director
Harry N. Pefanis*	53	President and Chief Operating Officer
Phillip D. Kramer*	54	Executive Vice President
John R. Rutherford*	50	Executive Vice President
Al Swanson*	46	Executive Vice President and Chief Financial Officer
W. David Duckett*	55	President—Plains Midstream Canada
Mark J. Gorman*	56	Senior Vice President—Crude Oil Operations and Business Development
Alfred A. Lindseth	41	Senior Vice President—Technology, Process & Risk Management
John P. vonBerg*	56	Senior Vice President—Commercial Activities
Stephen L. Bart	50	Vice President—Operations of Plains Midstream Canada
Samuel N. Brown	54	Vice President—Pipeline Business Development
Kevin L. Cantrell	50	Vice President—Internal Audit
David Craig	53	Executive Vice President and Chief Financial Officer of Plains Midstream Canada
Ralph R. Cross	55	Vice President—Corporate Development and Transportation Services of Plains Midstream Canada
A. Patrick Diamond	38	Vice President
Lawrence J. Dreyfuss	56	Vice President, General Counsel—Commercial & Litigation and Assistant Secretary
Roger D. Everett	65	Vice President—Human Resources
James B. Fryfogle	59	Vice President—Refinery Supply
M.D. (Mike) Hallahan	50	Vice President—Crude Oil of Plains Midstream Canada
Chris Herbold*	38	Vice President—Accounting and Chief Accounting Officer
Jim G. Hester	51	Vice President—Acquisitions
John Keffer	51	Vice President—Terminals
Charles Kingswell-Smith	59	Vice President and Treasurer
Gregg McClement	42	Vice President—Business Development—LPG of Plains Midstream Canada
Mike Mikuska	42	Vice President—Business Development of Plains Midstream Canada
Tim Moore*	53	Vice President, General Counsel and Secretary
Daniel J. Nerbonne	53	Vice President—Engineering
John F. Russell	62	Vice President—West Coast Projects

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Robert M. Sanford	61	Vice President—Lease Supply
Scott Sill	48	Vice President—LPG Operations of Plains Midstream Canada
Phil Smith	52	Vice President
Troy E. Valenzuela	49	Vice President—Environmental, Health and Safety
Sandi Wingert	40	Vice President—Accounting of Plains Midstream Canada
David E. Wright	65	Vice President
Everardo Goyanes	66	Director and Member of Audit** Committee
Gary R. Petersen	64	Director and Member of Compensation and Governance Committees
John T. Raymond(2)	40	Director and Member of Compensation Committee
Robert V. Sinnott(2)	61	Director and Member of Compensation** Committee
Vicky Sutil(2)	46	Director and Member of Compensation Committee
J. Taft Symonds	71	Director and Member of Audit and Governance** Committees
Christopher M. Temple	43	Director and Member of Audit Committee

* Indicates an “executive officer” for purposes of Item 401(b) of Regulation S-K.

** Indicates chairman of committee.

(1) Unless otherwise described, the position indicates the position held with Plains All American GP LLC.

(2) The GP LLC Agreement specifies that the Chief Executive Officer of the general partner will be a member of the board of directors. Under the GP LLC Agreement, three of the owners of our general partner have the right to appoint one director each to our board of directors. Mr. Raymond has been appointed by EMG Investment, LLC, of which he is Managing Partner and CEO. Mr. Sinnott has been appointed by KAFU Holdings, L.P., which is affiliated with Kayne Anderson Investment Management, Inc., of which he is President. Ms. Sutil has been appointed by Oxy, of which she is Senior Manager, Corporate Development. The remaining directors were elected by a majority of the membership interest. See Item 12. “Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters—Beneficial Ownership of General Partner Interest.”

Greg L. Armstrong has served as Chairman of the Board and Chief Executive Officer since our formation in 1998. He has also served as a director of our general partner or former general partner since our formation. In addition, he was President, Chief Executive Officer and director of Plains Resources Inc. from 1992 to May 2001. He previously served Plains Resources as: President and Chief Operating Officer from October to December 1992; Executive Vice President and Chief Financial Officer from June to October 1992; Senior Vice President and Chief Financial Officer from 1991 to 1992; Vice President and Chief Financial Officer from 1984 to 1991; Corporate Secretary from 1981 to 1988; and Treasurer from 1984 to 1987. Mr. Armstrong is a director of the Federal Reserve Bank of Dallas, Houston Branch, and National Oilwell Varco, Inc. Mr. Armstrong previously served as a director of BreitBurn Energy Partners, L.P. Mr. Armstrong is also Chairman, Chief Executive Officer and Director of PNGS GP LLC, a 100% owned subsidiary of PAA, which is the general partner of PAA Natural Gas Storage, L.P., a publicly traded MLP that is majority owned by PAA.

Harry N. Pefanis has served as President and Chief Operating Officer since our formation in 1998. He was also a director of our former general partner. In addition, he was Executive Vice President—Midstream of Plains Resources from May 1998 to May 2001. He previously served Plains Resources as: Senior Vice President from February 1996 until May 1998; Vice President—Products Marketing from 1988 to February 1996; Manager of Products Marketing from 1987 to 1988; and Special Assistant for Corporate Planning from 1983 to 1987. Mr. Pefanis was also President of several former midstream subsidiaries of Plains Resources until our formation. Mr. Pefanis is a director of Settoon Towing. Mr. Pefanis is also Vice Chairman and Director of PNGS GP LLC, a 100% owned subsidiary of PAA, which is the general partner of PAA Natural Gas Storage, L.P., a publicly traded MLP that is majority owned by PAA.

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Phillip D. Kramer has served as Executive Vice President since November 2008 and previously served as Executive Vice President and Chief Financial Officer from our formation in 1998 until November 2008. In addition, he was Executive Vice President and Chief Financial Officer of Plains Resources from May 1998 to May 2001. He previously served Plains Resources as: Senior Vice President and Chief Financial Officer from May 1997 until May 1998; Vice President and Chief Financial Officer from 1992 to 1997; Vice President from 1988 to 1992; Treasurer from 1987 to 2001; and Controller from 1983 to 1987.

John R. Rutherford has served as Executive Vice President since October 2010. Mr. Rutherford has 25 years of energy and investment banking experience, most recently serving as Managing Director and Head of North American Energy at Lazard, Freres & Co. Prior to joining Lazard, Mr. Rutherford worked at Simmons & Company International for 10 years, where he served as Managing Director and Partner and played a leadership role in building its financial advisory businesses in the mid-stream, downstream, and exploration and production sectors. During his career, Mr. Rutherford has developed substantial experience advising clients on mergers and acquisitions, corporate restructurings and other strategic actions, including many transactions in which he represented PAA.

Al Swanson has served as Executive Vice President and Chief Financial Officer since February 2011. He previously served as Senior Vice President and Chief Financial Officer from November 2008 through February 2011, as Senior Vice President—Finance from August 2008 until November 2008 and as Senior Vice President—Finance and Treasurer from August 2007 until August 2008. He served as Vice President—Finance and Treasurer from August 2005 to August 2007, as Vice President and Treasurer from February 2004 to August 2005 and as Treasurer from May 2001 to February 2004. In addition, he held finance related positions at Plains Resources including Treasurer from February 2001 to May 2001 and Director of Treasury from November 2000 to February 2001. Prior to joining Plains Resources, he served as Treasurer of Santa Fe Snyder Corporation from 1999 to October 2000 and in various capacities at Snyder Oil Corporation including Director of Corporate Finance from 1998, Controller—SOCO Offshore, Inc. from 1997, and Accounting Manager from 1992. Mr. Swanson began his career with Apache Corporation in 1986 serving in internal audit and accounting. Mr. Swanson is also Senior Vice President, Chief Financial Officer and Director of PNGS GP LLC, a 100% owned subsidiary of PAA, which is the general partner of PAA Natural Gas Storage, L.P., a publicly traded MLP that is majority owned by PAA.

W. David Duckett has served as President of Plains Midstream Canada since June 2003, and served as Executive Vice President of Plains Midstream Canada from July 2001 to June 2003. Mr. Duckett was with CANPET Energy Group Inc. (“CANPET”) from 1985 to 2001, where he served in various capacities, including as President, Chief Executive Officer and Chairman of the Board.

Mark J. Gorman has served as Senior Vice President—Operations and Business Development since August 2008. He previously served as Vice President from November 2006 until August 2008. Prior to joining Plains, he was with Genesis Energy in differing capacities as a Director, President and CEO, and Executive Vice President and COO from 1996 through August 2006. From 1992 to 1996, he served as a President for Howell Crude Oil Company. Mr. Gorman began his career with Marathon Oil Company, spending 13 years in various disciplines. Mr. Gorman is also a director of Settoon Towing, Butte, Frontier and SLC Pipeline.

Alfred A. Lindseth has served as Senior Vice President—Technology, Process & Risk Management since June 2003 and as Vice President—Administration from March 2001 to June 2003. He served as Risk Manager from March 2000 to March 2001. Mr. Lindseth previously served PricewaterhouseCoopers LLP in its Financial Risk Management Practice section as a Consultant from 1997 to 1999 and as Principal Consultant from 1999 to March 2000. He also served GSC Energy, an energy risk management brokerage and consulting firm, as Manager of its Oil & Gas Hedging Program from 1995 to 1996 and as Director of Research and Trading from 1996 to 1997.

John P. vonBerg has served as Senior Vice President—Commercial Activities since August 2008. Previously he served as Vice President—Commercial Activities from August 2007 until August 2008 and as Vice President—Trading from May 2003 until August 2007. He served as Director of these activities

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from January 2002 until May 2003. Prior to joining us in January 2002, he was with Genesis Energy in differing capacities as a Director, Vice Chairman, President and CEO from 1996 through 2001, and from 1993 to 1996 he served as a Vice President and a Crude Oil Manager for Phibro Energy USA. Mr. vonBerg began his career with Marathon Oil Company, spending 13 years in various disciplines.

Stephen L. Bart has served as Vice President—Operations of Plains Midstream Canada since April 2005 and was Managing Director, LPG Operations & Engineering from February to April 2005. From June 2003 to February 2005, Mr. Bart was engaged as a principal of Broad Quay Development, a consulting firm. From April 2001 to June 2003, Mr. Bart served as Chief Executive Officer of Novera Energy Limited, a publicly-traded international renewable energy concern. From January 2000 to April 2003, he served as Director, Northern Development, for Westcoast Energy Inc.

Samuel N. Brown has served as Vice President—Pipeline Business Development since October 2009. Prior to joining PAA, Mr. Brown served TEPPCO for over 10 years, most recently as Vice President—Commercial Downstream and previously as Vice President—Pipeline Marketing and Business Development for the Upstream segment. Prior to joining TEPPCO, Mr. Brown was with Duke Energy Transport and Trading Company.

Kevin L. Cantrell has served as Vice President – Internal Audit since February 2011 and served as Managing Director - Internal Audit from April 2009 to February 2011. Prior to joining PAA, Mr. Cantrell was a managing director and founding member of Protiviti, Inc., a global risk consulting and internal audit firm, from May 2002 to April 2009, and a manager in Andersen’s Risk Consulting practice in Houston, Texas, from February 1999 to May 2002, where he lead internal audit, risk management, and Sarbanes-Oxley compliance projects for clients in the Energy industry. Kevin began his professional career at J.P. Morgan Chase, where he held positions of increasing responsibilities in the internal audit and capital markets compliance groups from July 1986 through February 1999.

David Craig has served as Executive Vice President and Chief Financial Officer of Plains Midstream Canada since June 2008. Prior to joining our Canadian operations, Mr. Craig was with Nexen Inc. from 2004 to June 2008, where he served in various capacities, including most recently as Vice President of natural gas marketing. From 1999 until 2004, he was with Apache Canada Ltd., with responsibilities in the areas of gas marketing and finance. Mr. Craig has over 25 years of experience in the energy industry in various financial roles (including accounting, planning, treasury, and mergers & acquisitions) as well as natural gas marketing.

Ralph R. Cross has served as Vice President—Corporate Development and Transportation Services of Plains Midstream Canada since July 2001. Mr. Cross was previously with CANPET since 1992, where he served in various capacities, including most recently as Vice President of Business Development.

A. Patrick Diamond has served as Vice President since August 2007. He previously served as Director, Strategic Planning from July 2005 to August 2007 and as Manager—Special Projects from June 2001 to July 2005. In addition, he was Manager—Special Projects of Plains Resources from August 1999 to June 2001. Prior to joining Plains Resources, Mr. Diamond served Salomon Smith Barney in its Global Energy Investment Banking Group as an Associate from July 1997 to May 1999 and as a Financial Analyst from July 1994 to June 1997.

Lawrence J. Dreyfuss has served as Vice President, General Counsel—Commercial & Litigation and Assistant Secretary since August 2006. Mr. Dreyfuss was Vice President, Associate General Counsel and Assistant Secretary of our general partner from February 2004 to August 2006 and Associate General Counsel and Assistant Secretary of our general partner from June 2001 to February 2004 and held a senior management position in the Law Department since May 1999. In addition, he was a Vice President of Scurlock Permian LLC from 1987 to 1999.

Roger D. Everett has served as Vice President—Human Resources since November 2006 and as Director of Human Resources from August 2006 to December 2006. Before joining us, Mr. Everett was a Principal with Stone Partners, a human resource management consulting firm, for over 10 years serving as the Managing Director Human Resources from 2000 to 2006. Mr. Everett has held numerous positions of increasing responsibility in human resource management since 1979 including Vice President of Human Resources at Living Centers of America and Beverly Enterprises, Director of Human Resources at Healthcare International and Director of Compensation and benefits at Charter Medical.

James B. Fryfogle has served as Vice President—Refinery Supply since March 2005. He served as Vice President—Lease Operations from July 2004 until March 2005. Prior to joining us in January 2004, Mr. Fryfogle served as Manager of Crude Supply and Trading for Marathon Ashland Petroleum.

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Mr. Fryfogle had held numerous positions of increasing responsibility with Marathon Ashland Petroleum or its affiliates or predecessors since 1975.

M.D. (Mike) Hallahan has served as Vice President—Crude Oil of Plains Midstream Canada since February 2004 and Managing Director, Facilities from July 2001 to February 2004. He was previously with CANPET where he served in various capacities since 1996, most recently as General Manager, Facilities.

Chris Herbold has served as Vice President—Accounting and Chief Accounting Officer since August 2010. He served as Controller of PAA from 2008 until August 2010. He previously served as Director of Operational Accounting from 2006 to 2008, Director of Financial Reporting and Accounting from 2003 to 2006 and Manager of SEC and Financial Reporting from 2002 to 2003. Prior to joining PAA in April 2002, Mr. Herbold spent seven years working for the accounting firm Arthur Andersen LLP.

Jim G. Hester has served as Vice President—Acquisitions since March 2002. Prior to joining us, Mr. Hester was Senior Vice President—Special Projects of Plains Resources. From May 2001 to December 2001, he was Senior Vice President—Operations for Plains Resources. From May 1999 to May 2001, he was Vice President—Business Development and Acquisitions of Plains Resources. He was Manager of Business Development and Acquisitions of Plains Resources from 1997 to May 1999, Manager of Corporate Development from 1995 to 1997 and Manager of Special Projects from 1993 to 1995. He was Assistant Controller from 1991 to 1993, Accounting Manager from 1990 to 1991 and Revenue Accounting Supervisor from 1988 to 1990.

John Keffer has served as Vice President—Terminals since November 2006. Mr. Keffer joined Plains Marketing L.P. in October 1998 and prior to his appointment as Vice President, he served as Managing Director—Refinery Supply, Director of Trading and Manager of Sales and Trading. Prior to joining Plains, Mr. Keffer was with Prebon Energy, an energy brokerage firm, from January 1996 through September 1998. Mr. Keffer was with the Permian Corporation/Scurlock Permian from January 1990 through December 1995, where he served in several capacities in the marketing department including Director of Crude Oil Trading. Mr. Keffer began his career with Amoco Production Company and served in various capacities beginning in June 1982.

Charles Kingswell-Smith has served as Vice President and Treasurer since August 2008. Mr. Kingswell-Smith previously served as Managing Director of GE Energy Financial Services from January 2008 to July 2008 and as Managing Director with Merrill Lynch Capital from March 2007 until January 2008. Prior to joining Merrill Lynch Capital, Mr. Kingswell-Smith spent 12 years in the energy banking business with JPMorgan Chase and BankOne.

Mike Mikuska has served as Vice President—Business Development of Plains Midstream Canada since September 2008. Mr. Mikuska has been with PMC and its predecessor CANPET since 1995 and has served in various commercial and development roles over that time.

Gregg McClement has served as Vice President—Business Development—LPG of Plains Midstream Canada since December 2009. Mr. McClement has been with PMC and its predecessor CANPET since 2001. He previously held numerous senior management roles in the transportation industry with companies such as B.C. Rail and Union Pacific Railway.

Tim Moore has served as Vice President, General Counsel and Secretary since May 2000. In addition, he was Vice President, General Counsel and Secretary of Plains Resources from May 2000 to May 2001. Prior to joining Plains Resources, he served in various positions, including General Counsel—Corporate, with TransTexas Gas Corporation from 1994 to 2000. He previously was a corporate attorney with the Houston office of Weil, Gotshal & Manges LLP. Mr. Moore also has seven years of energy industry experience as a petroleum geologist.

Daniel J. Nerbonne has served as Vice President—Engineering since February 2005. Prior to joining us, Mr. Nerbonne was General Manager of Portfolio Projects for Shell Oil Products US from January 2004 to January 2005 and served in various capacities, including General Manager of Commercial

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and Joint Interest, with Shell Pipeline Company or its predecessors from 1998. From 1980 to 1998 Mr. Nerbonne held numerous positions of increasing responsibility in engineering, operations, and business development, including Vice President of Business Development from December 1996 to April 1998, with Texaco Trading and Transportation or its affiliates.

John F. Russell has served as Vice President—West Coast Projects since August 2007. He served as Vice President—Pipeline Operations from July 2004 to August 2007. Prior to joining us, Mr. Russell served as Vice President of Business Development & Joint Interest for ExxonMobil Pipeline Company. Mr. Russell had held numerous positions of increasing responsibility with ExxonMobil Pipeline Company or its affiliates or predecessors since 1974.

Robert M. Sanford has served as Vice President—Lease Supply since June 2006. He served as Managing Director—Lease Acquisitions and Trucking from July 2005 to June 2006 and as Director of South Texas and Mid Continent Business Units from April 2004 to July 2005. Mr. Sanford was with Link Energy/EOTT Energy from 1994 to April 2004, where he held various positions of increasing responsibility.

Scott Sill has served as Vice President, LPG Operations of Plains Midstream Canada since March 2010. He joined Plains Midstream Canada in April 2006 through PAA’s acquisition of the Shafter gas liquids processing facility. Prior to his most recent role as Managing Director of U.S. and Canadian LPG Operations, Scott performed the role of West Coast District Superintendent, overseeing an LPG isomerization/hydrotreating facility, salt cavern terminal, fractionation plant and various storage terminals. Scott brings over 20 years LPG operations experience to this role.

Phil Smith has served as Vice President—Operations since April 2010. He joined PAA in 2002 from Shell Pipeline. Phil is responsible for the Partnership’s operations and maintenance activities on its domestic pipeline and terminal facilities.

Troy E. Valenzuela has served as Vice President—Environmental, Health and Safety, or EH&S, since July 2002, and has had oversight responsibility for the environmental, safety and regulatory compliance efforts of us and our predecessors since 1992. He was Director of EH&S with Plains Resources from January 1996 to June 2002, and Manager of EH&S from July 1992 to December 1995. Prior to his time with Plains Resources, Mr. Valenzuela spent seven years with Chevron USA Production Company in various EH&S roles.

Sandi Wingert has served as Vice President—Accounting of Plains Midstream Canada since February 2008. She has been with PMC and its predecessor CANPET acting as Controller since 2000. Prior to joining our Canadian operations, she held various accounting roles with Koch Petroleum and Ernst & Young.

David E. Wright has served as Vice President since November 2006. Prior to joining Plains, he served as Executive Vice President, Corporate Development for Pacific Energy Partners, L.P. from February 2005 and as Vice President, Corporate Development and Marketing from December 2001. Mr. Wright also served as Vice President, Distribution West for Tosco Refining Company from March 1997 to June 2001, and as Vice President, Pipelines for GATX Terminals Corporation from October 1995 to March 1997.

Everardo Goyanes has served as a director of our general partner or former general partner since May 1999. Mr. Goyanes has been Chairman of Liberty Natural Resources since April 2009. From May 2000 to April 2009, he was President and Chief Executive Officer of Liberty Energy Holdings, LLC (an energy investment firm). From 1999 to May 2000, he was a financial consultant specializing in natural resources. From 1989 to 1999, he was Managing Director of the Natural Resources Group of ING Barings Furman Selz (a banking firm). He was a financial consultant from 1987 to 1989 and was Vice President—Finance of Forest Oil Corporation from 1983 to 1987. From 1967 to 1982, Mr. Goyanes served in various financial and management capacities at Chase Bank, where his major emphasis was international and corporate finance to large independent and major oil companies. Mr. Goyanes received a BA in Economics

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from Cornell University and a Master’s degree in Finance (honors) from Babson Institute. The Board of Directors has determined that Mr. Goyanes is “independent” under applicable NYSE rules and qualifies as an “Audit Committee Financial Expert.” Mr. Goyanes’ qualifications as an Audit Committee Financial Expert are supplemented by extensive experience comprising direct involvement in the energy sector over a span of more than 30 years. We believe that this experience, coupled with the leadership qualities demonstrated by his executive background bring important experience and skill to the Board.

Gary R. Petersen has served as a director of our general partner since June 2001. Mr. Petersen is Senior Managing Director of EnCap Investments L.P., an investment management firm which he co-founded in 1988. He is also a director of EV Energy Partners, L.P. He had previously served as Senior Vice President and Manager of the Corporate Finance Division of the Energy Banking Group for RepublicBank Corporation. Prior to his position at RepublicBank, he was Executive Vice President and a member of the Board of Directors of Nicklos Oil & Gas Company from 1979 to 1984. He served from 1970 to 1971 in the U.S. Army as a First Lieutenant in the Finance Corps and as an Army Officer in the Army Security Agency. He is a member of the Independent Petroleum Association of America, the Houston Producers Forum and the Petroleum Club of Houston. Mr. Petersen holds BBA and MBA degrees in finance from Texas Tech University. The Board of Directors has determined that Mr. Petersen is “independent” under applicable NYSE rules. Mr. Petersen has been involved in the energy sector for a period of more than 30 years, garnering extensive knowledge of the energy sectors’ various cycles, as well as the current market and industry knowledge that comes with management of approximately $9 billion of energy-related investments. In tandem with the leadership qualities evidenced by his executive background, we believe that Mr. Petersen brings numerous valuable attributes to the Board.

John T. Raymond has served as a director of our general partner since December 2010. Mr. Raymond is an owner and founder of EMG, a diversified natural resource private equity fund manager with over $2.5 billion under management, and has been Managing Partner and CEO since EMG’s inception in 2006. Previous to that time, Mr. Raymond held leadership positions with various energy companies, including President and CEO of Plains Resources Inc. (the predecessor entity for VEC), President and Chief Operating Officer of Plains Exploration and Production Company and Director of Development for Kinder Morgan, Inc. Mr. Raymond has been a direct or indirect owner of PAA’s general partner since 2001 and served on the board of PAA’s general partner from 2001 to 2005. We believe that Mr. Raymond’s experience with investment in and management of a variety of upstream and midstream assets and operations will provide a valuable resource to the Board.

Robert V. Sinnott has served as a director of our general partner or former general partner since September 1998. Mr. Sinnott is President, Chief Executive Officer, and Senior Managing Director of energy investments, of Kayne Anderson Capital Advisors, L.P. (an investment management firm). He also served as a Managing Director from 1992 to 1996 and as a Senior Managing Director from 1996 until assuming his CEO role in 2010. He is also President of Kayne Anderson Investment Management, Inc., the general partner of Kayne Anderson Capital Advisors, L.P. and he is a director of Kayne Anderson Energy Development Company and Kayne Anderson Midstream/Energy Fund Inc. He was Vice President and Senior Securities Officer of the Investment Banking Division of Citibank from 1986 to 1992. Mr. Sinnott received a BA from the University of Virginia and an MBA from Harvard. Mr. Sinnott’s extensive investment management background includes his current role of managing approximately $6 billion of energy-related investments. Coupled with his direct involvement in the energy sector, spanning more than 30 years, the breadth of his current market and industry knowledge is enhanced by the depth of his knowledge of the various cycles in the energy sector. We believe that as a result of his background and knowledge, as well as the attributes of leadership demonstrated by his executive experience, Mr. Sinnott brings substantial experience and skill to the Board.

Vicky Sutil has served as a director of our general partner since December 2010. Ms. Sutil is Senior Manager, Corporate Development, for Oxy, where she has led and worked on a variety of international and domestic oil and gas acquisitions. Her prior positions at Oxy have included Manager, Financial Planning and Analysis, and Senior Business Analyst. Before joining Oxy in 2000, Ms. Sutil worked for ARCO Products Company as a Business Analyst for the Refining and Retail Marketing divisions, and Senior Project Manager for the Refining Division. Earlier, she held a variety of engineering

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positions at Mobil Oil Corporation. Ms. Sutil served as Oxy’s designated board observer from 2008, when Oxy acquired its initial interest in PAA’s general partner, until December 2010. Ms. Sutil received a BS in Mechanical Engineering — Petroleum Emphasis from the University of California, Berkeley, and an MBA from Pepperdine University. We believe that Ms. Sutil’s financial and analytical background, coupled with her knowledge of engineering, will provide to the Board a distinctive and valuable perspective.

J. Taft Symonds has served as a director of our general partner since June 2001. Mr. Symonds is Chairman of the Board of Symonds Investment Company, Inc. (a private investment firm). From 1978 to 2004 he was Chairman of the Board and Chief Financial Officer of Maurice Pincoffs Company, Inc. (an international marketing firm). Mr. Symonds has a background in both investment and commercial banking, including merchant banking in New York, London and Hong Kong with Paine Webber, Robert Fleming Group and Banque de la Societe Financiere Europeenne. He was Chairman of the Houston Arboretum and Nature Center and currently serves as a director of Howard Supply Company LLC and Schilling Robotics LLC, where he serves on the audit committee. Mr. Symonds previously served as a director of Tetra Technologies Inc. Mr. Symonds received a BA from Stanford University and an MBA from Harvard. The Board of Directors has determined that Mr. Symonds is “independent” under applicable NYSE rules and qualifies as an “Audit Committee Financial Expert.” In addition to his qualifications as an Audit Committee Financial Expert, Mr. Symonds has a broad background in both commercial and investment banking, as well as investment management, all with a heavy emphasis on the energy sector. We believe that Mr. Symonds’ background offers to the Board a distinct and valuable knowledge base representative of both the capital and physical markets and refined by the leadership qualities evident from his executive experience.

Christopher M. Temple has served as a director of our general partner since May 2009. He is President of DelTex Capital LLC (a private investment firm). Mr. Temple served as the President of Vulcan Capital, the private investment group of Vulcan Inc., from May 2009 until December 2009 and as Vice President of Vulcan Capital from September 2008 to May 2009. Mr. Temple served on the board of directors and audit committee of Charter Communications Inc. from November 2009 through January 2011. Prior to joining Vulcan in September 2008, Mr. Temple served as a managing director at Tailwind Capital LLC from May to August 2008. Prior to joining Tailwind, Mr. Temple was a managing director at Friend Skoler & Co., Inc. from May 2005 to May 2008. From April 1996 to December 2004, Mr. Temple was a managing director at Thayer Capital Partners. Additionally, Mr. Temple was a licensed CPA serving clients in the energy sector with KPMG in Houston, Texas from 1989 to 1993. Mr. Temple holds a BBA, magna cum laude, from the University of Texas and an MBA from Harvard. The Board of Directors has determined that Mr. Temple is “independent” under applicable NYSE rules and qualifies as an “Audit Committee Financial Expert.” Mr. Temple has a broad investment management background across a variety of business sectors, as well as experience in the energy sector. We believe that this background, along with the leadership attributes indicated by his executive experience, provide an important source of insight and perspective to the Board.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Securities Exchange Act of 1934 requires directors, executive officers and persons who beneficially own more than ten percent of a registered class of our equity securities to file with the SEC and the NYSE initial reports of ownership and reports of changes in ownership of such equity securities. Such persons are also required to furnish us with copies of all Section 16(a) forms that they file. Such reports are accessible on or through our Internet website at http://www.paalp.com.

Based solely upon a review of the copies of Forms 3 and 4 furnished to us, or written representations from certain reporting persons that no Forms 5 were required, we believe that our executive officers and directors complied with all filing requirements with respect to transactions in our equity securities during 2010, except as follows: Mr. Duckett was late in filing two Forms 4 in connection with the sale of 23,896 common units on June 4, 2010 and the sale of 18,300 common units on December 20, 2010. These transactions were reported on a Form 4 filed on February 11, 2011.

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Item 11. Executive Compensation

Compensation Committee Report

The compensation committee of Plains All American GP LLC reviews and makes recommendations to the board of directors regarding the compensation for the executive officers and directors.

In fulfilling its oversight responsibilities, the compensation committee reviewed and discussed with management the compensation discussion and analysis contained in this Annual Report on Form 10-K. Based on those reviews and discussions, the compensation committee recommended to the board of directors that the compensation discussion and analysis be included in the Annual Report on Form 10-K for the year ended December 31, 2010 for filing with the SEC.

	Robert V. Sinnott, Chairman
	Gary R. Petersen

Compensation Committee Interlocks and Insider Participation

Messrs. Petersen and Sinnott currently serve on the compensation committee, and served on the compensation committee throughout 2010. Geoff McKay, a former director, served on the compensation committee for a portion of 2010. During 2010, none of the members of the committee was an officer or employee of us or any of our subsidiaries, or served as an officer of any company with respect to which any of our executive officers served on such company’s board of directors. In addition, none of the members of the compensation committee are former employees of ours or any of our subsidiaries. Mr. Sinnott is associated with Kayne Anderson and its affiliates, with which we have relationships. Mr. McKay is associated with Vulcan Energy and its affiliates, with which we have relationships. See Item 13. “Certain Relationships and Related Transactions, and Director Independence.” Mr. Raymond and Ms. Sutil were appointed to the compensation committee in February 2011.

Compensation Discussion and Analysis

Background

All of our officers and employees (other than Canadian personnel) are employed by Plains All American GP LLC. Our Canadian personnel are employed by Plains Midstream Canada, which is a wholly owned subsidiary. Under our partnership agreement, we are required to reimburse our general partner and its affiliates for all employment related costs, including compensation for executive officers, other than expenses related to the Class B units of Plains AAP, L.P.

Objectives

Since our inception, we have employed a compensation philosophy that emphasizes pay for performance, both on an individual and entity level, and places the majority of each Named Executive Officer’s (defined in the Summary Compensation Table below) compensation at risk. The primary long-term measure of our performance is our ability to increase our sustainable quarterly distribution to our unitholders. We believe our pay-for-performance approach aligns the interests of our executive officers with that of our equity holders, and at the same time enables us to maintain a lower level of base overhead in the event our operating and financial performance is below expectations. Our executive compensation is designed to attract and retain individuals with the background and skills necessary to successfully execute our business model in a demanding environment, to motivate those individuals to reach near-term and long-term goals in a way that aligns their interest with that of our unitholders, and to reward success in reaching such goals. We use three primary elements of compensation to fulfill that design—salary, cash bonus and long-term equity incentive awards. Cash bonuses and equity incentives (as opposed to salary) represent the performance driven elements. They are also flexible in application and can be tailored to meet our objectives. The determination of specific individuals’ cash bonuses is based on their relative contribution to achieving or exceeding annual goals and the determination of specific individuals’ long-term incentive

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awards is based on their expected contribution in respect of longer term performance objectives. We do not maintain a defined benefit or pension plan for our executive officers as we believe such plans primarily reward longevity and not performance. We provide a basic benefits package generally to all employees, which includes a 401(k) plan and health, disability and life insurance. In instances considered necessary for the execution of their job responsibilities, we also reimburse certain of our Named Executive Officers and other employees for club dues and similar expenses. We consider these benefits and reimbursements to be typical of other employers, and we do not believe they are distinctive of our compensation program.

Elements of Compensation

Salary. We do not “benchmark” our salary or bonus amounts. In practice, we believe our salaries are generally competitive with the narrower universe of large-cap master limited partnerships, but are moderate relative to the broad spectrum of energy industry competitors for similar talent.

Cash Bonuses. Our cash bonuses include annual discretionary bonuses in which all of our current domestic Named Executive Officers potentially participate as well as a quarterly bonus program in which Mr. vonBerg was eligible to participate in 2010, 2009 and 2008. Mr. Duckett participates in an annual and quarterly bonus program that is specific to activities managed by our Canadian personnel.

Long-Term Incentive Awards. The primary long-term measure of our performance is our ability to increase our sustainable quarterly distribution to our unitholders. Historically, we have used performance-indexed phantom unit grants to encourage and reward timely achievement of targeted distribution levels and align the long-term interests of our Named Executive Officers with those of our unitholders. These grants also require minimum service periods as further described below in order to encourage long-term retention. A phantom unit is the right to receive, upon the satisfaction of vesting criteria specified in the grant, a common unit (or cash equivalent). We do not use options as a form of incentive compensation. Unlike “vesting” of an option, vesting of a phantom unit results in delivery of a common unit or cash of equivalent value as opposed to a right to exercise. Terms of historical phantom unit grants have varied, but generally phantom units vest upon the later of achievement of targeted distribution threshold levels and continued employment for periods ranging from two to five years. These distribution performance thresholds are generally consistent with our targeted range for distribution growth. To encourage accelerated performance, if we meet certain distribution thresholds prior to meeting the minimum service requirement for vesting, our current Named Executive Officers have the right to receive distributions on phantom units prior to vesting in the underlying common units (referred to as distribution equivalent rights, or “DERs”).

In 2007, the owners of Plains AAP, L.P. authorized the creation of “Class B” units of Plains AAP, L.P. and authorized GP LLC’s compensation committee to issue grants of Class B units to create additional long-term incentives for our management. The entire economic burden of the Class B units is borne solely by Plains AAP, L.P. and does not impact our cash or units outstanding.

The Class B units are subject to restrictions on transfer and generally become incrementally “earned” (entitled to participate in distributions) upon achievement of certain performance thresholds. As of February 14, 2011, approximately 50% of the outstanding Class B units granted in 2007 had been earned, approximately 37.5% of the Class B units granted in 2009 had been earned, and none of the Class B units granted in 2010 had been earned.

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right. See Item 13. “Certain Relationships and Related Transactions, and Director Independence—Transactions with Related Persons—Our General Partner—Class B Units of Plains AAP, L.P.”

Transaction/Transition Grants. In connection with the initial public offering of PNG, we created a plan based on PNG equity, which is designed to reward and create incentive for certain of our officers who were instrumental in developing the natural gas storage business and bringing it to the point of the IPO, and who will continue to allocate meaningful amounts of time to the business. Recipients of these “transaction/transition grants” included Messrs. Armstrong, Pefanis and Swanson. Such grants are transactional and transitional and are not expected to be a recurring component of these individual’s compensation arrangements. Vesting terms are intended to align the interests of these individuals with those of PAA as such interests pertain to achieving specific future performance benchmarks that are significant to PNG and to PAA’s equity holdings in PNG. See Summary Compensation Table.

Relation of Compensation Elements to Compensation Objectives

Our compensation program is designed to motivate, reward and retain our executive officers. Cash bonuses serve as a near-term motivation and reward for achieving the annual goals established at the beginning of each year. Phantom unit awards (and associated DERs) and Class B units provide motivation and reward over both the near-term and long-term for achieving performance thresholds necessary for earning and vesting. Transaction/transition grants, as the title implies, focus on contributions to the success of a specific transaction, including reward for inception and consummation, as well as incentive for effective transition and execution of the business plan going forward. The level of annual bonus and phantom unit awards reflect the moderate salary profile and the significant weighting towards performance based, at-risk compensation. Salaries and cash bonuses (particularly quarterly bonuses), as well as currently payable DERs associated with unvested phantom units and earned Class B units subject to Plains AAP, L.P.’s call right, serve as near-term retention tools. Longer-term retention is facilitated by the minimum service periods of up to five years associated with phantom unit awards, the long-term vesting profile of the Class B units and, in the case of certain executives directly involved in activities that generate partnership earnings, annual bonuses that are payable over a three-year period. To facilitate Plains All American GP LLC’s compensation committee in reviewing and making recommendations, a compensation “tally sheet” is prepared by Plains All American GP LLC’s CEO and General Counsel and provided to the compensation committee.

We stress performance-based compensation elements to attempt to create a performance-driven environment in which our executive officers are (i) motivated to perform over both the short term and the long term, (ii) appropriately rewarded for their services and (iii) encouraged to remain with us even after meeting long-term performance thresholds in order to meet the minimum service periods and by the potential for rewards yet to come. We believe our compensation philosophy as implemented by application of the three primary compensation elements (i) aligns the interests of our Named Executive Officers with our unitholders, (ii) positions us to achieve our business goals, and (iii) effectively encourages the exercise of sound judgment and risk-taking that is conducive to creating and sustaining long-term value. We believe the processes employed by the compensation committee and the board in applying the elements of compensation (as discussed in more detail below) provide an adequate level of oversight with respect to the degree of risk being taken by management to achieve short-term performance goals. See “Relation of Compensation Policies and Practices to Risk Management.”

We believe our compensation program has been instrumental in our achievement of stated objectives. Over the five-year period ended December 31, 2010, our annual distribution per common unit has grown at a compound annual rate of 7.0% and the total return realized by our unitholders for that period averaged approximately 17.5%. During this period, we have enjoyed a high rate of retention among executive officers.

Application of Compensation Elements

Salary. We do not make systematic annual adjustments to the salaries of our Named Executive Officers. Instead, when indicated as a result of adding new senior management members to keep pace with

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our overall growth, necessary salary adjustments are made to maintain hierarchical relationships between senior management levels and the new senior management members. Since the date of our initial public offering (or date of employment, if later) through December 31, 2010, Messrs. Armstrong and Pefanis have each received one salary adjustment, Mr. Duckett has received small salary adjustments in line with other Canadian personnel, Mr. vonBerg has received one salary adjustment and Mr. Swanson has received four salary adjustments in connection with taking on increasing responsibilities and promotions.

Annual Discretionary Bonuses. Annual discretionary bonuses are determined based on our performance relative to our annual plan forecast and public guidance (typically provided quarterly in conjunction with release of earnings), our distribution growth targets, and other quantitative and qualitative goals established at the beginning of each year. Such annual objectives are discussed and reviewed with the board of directors in conjunction with the review and authorization of the annual plan.

At the end of each year, the CEO performs a quantitative and qualitative assessment of our performance relative to our goals. Key quantitative measures include earnings before interest, taxes, depreciation and amortization, excluding items affecting comparability (“adjusted EBITDA”), relative to established guidance, as well as the growth in the annualized quarterly distribution level per common unit relative to annual growth targets. Our primary performance metric is our ability to generate increasing and sustainable cash distributions to our unitholders. Accordingly, although net income and net income per unit are monitored to highlight inconsistencies with primary performance metrics, as is our market performance relative to our MLP peers and major indices, these metrics are considered secondary performance measures. The CEO’s written analysis of our performance examines our accomplishments, shortfalls and overall performance against opportunity, taking into account controllable and non-controllable factors encountered during the year.

The resulting document and supporting detail is submitted to the board of directors of Plains All American GP LLC for review and comment. Based on the conclusions set forth in the annual performance review, the CEO submits recommendations to the compensation committee for bonuses to our other Named Executive Officers taking into account the relative contribution of the individual officer. There are no set formulas for determining the annual discretionary bonus for our Named Executive Officers. Factors considered by the CEO in determining the level of bonus in general include (i) whether or not we achieved the goals established for the year and any notable shortfalls relative to expectations; (ii) the level of difficulty associated with achieving such objectives based on the opportunities and challenges encountered during the year; (iii) current year operating and financial performance relative to both public guidance and prior year’s performance; (iv) significant transactions or accomplishments for the period not included in the goals for the year; (v) our relative prospects at the end of the year with respect to future growth and performance; and (vi) our positioning at the end of the year with respect to our targeted credit profile. The CEO takes these factors into consideration as well as the relative contributions of each of our Named Executive Officers to the year’s performance in developing his recommendations for bonus amounts.

These recommendations are discussed with the compensation committee, adjusted as appropriate, and submitted to the board of directors for its review and approval. Similarly, the compensation committee assesses the CEO’s contribution toward meeting our goals, and recommends a bonus for the CEO it believes to be commensurate with such contribution. In several instances, the CEO and the President have requested that the bonus amount recommended by the compensation committee be reduced to maintain a closer relationship to bonuses awarded to the other Named Executive Officers. As a result, the current practice is for the CEO to submit to the compensation committee a preliminary draft of bonus recommendations with the amount for the CEO left blank. In the context of discussing and adjusting bonus amounts for other executives set forth in the preliminary draft, the committee and the CEO reach consensus on the appropriate bonus amount for the CEO. The preliminary draft is then revised to include any changes or adjustments, as well as an amount for the CEO, in the formal submittal to the compensation committee for review and recommendation to the board.

U.S. Bonus based on Adjusted EBITDA. Mr. vonBerg and certain other members of our U.S.-based senior management team are directly involved in activities that generate partnership earnings. These

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individuals, along with other employees in our marketing and business development groups participate in a quarterly bonus pool, the size of which is based on adjusted EBITDA, which directly rewards for quarterly performance the commercial and asset managing employees who participate. This quarterly incentive provides a direct incentive to optimize quarterly performance even when, on an annual basis, other factors might negatively affect bonus potential. The size of the bonus pool, and the allocation of quarterly bonus amounts among all participants based on relative contribution, is recommended by Mr. Pefanis and reviewed, modified and approved by Mr. Armstrong, as appropriate. Messrs. Pefanis and Armstrong do not participate in the quarterly bonus pool. The quarterly bonus amounts for Mr. vonBerg are taken into consideration in determining the recommended annual discretionary bonus submitted by the CEO to the compensation committee.

Annual Bonus and Quarterly Bonus based on Adjusted EBITDA (Canada). Substantially all of the personnel employed by Plains Midstream Canada (including Mr. Duckett) or involved in Canadian operations participate in a bonus pool under a program established at the time of our entry into Canada in 2001 in connection with the CANPET acquisition. The program encompasses a bonus pool consisting of 10% of Adjusted EBITDA for Canadian-based operations (reduced by the carrying cost of inventory in excess of base-level requirements and by the cost of capital associated with growth capital and acquisitions). Participation in the program is recommended by Mr. Duckett and reviewed, adjusted if warranted, and approved by Mr. Pefanis. Mr. Pefanis does not participate in the bonus pool. Mr. Duckett receives a quarterly bonus equal to approximately 40% of his participation level for the first three fiscal quarters of the year. He receives an annual bonus consisting of 60% of his participation in the first three quarters and 100% of his participation in the fourth quarter.

Long-Term Incentive Awards. We do not make systematic annual phantom unit awards to our Named Executive Officers. Instead, our objective is to time the granting of awards such that as performance thresholds are met for existing awards, additional long-term incentives are created. Thus, performance is rewarded by relatively greater frequency of awards and lack of performance by relatively lesser frequency of awards. Generally, we believe that a grant cycle of approximately three years (and extended time-vesting requirements) provides a balance between a meaningful retention period for us and a visible, reachable reward for the executive officer. Achievement of performance targets does not shorten the minimum service period requirement. If top performance targets on outstanding awards are achieved in the early part of this cycle, new awards are granted with higher performance thresholds, and the minimum service periods of the new awards are generally synchronized with the remaining time-vesting requirements of outstanding awards in a manner designed to encourage extended retention of our Named Executive Officers. Accordingly, these new arrangements inherently take into account the value of awards where performance levels have been achieved but have not yet vested due to ongoing service period requirements, but do not take into consideration previous awards that have fully vested.

As an additional means of providing longer-term, performance-based officer incentives that require extended periods of employment to realize the full benefit, in 2007 the owners of Plains AAP, L.P. authorized the creation of “Class B” units of Plains AAP, L.P., which the compensation committee of GP LLC is authorized to administer. See “—Elements of Compensation—Long-Term Incentives.” These Class B units are limited to 200,000 authorized units, of which approximately 175,500 were issued as of December 31, 2010 pursuant to individual restricted units agreements between Plains AAP, L.P. and certain members of management. As of December 31, 2010 our Named Executive Officers held 121,000 of the restricted Class B units. The remaining available Class B units are administered at the discretion of the compensation committee and may be awarded upon advancement, exceptional performance or other change in circumstance of an existing member of management, or upon the addition of a new individual to the management team.

Application in 2010

At the beginning of 2010, we established four public goals with paraphrased versions of three of these goals overlapping with three of our five internal goals. As a result, we entered 2010 with six distinct goals for the year.

The four public goals for the year were to:

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1. Deliver baseline operating and financial performance in line with guidance;

2. Successfully execute our 2010 capital program and set the stage for continued growth in 2011 and beyond;

3. Continue to pursue strategic and accretive acquisitions; and

4. Increase our annualized distribution level to $3.80 per unit by November 2010.

Our two internal qualitative goals included (i) the development and implementation of an optimal tax strategy/structure for our Canadian assets, and (ii) advancing multi-year programs and initiatives and prepare the organization for future growth.

In general, we substantially met or exceeded these six goals.

· Excluding the benefit of unforecasted acquisitions completed during the year, our adjusted EBITDA exceeded the high end of our original guidance for 2010;

· We timely and cost-effectively executed a $355 million expansion capital program, with delayed projects replaced by attractive new ones, and advanced and expanded our portfolio of organic growth projects, setting up a 2011 program of $550 million of high quality, solid return projects;

· We completed six acquisitions for aggregate consideration of approximately $410 million, which primarily consisted of pipeline and storage facilities that complemented our existing asset base and business activities;

· We increased our annualized distribution rate by 3.3% to $3.80 per common unit, while generating aggregate annual distribution coverage of approximately 111%;

· We initiated and completed the IPO of PNG, raising approximately $470 million of equity and debt proceeds and establishing a separate financing source for this entity with a significantly lower cost of equity capital;

· We developed, refined and implemented a strategy to optimize the tax structure of our Canadian operations, continued to expand, implement and develop our integrity management program and improved communication throughout the organization; and

· We raised approximately $700 million in both long-term debt and equity in two different transactions, renewed our $500 million hedged inventory facility and added a $500 million liquidity facility, both on favorable terms, and ended 2010 with a strong balance sheet, solid credit metrics and approximately $900 million of committed liquidity.

For 2010, the elements of compensation were applied as described below. Except as described below, no material additions or changes to these elements are contemplated for 2011.

Salary. No salary adjustments for Named Executive Officers were recommended or made in 2010. See “—Narrative Disclosure to Summary Compensation Table and Grants of Plan-Based Awards Table.”

Cash Bonuses. Based on the CEO’s annual performance review and the individual performance of each of our Named Executive Officers, the compensation committee recommended to the board of directors and the board of directors approved the annual bonuses reflected in the Summary Compensation Table and notes thereto. Such amounts take into account the performance relative to our 2010 goals; the absence of shortfalls relative to expectations; the level of difficulty associated with achieving such objectives; our

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relative positioning at the end of the year with respect to future growth and performance; the significant transactions or accomplishments for the period not included in the goals for the year; and our positioning at the end of the year with respect to our targeted credit profile. In the case of Mr. Duckett, the aggregate bonus amount represented 40% of his participation level for the first three fiscal quarters and an annual payment consisting of 60% of his participation for the first three quarters and 100% of his participation for the fourth quarter. For Mr. vonBerg, the aggregate bonus amount represented approximately 40% in annual bonus and 60% in quarterly bonus.

Long-Term Incentive Awards. Prior to 2010, the last full grant cycle of equity awards to Named Executive Officers occurred in 2007. The performance threshold for vesting in two-thirds of equity awards granted in 2007 has been met, and the third performance threshold of $4.00 is expected to be reached in 2012. Vesting under the 2007 awards is also subject to minimum service periods that extend to May 2011 and May 2012. Any of these phantom units that remain outstanding in May 2014 for which the performance thresholds have not been met will be forfeited.

Consistent with our policy of issuing new grants with extended time-vesting periods when attainment of the performance thresholds of existing grants has occurred or is anticipated in the near term, in 2010 the board of directors granted awards with a top performance threshold of $4.20 (annualized) distribution per common unit. These grants are intended to encourage continued growth and fundamental performance that will support future distribution growth. Phantom units granted in February 2010 will vest in respective one-third increments on the date on which we pay an annualized quarterly distribution of at least $3.90, $4.05 and $4.20 per common unit and the later of the May 2013, May 2014 and May 2015 distribution dates, respectively. Such awards have associated DERs that become payable in one-third increments upon achieving the referenced performance thresholds, without regard to the minimum service period. Phantom units granted in October 2010 will vest in 25% increments on the date on which we pay an annualized quarterly distribution of at least $3.90, $3.90, $4.05 and $4.20 per common unit and the later of the November 2012, May 2013, May 2014 and May 2015 distribution dates, respectively. Such awards have associated DERs that become payable 50%, 25% and 25% on the date on which we pay an annualized quarterly distribution of $3.90, $4.05 and $4.20, respectively. See “—Narrative Disclosure to Summary Compensation Table and Grants of Plan-Based Awards Table” and “—Application of Compensation Elements.”

Any of the 2010 phantom units that remain outstanding as of the May 2016 distribution date for which the performance thresholds have not been met will be forfeited. Upon vesting, the phantom units are payable on a one-for-one basis in common units. The 2010 awards included grants to our Named Executive Officers as follows: Mr. Armstrong, 180,000; Mr. Pefanis, 120,000; Mr. Swanson, 60,000; Mr. vonBerg, 54,000; Mr. Duckett, 75,000; and Mr. Rutherford, 100,000.

Transaction/Transition Grants. In September 2010, PAA entered into transaction/transition grant agreements with Messrs. Armstrong, Pefanis and Swanson, pursuant to which these individuals acquired phantom common units, phantom series A subordinated units and phantom series B subordinated units representing a portion of the limited partner interests of PNG issued to PAA in connection with PNG’s IPO. Distribution equivalent rights, payable by PAA in cash, were also granted with respect to the phantom common units and phantom series A subordinated units.

The phantom units will vest and be payable as follows: (i) the phantom common units will vest 50% on May 5, 2011 and 50% on May 5, 2012, and be payable one-for-one by PAA in Common Units of PNG; (ii) the phantom series A subordinated units will vest in connection with the conversion of the Series A Subordinated Units into Common Units, and be payable one-for-one by PAA in Common Units of PNG; and (iii) the phantom series B subordinated units will vest in tranches of 20%, 21%, 15%, 22% and 22%, respectively, in connection with the conversion of the First through Fifth Tranches of Series B Subordinated Units. Upon vesting, the phantom series B subordinated units will be payable one-for-one by PAA in Series A Subordinated Units or Common Units of PNG it receives upon conversion of the Series B Subordinated Units. Any phantom series A subordinated units and any phantom series B subordinated units that have not vested as of December 31, 2018 will be automatically cancelled on such date. The number of phantom units of each class or series granted by PAA to Messrs. Armstrong, Pefanis and Swanson is as follows: Mr. Armstrong, 62,000 each of phantom common units, phantom series A subordinated units and phantom series B subordinated units; Mr. Pefanis, 42,000 each of phantom common units, phantom series A subordinated units and phantom series B subordinated units; and Mr. Swanson, 21,000 each of phantom common units, phantom series A subordinated units and phantom series B subordinated units.

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Other Compensation Related Matters

Equity Ownership in PAA. As of December 31, 2010, our Named Executive Officers collectively owned substantial equity in the Partnership. Although we encourage our Named Executive Officers to acquire and retain ownership in the Partnership, we do not have a policy requiring maintenance of a specified equity ownership level. Our policies prohibit our Named Executive Officers from using puts, calls or options to hedge the economic risk of their ownership. As of December 31, 2010, our Named Executive Officers beneficially owned, in the aggregate, approximately 889,000 of our common units (excluding any unvested equity awards), an approximately 2.4% indirect ownership interest in our general partner and IDRs, and 121,000 Class B units of Plains AAP, L.P. Based on the market price of our common units at December 31, 2010 and an implied valuation for their collective general partner and IDR interests using similar valuation metrics, the value of the equity ownership of these individuals was significantly greater than the combined aggregate salaries and bonuses for 2010.

Recovery of Prior Awards. Except as provided by applicable laws and regulations, we do not have a policy with respect to adjustment or recovery of awards or payments if relevant company performance measures upon which previous awards were based are restated or otherwise adjusted in a manner that would reduce the size of such award or payment.

Section 162(m). With respect to the deduction limitations under Section 162(m) of the Code, we are a limited partnership and do not meet the definition of a “corporation” under Section 162(m).

Change in Control Triggers. The employment agreements for Messrs. Armstrong and Pefanis, the long-term incentive plan grants to our Named Executive Officers, and the Class B restricted units agreements include severance payment provisions or accelerated vesting triggered upon a change of control, as defined in the respective agreement. In the case of the long-term incentive plan grants and transaction/transition grants, the provision becomes operative only if the change in control is accompanied by a change in status (such as the termination of employment by Plains All American GP LLC). We believe this “double trigger” arrangement is appropriate because it provides assurance to the executive, but does not offer a windfall to the executive when there has been no real change in employment status. The provisions in the employment agreements for Messrs. Armstrong and Pefanis become operative only if the executive terminates employment within three months of the change in control. Messrs. Armstrong and Pefanis agreed to a conditional waiver of these provisions with respect to Vulcan Energy’s sale of its 50.1% general partner interest in December 2010. The Class B restricted units agreements generally call for vesting (upon a change in control) of any units that have already been earned, plus the next increment of units that could be earned at the next distribution threshold. Any remaining Class B restricted units would be forfeited (unless waived at the discretion of the general partner or acquirer as the case may be). As a result of significant participation by existing general partner owners or their affiliates in the December 2010 sale of Vulcan Energy’s 50.1% ownership in the general partner, the change of control provisions of the Class B restricted units agreements were not triggered. See “—Employment Contracts” and “—Potential Payments upon Termination or Change-in-Control.” The provision of severance or equity acceleration for certain terminations and change of control help to create a retention tool by assuring the executive that the benefit of the employment arrangement will be at least partially realized despite the occurrence of an event that would materially alter the employment arrangement.

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Relation of Compensation Policies and Practices to Risk Management

Our compensation policies and practices are designed to provide rewards for short-term and long-term performance, both on an individual basis and at the entity level. In general, optimal financial and operational performance, particularly in a competitive business, requires some degree of risk-taking. Accordingly, the use of compensation as an incentive for performance can foster the potential for management and others to take unnecessary or excessive risks to reach the performance thresholds. For us, such risks would primarily attach to certain commercial activities conducted in our supply and logistics segment as well as to the execution of capital expansion projects and acquisitions and the realization of associated returns.

From a risk management perspective, our policy is to conduct our commercial activities within pre-defined risk parameters that are closely monitored and are structured in a manner intended to control and minimize the potential for unwarranted risk-taking. See “Impact of Commodity Price Volatility and Dynamic Market Conditions on Our Business Model; Risk Management” in Part I of this annual report. We also routinely monitor and measure the execution and performance of our capital projects and acquisitions relative to expectations.

Our compensation arrangements contain a number of design elements that serve to minimize the incentive for unwarranted risk-taking to achieve short-term, unsustainable results, including delaying the reward and subjecting such rewards to forfeiture for terminations related to violations of our risk management policies and practices or of our code of conduct. See “Compensation Discussion and Analysis—Relation of Compensation Elements to Compensation Objectives.”

In combination with our risk-management practices, we do not believe that risks arising from our compensation policies and practices for our employees are reasonably likely to have a material adverse effect on us.

Summary Compensation Table

The following table sets forth certain compensation information for our Chief Executive Officer, Chief Financial Officer, and the four other most highly compensated executive officers in 2010 (our “Named Executive Officers”). We reimburse our general partner and its affiliates for expenses incurred on our behalf, including the costs of officer compensation (excluding the costs of the obligations represented by the Class B units). Mr. Rutherford joined PAA on October 1, 2010. Therefore, his salary and bonus amounts reflect a partial year of payment.

Name and Principal Position	Year	Salary ($)	Bonus ($)	Stock Awards ($)(1)	All Other Compensation ($)(2)	Total ($)

Greg L. Armstrong	2010	375,000	3,250,000	5,868,436	15,900	9,509,336
Chairman and CEO	2009	375,000	3,000,000	—	15,800	3,390,800
	2008	375,000	2,900,000	—	14,775	3,289,775

Harry N. Pefanis	2010	300,000	3,100,000	3,946,511	15,900	7,362,411
President and Chief Operating Officer	2009	300,000	2,900,000	—	15,800	3,215,800
	2008	300,000	2,800,000	—	14,775	3,114,775

Al Swanson	2010	250,000	1,100,000	1,973,255	15,900	3,339,155
Executive Vice President and	2009	250,000	1,000,000	376,483	15,763	1,642,246
Chief Financial Officer	2008	180,000	700,000	—	14,502	894,502

W. David Duckett(3)	2010	276,927	3,625,092	1,119,153	98,079	5,119,251
President—Plains Midstream	2009	251,058	3,378,240	—	83,643	3,712,941
	2008	268,095	2,915,424	—	88,831	3,272,350

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John P. vonBerg	2010	250,000	3,265,000	(4)	805,790	15,900	4,336,690
Senior Vice President—	2009	250,000	3,220,000	(4)	—	15,800	3,485,800
Commercial Activities	2008	200,000	2,740,000	(4)	—	14,580	2,954,580

John R. Rutherford	2010	62,500	325,000		4,548,447	300	4,936,247
Executive Vice President

(1) Grant date fair values are presented for (i) transaction/transition grants awarded to Messrs. Armstrong, Pefanis and Swanson, (ii) LTIP phantom unit grants awarded to Messrs. Armstrong, Pefanis, Swanson, Duckett, vonBerg and Rutherford, and (iii) Class B units for Mr. Rutherford. Dollar amounts represent the aggregate grant date fair value of transaction/transition grants, phantom units and Class B units awarded during each year based on the probable outcome of underlying performance conditions pursuant to FASB ASC Topic 718. For transaction/transition grants awarded in 2010, vesting of 100% of the phantom common units and phantom series A subordinated units, and vesting of 20% of the phantom series B subordinated units, was deemed probable of occurrence on the grant date. For phantom units granted in 2009 and 2010, the performance threshold for the first tranche (first two tranches for Mr. Rutherford) of vesting was deemed probable of occurrence as of the grant date. For Class B units awarded in 2010, the first tranche of vesting was deemed probable of occurrence on the grant date. The maximum grant date fair values of stock awards assuming that the highest level of performance conditions will be met are as follows:

Name	Year	Maximum Grant Date Fair Value ($)
Greg L. Armstrong	2010	12,229,929
	2009	—
	2008	—

Harry N. Pefanis	2010	8,198,147
	2009	—
	2008	—

Al Swanson	2010	4,099,073
	2009	1,129,450
	2008	—

W. David Duckett	2010	3,357,459
	2009	—
	2008	—

John P. vonBerg	2010	2,417,371
	2009	—
	2008	—

John R. Rutherford	2010	9,864,378

(2) Plains All American GP LLC matches 100% of employees’ contributions to its 401(k) plan in cash, subject to certain limitations in the plan. All Other Compensation for each of Messrs. Armstrong, Pefanis, Swanson and vonBerg includes $14,700 in such contributions for 2010. The remaining amount for each represents premium payments on behalf of such Named Executive Officer for group term life insurance. All Other Compensation for Mr. Duckett includes, for 2010, employer contributions to the Plains Midstream Canada savings plan of $36,000, group term life insurance premiums of $21,143, automobile lease payments of $30,849 and club dues of $10,087.

(3) Salary, bonus and all other compensation amounts for Mr. Duckett are presented in U.S. dollar equivalent based on the exchange rates in effect on the dates payments were made or approved.

(4) Includes quarterly bonuses aggregating $1,865,000, $1,920,000 and $1,440,000 and annual bonuses of $1,400,000, $1,300,000 and $1,300,000 in 2010, 2009 and 2008, respectively. The annual bonuses are payable 60% at the time of award and 20% in each of the two succeeding years.

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Grants of Plan-Based Awards Table

The following table sets forth summary information regarding all grants of plan-based awards made to our Named Executive Officers during the fiscal year ended December 31, 2010.

		All Other
		Stock
		Awards:		Grant Date
		Number Of		Fair Value Of
		Shares Of		Stock and
		Stock or		Option
	Grant	Units		Awards
Name	Date	(#)		($)(7)
Greg L. Armstrong	2/18/10	180,000	(1)	2,685,967
	9/9/10	62,000	(2)	1,467,540
	9/9/10	62,000	(3)	1,467,540
	9/9/10	62,000	(4)	247,389

Harry N. Pefanis	2/18/10	120,000	(1)	1,790,645
	9/9/10	42,000	(2)	994,140
	9/9/10	42,000	(3)	994,140
	9/9/10	42,000	(4)	167,586

Al Swanson	2/18/10	60,000	(1)	895,322
	9/9/10	21,000	(2)	497,070
	9/9/10	21,000	(3)	497,070
	9/9/10	21,000	(4)	83,793

W. David Duckett	2/18/10	75,000	(1)	1,119,153

John P. vonBerg	2/18/10	54,000	(1)	805,790

John R. Rutherford	10/1/10	100,000	(5)	2,821,611
	10/1/10	10,000	(6)	1,726,836

(1) The phantom units will vest (become payable 1-for-1 of our common units) as follows: (i) one-third will vest upon the later of the May 2013 distribution date and the date we pay a quarterly distribution of at least $0.975 ($3.90 annualized), (ii) one third will vest upon the later of the May 2014 distribution date and the date we pay a quarterly distribution of at least $1.0125 ($4.05 annualized), and (iii) one-third will vest upon the later of the May 2015 distribution date and the date we pay a quarterly distribution of at least $1.05 ($4.20 annualized). The phantom units include tandem distribution equivalent rights that vest (distributions become payable as if the underlying common unit were owned) in one-third increments on the dates we pay a quarterly distribution of $0.975 ($3.90 annualized), $1.0125 ($4.05 annualized) and $1.05 ($4.20 annualized), respectively. Any phantom units (and all associated DERs) that have not vested as of the May 2016 distribution date will be forfeited.

(2) These phantom common units will vest 50% on May 5, 2011 and 50% on May 5, 2012, and be payable one-for-one by PAA in Common Units of PNG.

(3) These phantom series A subordinated units will vest in connection with the conversion of PNG’s Series A Subordinated Units into Common Units, and be payable one-for-one by PAA in Common Units of PNG. Any of these phantom series A subordinated units that have not vested as of December 31, 2018 will be automatically cancelled on such date.

(4) These phantom series B subordinated units will vest in increments of 20%, 21%, 15%, 22% and 22%, respectively, in connection with the conversion of the First through Fifth Tranches of PNG’s Series B Subordinated Units. Upon vesting, the phantom series B subordinated units will be payable one-for-one by PAA in Series A Subordinated Units or Common Units of PNG it receives upon

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conversion of PNG’s Series B Subordinated Units. Any of these phantom series B subordinated units that have not vested as of December 31, 2018 will be automatically cancelled on such date.

(5) These phantom units will vest (become payable 1-for-1 of our common units) as follows: (i) 25% will vest upon the later of the November 2012 distribution date and the date we pay a quarterly distribution of at least $0.975 ($3.90 annualized), (ii) 25% will vest upon the later of the May 2013 distribution date and the date we pay a quarterly distribution of at least $0.975 ($3.90 annualized), (iii) 25% will vest upon the later of the May 2014 distribution date and the date we pay a quarterly distribution of $1.0125 ($4.05 annualized), and (iv) 25% will vest upon the later of the May 2015 distribution date and the date we pay a quarterly distribution of at least $1.05 ($4.20 annualized). These phantom units include distribution equivalent rights that vest (distributions become payable as if the underlying common unit were owned) 50%, 25% and 25%, respectively, on the dates we pay a quarterly distribution of $0.975 ($3.90 annualized), $1.0125 ($4.05 annualized) and $1.05 ($4.20 annualized). Any phantom units (and all associated DERs) that have not vested as of the May 2016 distribution date will be forfeited.

(6) These Class B units become “earned” (entitled to participate in distributions) in 25% increments 180 days after we pay annualized quarterly distributions on our common units that equal or exceed $3.90, $4.05, $4.20 and $4.50. To encourage retention following achievement of these performance benchmarks, Plains AAP, L.P. retained a call right to purchase any earned Class B units at a discount to fair market value that is exercisable upon the termination of the holder’s employment with Plains All American GP LLC and its affiliates (subject to certain exceptions) prior to January 1, 2017. A portion of the Class B units will vest (no longer be subject to the call right) upon a change of control. All earned Class B units will also vest if they remain outstanding as of January 1, 2017 or Plains AAP, L.P. elects not to timely exercise its call right.

(7) Represents the grant date fair value of phantom units, transaction/transition grants and Class B units based on the probable outcome of underlying performance conditions pursuant to FASB ASC Topic 718. The performance threshold for the first one-third (first 50% for Mr. Rutherford) vesting of phantom units was deemed probable of occurrence as of the grant date. For transaction/transition grants awarded in 2010, vesting of 100% of the phantom common units and phantom series A subordinated units, and vesting of 20% of the phantom series B subordinated units, was deemed probable of occurrence on the grant date. For Class B units awarded in 2010, the first tranche of vesting was deemed probable of occurrence on the grant date. The maximum grant date fair value of plan-based awards granted in 2010 is set forth below:

Name	Grant Date	Quantity (#)	Maximum Grant Date Fair Value ($)
Armstrong	2/18/10	180,000	8,057,902
	9/9/10	62,000	1,467,540
	9/9/10	62,000	1,467,540
	9/9/10	62,000	1,236,947

Pefanis	2/18/10	120,000	5,371,935
	9/9/10	42,000	994,140
	9/9/10	42,000	994,140
	9/9/10	42,000	837,932

Swanson	2/18/10	60,000	2,685,967
	9/9/10	21,000	497,070
	9/9/10	21,000	497,070
	9/9/10	21,000	418,966

Duckett	2/18/10	75,000	3,357,459

vonBerg	2/18/10	54,000	2,417,371

Rutherford	10/1/10	100,000	5,643,223
	10/1/10	10,000	4,221,155

Narrative Disclosure to Summary Compensation Table and Grants of Plan-Based Awards Table

A discussion of 2010 salaries and bonuses and how they fit into the overall compensation array is included in “—Compensation Discussion and Analysis.” The following is a discussion of other material factors necessary to an understanding of the information disclosed in the Summary Compensation Table and Grants of Plan-Based Awards Table above.

Salary—As discussed in this Item 11, we do not make systematic annual adjustments to the salaries of our Named Executive Officers. In that regard, no salary adjustments were made for any of our Named Executive Officers in 2010.

Grants of Plan-Based Awards—In 2010, our Named Executive Officers were awarded the following phantom units under our LTIP: Mr. Armstrong, 180,000; Mr. Pefanis, 120,000; Mr. Swanson, 60,000; Mr. Duckett, 75,000; Mr. vonBerg, 54,000; and Mr. Rutherford, 100,000. The board of directors determined in its discretion that, in light of the service period and performance threshold requirements for vesting of the phantom units, the number of units granted to each of the Named Executive Officers was adequate to create an incentive for both retention and performance.

Transaction/Transition Grants—In September 2010, Messrs. Armstrong, Pefanis and Swanson received the following transaction/transition grants from PAA: Mr. Armstrong, 62,000 each of phantom common units, phantom series A subordinated units and phantom series B subordinated units; Mr. Pefanis, 42,000 each of phantom common units, phantom series A subordinated units and phantom series B subordinated units; and Mr. Swanson, 21,000 each of phantom common units, phantom series A subordinated units and phantom series B subordinated units. Upon vesting, these phantom units will be payable one-for-one by PAA in Common Units or Series A Subordinated Units of PNG.

Class B Units—In connection with his employment with us in October 2010, Mr. Rutherford received a grant of 10,000 Class B units of Plains AAP, L.P.

Employment Contracts

Mr. Armstrong is employed as Chairman and Chief Executive Officer. The initial three-year term of Mr. Armstrong’s employment agreement commenced on June 30, 2001, and is automatically extended

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for one year on June 30 of each year (such that the term is reset to three years) unless Mr. Armstrong receives notice from the chairman of the compensation committee that the board of directors has elected not to extend the agreement. Mr. Armstrong has agreed, during the term of the agreement and for five years thereafter, not to disclose (subject to typical exceptions, including, but not limited to, requirement of law or prior disclosure by a third party) any confidential information obtained by him while employed under the agreement. The agreement provided for a base salary of $330,000 per year, subject to annual review. In 2005, Mr. Armstrong’s annual salary was increased to $375,000.

Mr. Pefanis is employed as President and Chief Operating Officer. The initial three-year term of Mr. Pefanis’ employment agreement commenced on June 30, 2001, and is automatically extended for one year on June 30 of each year (such that the term is reset to three years) unless Mr. Pefanis receives notice from the Chairman of the Board that the board of directors has elected not to extend the agreement. Mr. Pefanis has agreed, during the term of the agreement and for one year thereafter, not to disclose (subject to typical exceptions) any confidential information obtained by him while employed under the agreement. The agreement provided for a base salary of $235,000 per year, subject to annual review. In 2005, Mr. Pefanis’ annual salary was increased to $300,000.

In connection with Mr. Rutherford’s employment in October 2010, Plains All American GP LLC and Mr. Rutherford entered into an agreement setting forth the terms of his employment. The agreement, which may be terminated by either party at any time, provides for a base salary of $250,000 per year, and a minimum bonus for 2010, 2011 and 2012 of $1 million (subject to proration for 2010). Plains All American GP LLC’s obligation to pay the minimum bonus is subject to Mr. Rutherford’s continued employment through the bonus payment date, unless his failure to remain employed results from a change in status, as defined in the employment agreement. Mr. Rutherford also entered into an ancillary agreement pursuant to which he has agreed to maintain confidentiality for a period of two years following termination of his employment and not to solicit customers and assets for a period of one year following termination of his employment.

See “—Compensation Discussion and Analysis” for a discussion of how we use salary and bonus to achieve compensation objectives. See “—Potential Payments upon Termination or Change-In-Control” for a discussion of the provisions in Messrs. Armstrong’s and Pefanis’ employment agreements related to termination, change of control and related payment obligations.

Outstanding Equity Awards at Fiscal Year-End

The following table sets forth certain information regarding outstanding equity awards at December 31, 2010 with respect to our Named Executive Officers:

	Unit Awards
Name	Number of Shares or Units of Stock That Have Not Vested (#)		Market Value of Shares or Units of Stock That Have Not Vested ($)(1)		Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested (#)		Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested ($)(1)
Greg L. Armstrong	120,000	(2)		7,534,800	60,000	(2)		3,767,400
	20,000	(3)		5,382,400	20,000	(3)		3,375,600
	—		—		180,000	(5)		11,302,200
	62,000	(6)		1,545,660	62,000	(7)		1,545,660
					62,000	(8)		1,545,660

Harry N. Pefanis	80,000	(2)		5,023,200	40,000	(2)		2,511,600
	15,000	(3)		4,036,800	15,000	(3)		2,531,700
	—		—		120,000	(5)		7,534,800
	42,000	(6)		1,047,060	42,000	(7)		1,047,060
					42,000	(8)		1,047,060

Al Swanson	22,000	(2)		1,381,380	11,000	(2)		690,690
	11,666	(4)		732,508	23,334	(4)		1,465,142
	2,500	(3)		692,675	7,500	(3)		1,496,825
	—		—		60,000	(5)		3,767,400
	21,000	(6)		523,530	21,000	(7)		523,530
					21,000	(8)		523,530

W. David Duckett	50,000	(2)		3,139,500	25,000	(2)		1,569,750
	4,250	(3)		1,177,548	12,750	(3)		2,544,602
	—		—		75,000	(5)		4,709,250

John P. vonBerg	36,000	(2)		2,260,440	18,000	(2)		1,130,220
	7,000	(3)		1,883,840	7,000	(3)		1,181,460
	—		—		54,000	(5)		3,390,660

John R. Rutherford	—		—		100,000	(9)		6,279,000
	—		—		10,000	(10)		4,221,155

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(1) Market value of phantom units reported in these columns is calculated by multiplying the closing market price ($62.79) of our common units at December 31, 2010 (the last trading day of the fiscal year) by the number of units. Market value of transaction/transition grants reported in these columns is calculated by multiplying the closing market price ($24.93) of PNG’s common units at December 31, 2010 (the last trading day of the fiscal year) by the number of units. No discount is applied for remaining performance threshold or service period requirements. The Class B units are valued based on the grant date fair value computed in accordance with FASB ASC Topic 718 assuming that the highest level of performance conditions will be met.

(2) These phantom units will vest in one-third increments as follows: one-third will vest upon the May 2011 distribution date; one-third will vest upon the later of the May 2011 distribution date and the date on which we pay a quarterly distribution of at least $1.00; and one-third will vest upon the May 2012 distribution date. The first 75% of DERs associated with these units is currently payable. The remaining 25% becomes payable upon achieving a quarterly distribution level of $1.00 per unit. Any phantom units that have not vested (and all associated DERs) as of the May 2014 distribution date will expire.

(3) Each Class B unit represents a “profits interest” in Plains AAP, L.P., which entitles the holder to participate in future profits and losses from operations, current distributions from operations, and an interest in future appreciation or depreciation in Plains AAP, L.P.’s asset values, but does not represent an interest in the capital of Plains AAP, L.P. on the applicable grant date of the Class B units. As of December 31, 2010, 50% of the Class B units held by Messrs. Armstrong, Pefanis and vonBerg had been earned, and 25% of the Class B units held by Messrs. Swanson and Duckett had been earned. None of the Class B units have vested. For additional information regarding the Class B units, please read Item 13. “Certain Relationships and Related Transactions, and Director Independence—Our General Partner—Class B Units of Plains AAP, L.P.”

(4) These phantom units will vest in one-third increments as follows: one-third will vest upon the May 2011 distribution date, one-third will vest upon the later of the May 2012 distribution date and the date on which we pay a quarterly distribution of at least $1.00, and one-third will vest upon the later of the May 2013 distribution date and the date on which we pay a quarterly distribution of at least $1.0625. Two-thirds of the DERs associated with these units are currently payable. The remaining one-third becomes payable upon achieving a quarterly distribution level of $1.00 per unit. Any phantom units that have not vested (and all associated DERs) as of the May 2015 distribution date will expire.

(5) These phantom units will vest in one-third increments as follows: one-third will vest upon the later of the May 2013 distribution date and the date on which we pay a quarterly distribution of at least $0.975, one-third will vest upon the later of the May 2014 distribution date and the date on which we pay a quarterly distribution of at least $1.0125, and one-third will vest upon the later of the May 2015 distribution date and the date on which we pay a quarterly distribution of at least $1.05. The DERs associated with these units become payable in one-third increments upon achieving quarterly distribution levels of $0.975, $1.0125 and $1.05 per unit. Any phantom units that have not vested (and all associated DERs) as of the May 2016 distribution date will expire.

(6) These phantom common units will vest 50% on May 5, 2011 and 50% on May 5, 2012, and be payable one-for-one by PAA in Common Units of PNG.

(7) These phantom series A subordinated units will vest in connection with the conversion of PNG’s Series A Subordinated Units into PNG Common Units, and be payable one-for-one by PAA in Common Units of PNG. Any of these phantom series A subordinated units that have not vested as of December 31, 2018 will be automatically cancelled on such date.

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(8) These phantom series B subordinated units will vest in increments of 20%, 21%, 15%, 22% and 22%, respectively, in connection with the conversion of the First through Fifth Tranches of PNG’s Series B Subordinated Units. Upon vesting, the phantom series B subordinated units will be payable one-for-one by PAA in Series A Subordinated Units or Common Units of PNG it receives upon conversion of PNG’s Series B Subordinated Units. Any of these phantom series B subordinated units that have not vested as of December 31, 2018 will be automatically cancelled on such date.

(9) These phantom units will vest as follows: (i) 25% will vest upon the later of the November 2012 distribution date and the date we pay a quarterly distribution of at least $0.975 ($3.90 annualized), (ii) 25% will vest upon the later of the May 2013 distribution date and the date we pay a quarterly distribution of at least $0.975 ($3.90 annualized), (iii) 25% will vest upon the later of the May 2014 distribution date and the date we pay a quarterly distribution of $1.0125 ($4.05 annualized), and (iv) 25% will vest upon the later of the May 2015 distribution date and the date we pay a quarterly distribution of at least $1.05 ($4.20 annualized). The DERs associated with these phantom units vest 50%, 25% and 25%, respectively, on the dates we pay a quarterly distribution of $0.975 ($3.90 annualized), $1.0125 ($4.05 annualized) and $1.05 ($4.20 annualized). Any phantom units (and all associated DERs) that have not vested as of the May 2016 distribution date will be forfeited.

(10) These Class B units become “earned” (entitled to participate in distributions) in 25% increments 180 days after we pay annualized quarterly distributions on our common units that equal or exceed $3.90, $4.05, $4.20 and $4.50. To encourage retention following achievement of these performance benchmarks, Plains AAP, L.P. retained a call right to purchase any earned Class B units at a discount to fair market value that is exercisable upon the termination of the holder’s employment with Plains All American GP LLC and its affiliates (subject to certain exceptions) prior to January 1, 2017. A portion of the Class B units will vest (no longer be subject to the call right) upon a change of control. All earned Class B units will also vest if they remain outstanding as of January 1, 2017 or Plains AAP, L.P. elects not to timely exercise its call right.

Option Exercises and Units Vested

The following table sets forth certain information regarding the vesting of phantom units during the fiscal year ended December 31, 2010 with respect to our Named Executive Officers.

	Unit Awards
Name	Number of Units Acquired on Vesting (#)(1)	Value Realized on Vesting ($)(1)
Greg L. Armstrong	120,000	6,826,800
Harry N. Pefanis	80,000	4,551,200
Al Swanson	17,000	967,130
W. David Duckett	39,175	2,228,666
John P. vonBerg	28,675	1,631,321
John R. Rutherford	—	—

(1) Represents the gross number and value of phantom units that vested during the year ended December 31, 2010. The actual number of units delivered was net of income tax withholding. Consistent with the terms of our 2005 Long-Term Incentive Plan, the value realized upon vesting is computed by multiplying the closing market price ($56.89) of our common units on May 13, 2010 (the date preceding the vesting date) by the number of units that vested.

Pension Benefits

We sponsor a 401(k) plan that is available to all U.S. employees, but we do not maintain a pension or defined benefit program.

Nonqualified Deferred Compensation and Other Nonqualified Deferred Compensation Plans

We do not have a nonqualified deferred compensation plan or program for our officers or employees.

Potential Payments upon Termination or Change-in-Control

The following table sets forth potential amounts payable to the Named Executive Officers upon termination of employment under various circumstances, and as if terminated on December 31, 2010.

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	By Reason of Death ($)		By Reason of Disability ($)		By Company without Cause ($)		By Executive with Good Reason ($)		In Connection with a Change In Control ($)
Greg L. Armstrong
Salary and Bonus	7,550,000	(1)	7,550,000	(1)	7,550,000	(1)	7,550,000	(1)	11,325,000	(2)
Equity Compensation	18,470,052	(3)	18,470,052	(3)	24,150,060	(4)	22,604,400	(4)	27,241,380	(5)
Health Benefits	N/A		41,394	(6)	41,394	(6)	41,394	(6)	41,394	(6)
Tax Gross-up	N/A		N/A		N/A		N/A		961,462	(7)
Class B Units	N/A		N/A		N/A		N/A		7,835,800	(8)
Total	26,020,052		26,061,446		31,741,454		30,195,794		47,405,036

Harry N. Pefanis
Salary and Bonus	7,000,000	(1)	7,000,000	(1)	7,000,000	(1)	7,000,000	(1)	10,500,000	(2)
Equity Compensation	12,349,932	(3)	12,349,932	(3)	16,116,660	(4)	15,069,600	(4)	18,210,780	(5)
Health Benefits	N/A		41,394	(6)	41,394	(6)	41,394	(6)	41,394	(6)
Tax Gross-up	N/A		N/A		N/A		N/A		1,082,710	(7)
Class B Units	N/A		N/A		N/A		N/A		5,876,850	(8)
Total	19,349,932		19,391,326		23,158,054		22,110,994		35,711,734

Al Swanson (9)
Equity Compensation	5,944,778	(3)	5,944,778	(3)	2,637,418	(4)	N/A		9,607,710	(5)
Class B Units	N/A		N/A		N/A		N/A		1,958,950	(8)
Total	5,944,778		5,944,778		2,637,418		N/A		11,566,660

W. David Duckett (9)
Equity Compensation	6,279,000	(3)	6,279,000	(3)	3,139,500	(4)	N/A		9,418,500	(5)
Class B Units	N/A		N/A		N/A		N/A		3,330,215	(8)
Total	6,279,000		6,279,000		3,139,500		N/A		12,748,715

John P. vonBerg (9)
Equity Compensation	4,520,880	(3)	4,520,880	(3)	2,260,440	(4)	N/A		6,781,320	(5)
Class B Units	N/A		N/A		N/A		N/A		2,742,530	(8)
Total	4,520,880		4,520,880		2,260,440		N/A		9,523,850

John R. Rutherford
Bonus	N/A		N/A		2,250,000	(10)	2,250,000	(10)	N/A
Equity Compensation	3,139,500	(3)	3,139,500	(3)	N/A		N/A		1,569,750	(5)
Class B Units	N/A		N/A		N/A		N/A		1,726,825	(8)
Total	3,139,500		3,139,500		2,250,000		2,250,000		3,296,575

(1) The employment agreements between Plains All American GP LLC and Messrs. Armstrong and Pefanis provide that if (i) their employment with Plains All American GP LLC is terminated as a result of their death, (ii) they terminate their employment with Plains All American GP LLC (a) because of a disability (as defined in Section 409A of the Code) or (b) for good reason (as defined below), or (iii) Plains All American GP LLC terminates their employment without cause (as defined below), they are entitled to a lump-sum amount equal to the product of (1) the sum of their (a) highest annual base salary paid prior to their date of termination and (b) highest annual bonus paid or payable for any of the three years prior to the date of termination, and (2) the lesser of (i) two or (ii) the number of days remaining in the term of their employment agreement divided by 360. The amount provided in the table assumes for each executive a termination date of December 31, 2010, and also assumes a highest annual base salary of $375,000 and highest annual bonus of $3,400,000 for Mr. Armstrong, and a highest annual base salary of $300,000 and highest annual bonus of $3,200,000 for Mr. Pefanis.

The employment agreements between Plains All American GP LLC and Messrs. Armstrong and Pefanis define “cause” as (i) willfully engaging in gross misconduct, or (ii) conviction of a felony involving moral turpitude. Notwithstanding, no act, or failure to act, on their part is “willful” unless done, or omitted to be done, not in good faith and without reasonable belief that such act or omission was in the best interest of Plains All American GP LLC or otherwise likely to result in no material injury to Plains All American GP LLC. However, neither Mr. Armstrong or Mr. Pefanis will be deemed to have been terminated for cause unless and until there is delivered to them a copy of a resolution of the board of directors of Plains All American GP LLC at a meeting held for that purpose (after reasonable notice and an opportunity to be heard), finding that Mr. Armstrong or Mr. Pefanis, as applicable, was guilty of the conduct described above, and specifying the basis for that finding. If Mr. Armstrong or Mr. Pefanis were terminated for cause, Plains All American GP LLC would be obligated to pay base salary through the date of termination, with no other payment obligations triggered by the termination under the employment agreement or other employment arrangement.

The employment agreements between Plains All American GP LLC and Messrs. Armstrong and Pefanis define “good reason” as the occurrence of any of the following circumstances: (i) removal by Plains All American GP LLC from, or failure to re-elect them to, the positions to which

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Messrs. Armstrong and Pefanis were appointed pursuant to their respective employment agreements, except in connection with their termination for cause (as defined above); (ii) (a) a reduction in their rate of base salary (other than in connection with across-the-board salary reductions for all executive officers of Plains All American GP LLC) unless such reduction reduces their base salary to less than 85% of their current base salary, (b) a material reduction in their fringe benefits, or (c) any other material failure by Plains All American GP LLC to comply with its obligations under their employment agreements to pay their annual salary and bonus, reimburse their business expenses, provide for their participation in certain employee benefit plans and arrangements, furnish them with suitable office space and support staff, or allow them no less than 15 business days of paid vacation annually; or (iii) the failure of Plains All American GP LLC to obtain the express assumption of the employment agreements by a successor entity (whether direct or indirect, by purchase, merger, consolidation or otherwise) to all or substantially all of the business and/or assets of Plains All American GP LLC.

(2) Pursuant to their employment agreements, if Messrs. Armstrong and Pefanis terminate their employment with Plains All American GP LLC within three (3) months of a change in control (as defined below), they are entitled to a lump-sum payment in an amount equal to the product of (i) three and (ii) the sum of (a) their highest annual base salary previously paid to them and (b) their highest annual bonus paid or payable for any of the three years prior to the date of such termination. The amount provided in the table assumes a change in control and termination date of December 31, 2010, and also assumes a highest annual base salary of $375,000 and highest annual bonus of $3,400,000 for Mr. Armstrong, and a highest annual base salary of $300,000 and highest annual bonus of $3,200,000 for Mr. Pefanis.

For this purpose a “change in control” is currently defined in their employment agreements to mean (i) the acquisition by a person or group (other than Vulcan Energy or a wholly owned subsidiary thereof) of beneficial ownership, directly or indirectly, of 50% or more of the membership interest of Plains All American GP LLC or (ii) the owners of the membership interests of Plains All American GP LLC on June 30, 2001 ceasing to beneficially own, directly or indirectly, more than 50% of the membership interests of Plains All American GP LLC.

In August 2005, Vulcan Energy increased its interest in Plains All American GP LLC from approximately 44% to greater than 50%. The consummation of the transaction constituted a change in control under the employment agreements with Messrs. Armstrong and Pefanis. However, Messrs. Armstrong and Pefanis entered into agreements with Plains All American GP LLC waiving their rights to payments under their employment agreements in connection with the change in control, contingent on the execution and performance by Vulcan Energy of a voting agreement with Plains All American GP LLC that restricted certain of Vulcan’s voting rights. Upon a breach, termination, or notice of termination of the voting agreement by Vulcan Energy these waivers will automatically terminate and a change in control would be deemed to have occurred. In connection with the December 2010 sale by Vulcan Energy of its interest in our general partner, this voting agreement was terminated and Messrs. Armstrong and Pefanis executed new waiver agreements.

(3) The letters evidencing phantom unit grants to our Named Executive Officers between 2007 and 2010 provide that in the event of their death or disability (as defined below), all of their then outstanding phantom units and associated DERs will be deemed nonforfeitable, and (i) any unvested phantom units that had satisfied all of the vesting criteria as of the date of their termination but for the passage of time would vest on the next following distribution date and (ii) the remaining unvested outstanding phantom units will vest on the distribution date on which the vesting criteria is met. For this purpose “disability” means a physical or mental infirmity that impairs the ability substantially to perform duties for a period of eighteen (18) months or that the general partner otherwise determines constitutes a disability.

The dollar value amount provided assumes the death or disability occurred on December 31, 2010. As a result, all phantom units and the associated DERs of our Named Executive Officers would

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have become nonforfeitable effective as of December 31, 2010, and vested on February 14, 2011 to the extent the vesting criteria had been satisfied (other than the passage of time) or, if the vesting criteria had not been satisfied, at the times described in the footnotes to the Outstanding Equity Awards at Fiscal Year-End table. For the 2007, 2009 and 2010 grants, any units not vested by May 2014, May 2015 and May 2016, respectively, would expire. That portion of the dollar value given that is attributable to PAA phantom units assumes that all performance thresholds will be timely achieved if deemed probable of occurrence as of December 31, 2010, and is based on the market value of PAA’s common units on December 31, 2010 ($62.79 per unit) without discount for service period. If the performance thresholds were not deemed probable of occurrence as of December 31, 2010, the units are assumed to expire unvested in May 2015 or May 2016. At December 31, 2010, an annualized distribution level of $4.00 was deemed probable of occurrence. All outstanding 2007 grants, two-thirds of the 2009 grants and one-third of the 2010 grants (50% for Mr. Rutherford) were assumed to eventually vest as a result.

The transaction/transition grant agreements provide that in the event of death or disability (as defined above), any unvested phantom units and associated DERs shall be deemed nonforfeitable and shall vest or be cancelled at the times described in the footnotes to the Outstanding Equity Awards at Fiscal Year-End Table. As of December 31, 2010, vesting of all of the phantom common units and phantom series A subordinated units, and vesting of 20% of the phantom series B subordinated units, was deemed probable of occurrence. That portion of the dollar value given that is attributable to the transaction/transition grants is based on the market value of PNG’s common units on December 31, 2010 ($24.93 per unit), without discount for service period.

(4) Pursuant to the phantom unit grants to our Named Executive Officers between 2007 and 2010, in the event their employment is terminated other than in connection with a change of control (as defined in Footnote 5 below) or by reason of death, disability (as defined in Footnote 3 above) or retirement, all of the phantom units and associated DERs (regardless of vesting) then outstanding under such phantom unit grants would automatically be forfeited as of the date of termination; provided, however, that if Plains All American GP LLC terminated their employment other than for cause (as defined in Footnote 5 below), any unvested phantom units that had satisfied all of the vesting criteria as of the date of their termination but for the passage of time would be deemed nonforfeitable and would vest on the next following distribution date. The dollar value amount provided assumes that our Named Executive Officers were terminated without cause on December 31, 2010. As a result, two-thirds of the 2007 phantom unit grants and one-third of the 2009 phantom unit grants held by our Named Executive Officers would be deemed nonforfeitable and would vest on the February 2011 distribution date. The remaining one-third of the outstanding 2007 phantom unit grants, two-thirds of the 2009 phantom unit grants and all of the 2010 phantom unit grants would be forfeited. That portion of the dollar value given that is attributable to PAA phantom units is based on the market value of PAA’s common units on December 31, 2010 ($62.79 per unit), without discount for service period. In addition to the foregoing, under Canadian law, Mr. Duckett could have a claim for additional payment if inadequate notice were given for a termination without cause.

Under the waiver signed in 2010 by Mr. Armstrong and Mr. Pefanis (see footnote 2 above), upon a termination of employment by the company without cause or by the executive for good reason (in each case as defined in the relevant employment agreement) all of the executive’s outstanding awards under the 1998 and 2005 Long-Term Incentive Plans would immediately vest.

The transaction/transition grant agreements provide that in the event of termination without cause (as defined in Footnote 5 below), any unvested phantom common units and associated DERs shall be deemed nonforfeitable and shall be payable on the next following distribution date. That portion of the dollar value given that is attributable to the transaction/transition grants is based on the market value of PNG’s common units on December 31, 2010 ($24.93 per unit), without discount for service period.

(5) The letters evidencing the phantom unit grants to our Named Executive Officers between 2007 and 2010, provide that in the event of a change in status (as defined below), all (25% for Mr. Rutherford) of the then outstanding phantom units and associated DERs will be deemed nonforfeitable, and such phantom units will vest in full (i.e., the phantom units will become payable in the form of one common unit per phantom unit) upon the next following distribution date. Assuming the change in status occurred on December 31, 2010, all (25% for Mr. Rutherford) outstanding phantom units and the associated DERs would have become nonforfeitable as of December 31, 2010, and such phantom units would vest on the February 2011 distribution date. That portion of the dollar value given that is attributable to PAA phantom units is based on the market value of PAA’s common units on December 31, 2010 ($62.79 per unit), without discount for service period.

The transaction/transition grant agreements provide that in the event of a change in status (as defined below), all outstanding phantom units and tandem DERs shall be deemed nonforfeitable on such date, and such phantom units will be payable on the next following distribution date. Assuming a change in status occurred on December 31, 2010, all outstanding phantom units under the transaction/transition grant agreements would have been nonforfeitable and would have vested on the February 2011 distribution date. That portion of the dollar value given that is attributable to the transaction/transition grants is based on the market value of PNG’s common units on December 31, 2010 ($24.93 per unit), without discount for service period.

The phrase “change in status” means, with respect to a Named Executive Officer, the occurrence, during the period beginning two and a half months prior to and ending one year following a change of control (as defined below), of any of the following: (A) the termination of employment

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by Plains All American GP LLC other than a termination for cause (as defined below), or (B) the termination of employment by the Named Executive Officer due to the occurrence, without the Named Executive Officer’s written consent, of (i) any material diminution in the Named Executive Officer’s authority, duties or responsibilities, (ii) any material reduction in the Named Executive Officer’s base salary or (iii) any other action or inaction that would constitute a material breach of the agreement by Plains All American GP LLC.

The phrase “change of control” means, and is deemed to have occurred upon the occurrence of, one or more of the following events: (i) Plains All American GP LLC ceasing to be the general partner of our general partner; (ii) any sale, lease, exchange or other transfer (in one transaction or a series of related transactions) of all or substantially all of the assets of our partnership or Plains All American GP LLC to any person and/or its affiliates, other than to us or Plains All American GP LLC, including any employee benefit plan thereof; (iii) the consolidation, reorganization, merger, or any other similar transaction involving (A) a person other than us or Plains All American GP LLC and (B) us, Plains All American GP LLC or both; (iv) the persons who own membership interests in Plains All American GP LLC as of the grant date ceasing to beneficially own, directly or indirectly, more than 50% of the membership interests of Plains All American GP LLC; or (v) any person, including any partnership, limited partnership, syndicate or other group deemed a “person” for purposes of Section 13(d) or 14(d) of the Securities Exchange Act of 1934, as amended, becoming the beneficial owner, directly or indirectly, of more than 49.9% of the membership interest in Plains All American GP LLC. Notwithstanding the definition of change of control, no change of control is deemed to have occurred in connection with a restructuring or reorganization related to the securitization and sale to the public of direct or indirect equity interests in the general partner if (x) Plains All American GP LLC retains direct or indirect control over the general partner and (y) the current members of Plains All American GP LLC continue to own more than 50% of the member interest in Plains All American GP LLC.

The term “cause” means (i) the failure to perform a job function in accordance with standards described in writing, or (ii) the violation of Plains All American GP LLC’s Code of Business Conduct (unless waived in accordance with the terms thereof), in each case, with the specific failure or violation described in writing.

(6) Pursuant to their employment agreements with Plains All American GP LLC, if Messrs. Armstrong or Pefanis are terminated other than (i) for cause (as defined in Footnote 1 above), (ii) by reason of death or (iii) by resignation (unless such resignation is due to a disability or for good reason (each as defined in Footnote 1 above)), then they are entitled to continue to participate, for a period which is the lesser of two years from the date of termination or the remaining term of the employment agreement, in such health and accident plans or arrangements as are made available by Plains All American GP LLC to its executive officers generally. The amounts provided in the table assume a termination date of December 31, 2010.

(7) Pursuant to their employment agreements, Messrs. Armstrong and Pefanis will be reimbursed for any excise tax due under Section 4999 of the Code as a result of compensation (parachute) payments made under their respective employment agreements. The range of values of this benefit assumes that Messrs. Armstrong and Pefanis were terminated in connection with a change in control effective as of December 31, 2010.

(8) Pursuant to the Class B Restricted Units Agreements, upon the occurrence of a Change in Control, any earned Class B units (and any Class B units that will become earned in less than 180 days) become vested units and, to the extent any Class B units remain unearned, an incremental 25% of the number of Class B units originally granted becomes vested. As of December 31, 2010, 50% of the Class B units held by Messrs. Armstrong, Pefanis and vonBerg had been earned, 50% of the Class B units held by Messrs. Swanson and Duckett had been earned or would become earned in less than 180 days, and none of the Class B units held by Mr. Rutherford had been earned or would become earned in less than 180 days. Assuming a Change in Control on December 31, 2010, 75% of the Class B units held by Messrs. Armstrong, Pefanis, Swanson, Duckett and vonBerg would become vested, and 25% of the Class B units held by Mr. Rutherford would become vested.

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The value of such Class B units as reflected in the table is derived in accordance with FASB ASC Topic 718. “Change in Control” means the determination by the Board that one of the following events has occurred: (i) Plains All American GP LLC ceases to retain direct or indirect control over the Partnership; (ii) the owners of Plains All American GP LLC as of the respective grant date of the Class B units (the “Grant Date”) and their affiliates (the “Owner Affiliates”) cease to own directly or indirectly at least 50% of its member interest; (iii) a “person” or “group” (as such terms are used in Sections 13(d) and 14(d) of the Exchange Act) becomes after the Grant Date the “beneficial owner” (as defined in Rules 13(d)-3 and 13(d)-5 under the Exchange Act), directly or indirectly, of more than 50% of the member interest of Plains All American GP LLC; or (iv) a transfer, sale, exchange or other disposition in a single transaction or series of transactions (whether by merger or otherwise) of all or substantially all of the assets of the Plains AAP, L.P. or the Partnership to one or more persons who are not Affiliates of Plains AAP, L.P., other than a transaction in which the Owner Affiliates become the “beneficial owners,” directly or indirectly, of more than 50% of the voting power of such person or persons immediately following such transaction.

(9) If Messrs. Swanson, Duckett or vonBerg were terminated for cause, Plains All American GP LLC would be obligated to pay base salary through the date of termination, with no other payment obligation triggered by the termination under any employment arrangement.

(10) Mr. Rutherford’s employment agreement provides that in the event his employment is terminated by Plains All American GP LLC other than for cause, or in the event he terminates his employment due to the occurrence, without his consent, of (i) any material diminution in authority, duties or responsibilities, (ii) any material reduction in base salary, or (iii) any other action or inaction that would constitute a material breach of the agreement by Plains All American GP LLC, he will be entitled to receive a minimum annual bonus of $1 million for calendar years 2010, 2011 and 2012. The minimum annual bonus for 2010 shall be prorated from the date of employment.

Confidentiality, Non-Compete and Non-Solicitation Arrangements

Pursuant to his employment agreement, Mr. Armstrong has agreed to maintain the confidentiality of PAA information for a period of five years after the termination of his employment. Mr. Pefanis has agreed to a similar restriction for a period of one year following the termination of his employment. Mr. Duckett has agreed to maintain confidentiality following termination of his employment for a period of two years with respect to customer lists. He has also agreed not to compete in a specified geographic area for a period of two years after termination of his employment. Mr. vonBerg has agreed to maintain confidentiality and not to solicit customers for a period of one year following termination of his employment. Mr. Rutherford has agreed to maintain confidentiality for a period of two years after termination of his employment and not to solicit customers and assets for a period of one year after termination of his employment.

Compensation of Directors

The following table sets forth a summary of the compensation paid to each person who served as a non-employee director of Plains All American GP LLC in 2010:

Name	Fees Earned or Paid in Cash ($)	Stock Awards ($) (1)	Total ($)
Lance Conn (2)	—	—	—
Everardo Goyanes	75,000	152,525	227,525
Geoff McKay (2)	45,000	—	45,000
Gary R. Petersen (3)	45,000	305,550	350,550
John T. Raymond (4)	—	—	—
Robert V. Sinnott	47,000	76,263	123,263
Arthur L. Smith (5)	58,250	152,525	210,775
Vicky Sutil (4)	—	—	—
J. Taft Symonds	60,000	152,525	212,525
Christopher M. Temple (2)	48,750	602,801	651,551

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(1) The dollar value of LTIPs granted during 2010 is based on the grant date fair value computed in accordance with FASB ASC Topic 718. In connection with the August 2010 vesting of director LTIP awards, Messrs. Goyanes, Smith and Symonds each were granted 2,500 units, Mr. Sinnott was granted 1,250 units and Mr. Temple was granted 625 units by virtue of the automatic re-grant feature of the vested awards. Upon vesting of the director LTIP awards in August 2010 (other than the incremental audit committee awards), a cash payment was made to Vulcan Capital and an affiliate of EnCap as directed by Messrs. McKay and Petersen, respectively. Such cash payment was based on the unit value of Mr. Sinnott’s award on the previous year’s vesting date. In addition to the automatic re-grant in August, Mr. Temple also received an initial grant of 5,000 LTIPs in February 2010 and a supplemental audit committee award of 5,000 LTIPs in August 2010. Mr. Petersen received a grant of 5,000 LTIPs in August 2010.

(2) Compensation attributable to the directors previously designated by Vulcan was assigned to Vulcan. Mr. Temple served as Vulcan’s designated director from May 2009 until February 2010. In February 2010, Mr. McKay replaced Mr. Temple as Vulcan’s designated director. Mr. Temple continues to serve as an independent director in an at-large capacity and was appointed to the audit committee in August 2010. Mr. Conn resigned from the board in February 2010, and Mr. McKay departed the board in December 2010 in connection with the sale by Vulcan Energy of its interest in our general partner.

(3) Prior to July 2010, Mr. Petersen assigned to EnCap’s investment funds any compensation attributable to his service as a director. After July 1, 2010, all director compensation is paid directly to Mr. Petersen or per his instruction.

(4) Mr. Raymond and Ms. Sutil joined the board on December 23, 2010. They were not paid any compensation in 2010. Ms. Sutil’s compensation is assigned to Oxy.

(5) In connection with his departure from the audit committee in August 2010, Mr. Smith’s 5,000 audit committee LTIPs were cancelled. Mr. Smith departed the board in December 2010 in connection with the sale by Vulcan Energy of its interest in our general partner. His remaining 5,000 LTIPs will vest in full in February 2011.

Each director of Plains All American GP LLC who is not an employee of Plains All American GP LLC is reimbursed for any travel, lodging and other out-of-pocket expenses related to meeting attendance or otherwise related to service on the board (including, without limitation, reimbursement for continuing education expenses). Each non-employee director is currently paid an annual retainer fee of $45,000. Mr. Armstrong is otherwise compensated for his services as an employee and therefore receives no separate compensation for his services as a director. In addition to the annual retainer, each committee chairman (other than the chairman of the audit committee) receives $2,000 annually. The chairman of the audit committee receives $30,000 annually, and the other members of the audit committee receive $15,000 annually, in each case, in addition to the annual retainer. During 2010, Messrs. Sinnott, Goyanes and Smith served as chairmen of the compensation, audit and governance committees, respectively.

Our non-employee directors receive LTIP awards or cash equivalent awards as part of their compensation. The LTIP awards vest annually in 25% increments over a four-year period and have an automatic re-grant feature such that as they vest, an equivalent amount is granted. The awards have associated distribution equivalent rights that are payable quarterly. The three non-employee directors who serve on the audit committee each have outstanding a grant of 10,000 units (vesting 2,500 units per year). Messrs. Petersen, Raymond and Sinnott each have outstanding a grant of 5,000 units (vesting 1,250 units per year). Upon vesting of the director LTIPs (other than the incremental audit committee awards), a cash

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payment will be made to Oxy as directed by the Oxy designee. Such cash payment is based on the unit value of Mr. Sinnott’s award on the previous year’s vesting date.

All LTIP awards held by a director vest in full upon the next following distribution date after the death or disability (as determined in good faith by the board) of the director. For audit committee grants, the awards also vest in full if such director (i) retires (no longer with full-time employment and no longer serving as an officer or director of any public company) or (ii) is removed from the board of directors or is not reelected to the board of directors, unless such removal or failure to reelect is for “good cause,” as defined in the letter granting the units.

Reimbursement of Expenses of Our General Partner and its Affiliates

We do not pay our general partner a management fee, but we do reimburse our general partner for all direct and indirect costs of services provided to us, incurred on our behalf, including the costs of employee, officer and director compensation (other than expenses related to the Class B units of Plains AAP, L.P.) and benefits allocable to us, as well as all other expenses necessary or appropriate to the conduct of our business, allocable to us. We record these costs on the accrual basis in the period in which our general partner incurs them. Our partnership agreement provides that our general partner will determine the expenses that are allocable to us in any reasonable manner determined by our general partner in its sole discretion.

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Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters

Beneficial Ownership of Limited Partner Interest

Our common units outstanding represent 98% of our equity (limited partner interest). The 2% general partner interest is discussed separately below under “—Beneficial Ownership of General Partner Interest.” The following table sets forth the beneficial ownership of limited partner units held by beneficial owners of 5% or more of the units, directors, the Named Executive Officers, and all directors and executive officers as a group as of February 21, 2011.

Name of Beneficial Owner	Common Units		Percentage of Common Units
Paul G. Allen	16,293,379	(1)	11.5	%
Vulcan Energy Corporation	12,390,120	(2)	8.8	%
Richard Kayne/Kayne Anderson Capital Advisors, L.P.	6,981,453	(3)	4.9	%
Greg L. Armstrong	423,750	(4)(5)		(6)
Harry N. Pefanis	271,958	(5)		(6)
Dave Duckett	119,541	(5)		(6)
John P. vonBerg	47,025	(5)		(6)
Al Swanson	26,606	(5)		(6)
John R. Rutherford	—		—
Everardo Goyanes	29,200			(6)
Gary R. Petersen	5,000			(6)
John T. Raymond	945,017			(6)
Robert V. Sinnott	60,655	(7)		(6)
Vicky Sutil	—		—
J. Taft Symonds	34,800			(6)
Chris Temple	625			(6)
All directors and executive officers as a group (18 persons)	2,151,124	(8)	1.5	%

(1) Mr. Allen owns approximately 80% of the outstanding shares of common stock of Vulcan Energy Corporation. Mr. Allen also controls Vulcan Capital Private Equity I LLC (“Vulcan I LLC”), which is the record holder of 3,706,044 common units, and Vulcan Capital Private Equity II LLC (together with Vulcan I LLC, “Vulcan LLC”), which is the record holder of 197,215 common units. The address for Mr. Allen and Vulcan LLC is 505 Fifth Avenue S, Suite 900, Seattle, Washington 98104. Mr. Allen disclaims any deemed beneficial ownership, beyond his pecuniary interest, in any of our partner interests held by Vulcan Energy Corporation or any of its affiliates.

(2) The address for Vulcan Energy Corporation is 505 Fifth Avenue S, Suite 900, Seattle, Washington 98104.

(3) Richard A. Kayne is Chief Executive Officer and Director of Kayne Anderson Investment Management, Inc., which is the general partner of Kayne Anderson Capital Advisors, L.P. (“KACALP”). Various accounts (including KAFU Holdings, L.P., which owns a portion of our general partner) under the management or control of KACALP own 6,712,436 common units. Mr. Kayne may be deemed to beneficially own such units. In addition, Mr. Kayne directly owns or has sole voting and dispositive power over 269,017 common units. Mr. Kayne disclaims beneficial ownership of any of our partner interests other than units held by him or interests attributable to him by virtue of his interests in the accounts that own our partner interests. The address for Mr. Kayne and Kayne Anderson Investment Management, Inc. is 1800 Avenue of the Stars, 2nd Floor, Los Angeles, California 90067.

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(4) Does not include approximately 566 common units owned by our general partner in connection with its Performance Option Plan. Mr. Armstrong disclaims any beneficial ownership of such units beyond his rights as a grantee under the plan. See Item 13. “Certain Relationships and Related Transactions, and Director Independence—General Partner’s Performance Option Plan.”

(5) Does not include unvested phantom units granted under our Long-Term Incentive Plans, none of which will vest within 60 days of the date hereof. See Item 11. “Executive Compensation—Outstanding Equity Awards at Fiscal Year-End.”

(6) Less than one percent.

(7) Pursuant to the GP LLC Agreement, Mr. Sinnott has been designated as one of our directors by KAFU Holdings, L.P., which is controlled by Kayne Anderson Investment Management, Inc., of which he is President. Mr. Sinnott disclaims any deemed beneficial ownership of the interests owned by KAFU Holdings, L.P. or its affiliates, beyond his pecuniary interest therein, if any. Mr. Sinnott has a non-controlling ownership interest in KACALP, which is the general partner of KAFU Holdings, L.P. KACALP is entitled to a percentage of the profits earned by the funds invested in KAFU Holdings, L.P. The address for KAFU Holdings, L.P. is 1800 Avenue of the Stars, 2nd Floor, Los Angeles, California 90067.

(8) As of February 21, 2011, no units were pledged by directors or Named Executive Officers. Certain of the directors and Named Executive Officers hold units in marginable broker’s accounts, but none of the units were margined as of February 21, 2011.

Beneficial Ownership of General Partner Interest

Plains AAP, L.P. owns all of our incentive distribution rights and, through its 100% member interest in PAA GP LLC, our 2% general partner interest. The following table sets forth the effective ownership of Plains AAP, L.P. (after giving effect to proportionate ownership of Plains All American GP LLC, its 1% general partner).

Name of Owner and Address (in the case of Owners of more than 5%)	Percentage Ownership of Plains AAP, L.P. (1)
Oxy Holding Company (Pipeline), Inc. 10889 Wilshire Boulevard Los Angeles, CA 90024	35.0	%
EMG Investment, LLC 1401 McKinney, Suite 1025 Houston, TX 77101	25.0	%
KAFU Holdings, L.P. and Affiliates (2) 1800 Avenue of the Stars, 2nd Floor Los Angeles, CA 90067	20.8	%
KA First Reserve XII, LLC 600 Travis, Suite 6000 Houston, TX 77002	5.9	%
PAA Management, L.P. (3)	4.6	%
Strome PAA, L.P.	3.7	%
Windy, L.L.C.	3.0	%
Lynx Holdings I, LLC	1.4	%
Various Individual Investors	0.6	%

(1) Plains AAP, L.P. owns a 100% member interest in PAA GP LLC, which owns our 2% general partner interest. Plains AAP, L.P. has pledged its member interest, as well as its interest in our incentive distribution rights, as security for its obligations

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under the Credit Agreement dated as of January 3, 2008 among Plains AAP, L.P., Citibank, N.A. and the lenders party thereto (the “Plains AAP Credit Agreement”). A default by Plains AAP, L.P. under the Plains AAP Credit Agreement could result in a change in control of our general partner. Certain members of management own a profits interest in Plains AAP, L.P. in the form of Class B units.

(2) Mr. Sinnott disclaims any deemed beneficial ownership of the interests owned by KAFU Holdings, L.P. beyond his pecuniary interest therein, if any. Mr. Sinnott has a non-controlling ownership interest in KACALP, which is the general partner of KAFU Holdings, L.P. KACALP is entitled to a percentage of the profits earned by the funds invested in KAFU Holdings, L.P.

(3) PAA Management, L.P. is owned entirely by certain current and former members of senior management, including Messrs. Armstrong (approximately 25%), Pefanis (approximately 14%), Duckett (approximately 4%), vonBerg (approximately 4%) and Swanson (approximately 5%). Other than Mr. Armstrong, no directors own any interest in PAA Management, L.P. Executive officers as a group own approximately 66% of PAA Management, L.P. Mr. Armstrong disclaims any beneficial ownership of the general partner interest owned by Plains AAP, L.P., other than through his ownership interest in PAA Management, L.P.

Equity Compensation Plan Information

The following table sets forth certain information with respect to our equity compensation plans as of December 31, 2010. For a description of these plans, see Item 13. “Certain Relationships and Related Transactions, and Director Independence—Equity-Based Long-Term Incentive Plans.”

Plan Category	Number of Units to be Issued upon Exercise/Vesting of Outstanding Options, Warrants and Rights (a)		Weighted Average Exercise Price of Outstanding Options, Warrants and Rights (b)		Number of Units Remaining Available for Future Issuance under Equity Compensation Plans (c)
Equity compensation plans approved by unitholders:
1998 Long Term Incentive Plan	621,900	(1)	N/A	(2)	271,686	(1)(3)
2005 Long Term Incentive Plan	1,504,000	(4)	N/A	(2)	347,809	(3)
Equity compensation plans not approved by unitholders:
1998 Long Term Incentive Plan	—	(1)(5)	N/A	(2)	—	(6)
General Partner’s Performance Option Plan	—	(7)	N/A	(7)	—	(7)
PPX Successor LTIP	356,167	(8)	N/A	(2)	633,360	(8)

(1) As originally instituted by our former general partner prior to our initial public offering, the 1998 LTIP contemplated the issuance of up to 975,000 common units to satisfy awards of phantom units. Upon vesting, these awards could be satisfied either by (i) primary issuance of units by us or (ii) cash settlement or purchase of units by our general partner with the cost reimbursed by us. In 2000, the 1998 LTIP was amended, as provided in the plan, without unitholder approval to increase the maximum awards to 1,425,000 phantom units; however, we can issue no more than 975,000 new units to satisfy the awards. Any additional units must be purchased by our general partner in the open market or in private transactions and be reimbursed by us. As of December 31, 2010, we have issued approximately 427,742 common units in satisfaction of vesting under the 1998 LTIP. The number of units presented in column (a) assumes that all remaining grants will be

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satisfied by the issuance of new units upon vesting. In fact, a substantial number of phantom units that have vested were satisfied without the issuance of units. These phantom units were settled in cash or withheld for taxes. Any units not issued upon vesting will become “available for future issuance” under column (c).

(2) Phantom unit awards under the 1998 LTIP, 2005 LTIP and PPX Successor LTIP vest without payment by recipients.

(3) In accordance with Item 201(d) of Regulation S-K, column (c) excludes the securities disclosed in column (a). However, as discussed in footnotes (1) and (4), any phantom units represented in column (a) that are not satisfied by the issuance of units become “available for future issuance.”

(4) The 2005 Long Term Incentive Plan was approved by our unitholders in January 2005. The 2005 LTIP contemplates the issuance or delivery of up to 3,000,000 units to satisfy awards under the plan. The number of units presented in column (a) assumes that all outstanding grants will be satisfied by the issuance of new units upon vesting unless such LTIPs are by their terms payable only in cash. In fact, some portion of the phantom units may be settled in cash and some portion will be withheld for taxes. Any units not issued upon vesting will become “available for future issuance” under column (c).

(5) Although awards for units may from time to time be outstanding under the portion of the 1998 LTIP not approved by unitholders, all of these awards must be satisfied in cash or out of units purchased by our general partner and reimbursed by us. None will be satisfied by “units issued upon exercise/vesting.”

(6) Awards for up to 346,328 phantom units may be granted under the portion of the 1998 LTIP not approved by unitholders; however, no common units are “available for future issuance” under the plan, because all such awards must be satisfied with cash or out of units purchased by our general partner and reimbursed by us.

(7) In 2001, our general partner adopted a Performance Option Plan for officers and key employees pursuant to which optionees have the right to purchase units from the general partner. The 450,000 units that were originally authorized to be sold under the plan were contributed to the general partner by certain of its owners in connection with the transfer of a majority of our general partner interest in 2001 without economic cost to the Partnership. No options were outstanding at December 31, 2010, and no units remain available for future grant. See Item 13. “Certain Relationships and Related Transactions, and Director Independence—Our General Partner—General Partner’s Performance Option Plan.”

(8) In connection with the Pacific merger, under applicable stock exchange rules, we carried over the available units under the Pacific LTIP (applying the conversion ratio of 0.77 PAA units for each Pacific unit). In that regard, we have adopted the Plains All American PPX Successor Long-Term Incentive Plan (the “PPX Successor LTIP”). Potential awards under such plan include options and phantom units (with or without tandem DERs). The provisions of such plan are substantially the same as the 2005 LTIP, except that awards under the PPX Successor LTIP may only be made to employees who were working for Pacific at the time of the merger or to employees hired after the date of the Pacific acquisition.

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Item 13. Certain Relationships and Related Transactions, and Director Independence

For a discussion of director independence, see Item 10. “Directors and Executive Officers of Our General Partner and Corporate Governance.”

Our General Partner

Our operations and activities are managed, and our officers and personnel are employed, by our general partner (or, in the case of our Canadian operations, Plains Midstream Canada). We do not pay our general partner a management fee, but we do reimburse our general partner for all expenses incurred on our behalf (other than expenses related to the Class B units of Plains AAP, L.P.). Total costs reimbursed by us to our general partner for the year ended December 31, 2010 were approximately $374 million.

Our general partner owns the 2% general partner interest and all of the incentive distribution rights. 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, generally our general partner is entitled, without duplication, to 15% of amounts we distribute in excess of $0.450 ($1.80 annualized) per unit, 25% of the amounts we distribute in excess of $0.495 ($1.98 annualized) per unit and 50% of amounts we distribute in excess of $0.675 ($2.70 annualized) per unit. In connection with the Pacific, Rainbow and PNGS acquisitions, our general partner agreed to a temporary reduction in the amount of incentive distributions otherwise payable to it. Following our distribution in February 2011, the remaining incentive distribution reductions totaled approximately $5 million.

The following table illustrates the allocation of aggregate distributions at different per-unit levels, excluding the effect of the incentive distribution reductions (dollars in thousands):

Annual LP Distribution Per Unit		Distribution to LP Unitholders(1)		Distribution to GP(1)(2)		Total Distribution(1)(2)		GP % of Total Distribution
$	1.80	$	254,160	$	5,187	$	259,347	2	%
$	1.98	$	279,576	$	9,672	$	289,248	3	%
$	2.70	$	381,240	$	43,560	$	424,800	10	%
$	3.80	$	536,560	$	198,880	$	735,440	27	%
$	3.90	$	550,680	$	213,000	$	763,680	28	%
$	4.00	$	564,800	$	227,120	$	791,920	29	%

(1) Assumes 141,200,000 units outstanding. The actual number of units outstanding as of December 31, 2010 was 141,199,175. An increase in the number of units outstanding would increase both the distribution to unitholders and the distribution to the general partner for any given level of distribution per unit.

(2) Includes distributions attributable to the 2% general partner interest and the incentive distribution rights.

Equity-Based Long-Term Incentive Plans

Our general partner has adopted the Plains All American GP LLC 1998 Long-Term Incentive Plan (the “1998 LTIP”) and the Plains All American GP LLC 2005 Long-Term Incentive Plan (the “2005 LTIP”) for employees and directors of our general partner and its affiliates who perform services for us, and the PPX Successor LTIP for former Pacific employees and employees hired after the date of the Pacific merger (together with the 1998 LTIP and 2005 LTIP, the “Plans”). Awards contemplated by the Plans include phantom units (referred to as restricted units in the 1998 LTIP), distribution equivalent rights

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(DERs) and unit options. As amended, the 1998 LTIP authorizes the grant of awards covering an aggregate of 1,425,000 common units deliverable upon vesting or exercise (as applicable) of such awards. The 2005 LTIP authorizes the grant of awards covering an aggregate of 3,000,000 common units deliverable upon vesting or exercise (as applicable) of such awards. The PPX Successor LTIP authorizes the grant of awards covering an aggregate of 999,809 common units deliverable upon vesting or exercise (as applicable) of such awards. Our general partner’s board of directors has the right to alter or amend the Plans from time to time, including, subject to any applicable NYSE listing requirements, increasing the number of common units with respect to which awards may be granted; provided, however, that no change in any outstanding grant may be made that would materially impair the rights of the participant without the consent of such participant.

Common units to be delivered upon the vesting of rights may be newly issued common units, common units acquired by our general partner in the open market or in private transactions, common units acquired by us from any other person, common units already owned by our general partner, or any combination of the foregoing. Our general partner will be entitled to reimbursement by us for the cost incurred in acquiring common units. In addition, over the term of the plan we may issue new common units to satisfy delivery obligations under the grants. When we issue new common units upon vesting of grants, the total number of common units outstanding increases.

Phantom Units. A phantom unit entitles the grantee to receive, upon the vesting of the phantom unit, a common unit (or cash equivalent, depending on the terms of the grant).

As of December 31, 2010, grants of approximately 621,900; 1,784,000; and 751,145 unvested phantom units were outstanding under the 1998 LTIP, 2005 LTIP and PPX Successor LTIP, respectively, and approximately 271,686; 347,809; and 633,360 remained available for future grant, respectively. The compensation committee or board of directors may, in the future, make additional grants under the Plans to employees and directors containing such terms as the compensation committee or board of directors shall determine, including DERs with respect to phantom units. DERs entitle the grantee to a cash payment, either while the award is outstanding or upon vesting, equal to any cash distributions paid on a unit while the award is outstanding.

The issuance of the common units upon vesting of phantom units is primarily intended to serve as a means of incentive compensation for performance. Therefore, no consideration is paid to us by the plan participants upon receipt of the common units.

Unit Options. Although the Plans currently permit the grant of options covering common units, no options have been granted under the Plans to date. However, the compensation committee or board of directors may, in the future, make grants under the plan to employees and directors containing such terms as the compensation committee or board of directors shall determine, provided that unit options have an exercise price equal to the fair market value of the units on the date of grant.

General Partner’s Performance Option Plan

In 2001, certain owners of the general partner contributed an aggregate of 450,000 subordinated units (now converted into common units) to the general partner to provide a pool of units available for the grant of options to management and key employees. As of December 31, 2010, there were no options outstanding under the plan, and no units remain available for future grant.

Class B Units of Plains AAP, L.P.

In August 2007, the owners of Plains AAP, L.P. authorized the creation and issuance of up to 200,000 Class B units of Plains AAP, L.P. and authorized the compensation committee of Plains All American GP LLC to issue grants of Class B units to create long-term incentives for our management. The entire economic burden of the Class B units, which are equity classified, is borne solely by Plains AAP, L.P. and does not impact our cash or units outstanding. Therefore, we recognize the grant date fair value of the Class B units as compensation expense over the service period. The expense is also reflected as a capital contribution, and thus results in a corresponding credit to Partners’ Capital in our Consolidated

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Financial Statements. The expense and capital contribution for the twelve months ended December 31, 2010 was approximately $9 million. We will not be obligated to reimburse Plains AAP, L.P. for such costs and any distributions made on the Class B units will not reduce the amount of cash available for distribution to our unitholders. Each Class B unit represents a “profits interest” in Plains AAP, L.P., which entitles the holder to participate in future profits and losses from operations, current distributions from operations, and an interest in future appreciation or depreciation in Plains AAP, L.P.’s asset values. As of December 31, 2010, 175,500 Class B units were issued and outstanding.

The outstanding Class B units are subject to restrictions on transfer and generally become “earned” (entitled to participate in distributions) in percentage increments when the annualized quarterly distributions on our common units equal or exceed certain thresholds. Class B units granted in 2007 become earned in 25% increments when the annualized quarterly distributions on our common units equal or exceed $3.50, $3.75, $4.00 and $4.50 per unit. Class B units granted in 2009 become earned in increments of 37.5%, 37.5% and 25% 180 days after we pay annualized quarterly distributions on our common units of $3.75, $4.00 and $4.50, respectively. Class B units granted in 2010 become earned in 25% increments 180 days after we pay annualized quarterly distributions on our common units equal or exceed $3.90, $4.05, $4.20 and $4.50 per unit. Upon achievement of these performance thresholds (or, in some cases, within six months thereafter), the Class B units will be entitled to their proportionate share of all quarterly cash distributions made by Plains AAP, L.P. in excess of $11 million per quarter (as adjusted for debt service costs and excluding special distributions funded by debt). Assuming all authorized Class B units are issued, the maximum participation would be 8% of the amount in excess of $11 million per quarter, as adjusted. As of December 31, 2010, approximately 50% of the Class B units granted in 2007 had been earned, 37.5% of the Class B units granted in 2009 had been earned and none of the Class B units granted in 2010 had been earned.

To encourage retention following achievement of these performance benchmarks, Plains AAP, L.P. retained a call right to purchase any earned Class B units at a discount to fair market value that is exercisable upon the termination of a holder’s employment with Plains All American GP LLC and its affiliates for any reason prior to January 1, 2016 (January 1, 2017 for Class B units granted in 2010), other than a termination of employment by the employee for good reason or by Plains All American GP LLC other than for cause (as defined). Upon the occurrence of a change of control (as defined), (i) all earned units will vest (no longer be subject to Plains AAP, L.P.’s call right), (ii) to the extent any of the units granted in 2007 and 2010 are unearned at the time, an incremental 25% of the units originally awarded will vest, (iii) if none of the units granted in 2009 have been earned at the time, 37.5% will vest, (iv) if 37.5% of the units granted in 2009 have been earned at the time, then an additional 37.5% will vest and (v) if 75% of the units granted in 2009 have been earned at the time, then the remaining 25% will vest. All earned Class B units will also vest if they remain outstanding as of January 1, 2016 (January 1, 2017 for Class B units granted in 2010) or Plains AAP, L.P. elects not to timely exercise its call right.

Transactions with Related Persons

Vulcan Energy

In December 2010, Vulcan Energy sold its 50.1% interest in our general partner. Substantially all of the interest was acquired by existing owners of PAA’s general partner or their affiliates. Purchasers included a subsidiary of Occidental Petroleum Corporation (“Oxy”); a fund affiliated with The Energy & Minerals Group (“EMG”), which is also an affiliate of Lynx Holdings; funds associated with Kayne Anderson and First Reserve; and various other investors. As of December 31, 2010, Vulcan Energy and its affiliates owned approximately 9% of our outstanding limited partner units.

Voting Agreements. In August 2005, in connection with an increase in Vulcan Energy’s ownership interest in our general partner, Vulcan Energy entered into a voting agreement that restricted its ability to unilaterally elect or remove the independent directors serving on our audit committee. Lynx Holdings I, LLC, also agreed to restrict certain of its voting rights with respect to its membership interest in GP LLC. Our CEO and COO agreed, subject to certain ongoing conditions, to waive certain change-of-

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control payment rights that would otherwise have been triggered by the increase in Vulcan Energy’s ownership interest.

These voting rights agreements were terminated in December 2010 in connection with the sale by Vulcan Energy of its 50.1% interest in our general partner. Vulcan Energy has agreed that prior to the earlier of December 23, 2015 and the date, if any, of certain changes in our senior-most management, it will not vote any of its limited partner interests in favor of any proposal to remove GP LLC as our general partner. See Item 10. “Directors and Executive Officers of Our General Partner and Corporate Governance—Partnership Management and Governance.”

Administrative Services Agreement. On October 14, 2005, GP LLC and Vulcan Energy entered into an Administrative Services Agreement, effective as of September 1, 2005 (the “Services Agreement”). Pursuant to the Services Agreement, GP LLC provided administrative services to Vulcan Energy for consideration of an annual fee of $1 million, plus certain expenses. The Services Agreement was terminated in December 2010 in connection with the sale by Vulcan Energy of its 50.1% interest in our general partner. However, we have agreed to provide transition services and assistance to Vulcan Energy until June 2011 for consideration of a $1 million fee.

Indemnification Arrangement. In 2001, in connection with the transfer of interests in our general partner, Vulcan Energy (as successor in interest to the owner of our former general partner) agreed to indemnify us for (i) any claims relating to securities laws or regulations in connection with the upstream or midstream businesses, based on acts or omissions, or alleged acts or omissions, occurring on or prior to June 8, 2001, or (ii) any claims relating to the operation of the upstream business, whenever arising. In addition, we agreed to indemnify Vulcan Energy for any claims relating to the operation of the midstream business, whenever arising.

Other. In addition to those relationships described above, we have engaged in other transactions with affiliates of Vulcan Energy. See “—Natural Gas Storage Investment.”

Natural Gas Storage Investment

In September 2005, we and Vulcan Gas Storage LLC, a subsidiary of Vulcan LLC, an investment arm of Paul G. Allen, formed PAA/Vulcan Gas Storage, LLC to acquire ECI (now known as PAA Natural Gas Storage, LLC or “PNGS”), an indirect subsidiary of Sempra Energy, for approximately $250 million. We and Vulcan Gas Storage each made an initial cash investment of approximately $113 million and Bluewater Natural Gas Holdings, LLC, a subsidiary of PAA/Vulcan, entered into a $90 million credit facility contemporaneously with closing.

From September 2005 until September 3, 2009, we owned 50% of PAA/Vulcan and Vulcan Gas Storage LLC owned the other 50%. Giving effect to all contributions and distributions made during the period from January 1, 2007 through September 3, 2009, we and Vulcan Gas Storage each made a net contribution of $39 million. Such contributions and distributions did not result in an increase or decrease to our ownership interest.

On September 3, 2009, one of our subsidiaries acquired the remaining 50% interest in PAA/Vulcan from Vulcan Gas Storage LLC, which resulted in our ownership of a 100% interest in PNGS. The purchase price for the transaction consisted of $90 million in cash paid at closing, 1,907,305 common units issued to Vulcan Gas Storage at closing, and up to $40 million of deferred/contingent cash consideration. The deferred/contingent consideration is payable in cash in two installments of $20 million each upon achievement of certain performance milestones and events expected to occur over the next several years. The first of these installments was paid in May 2010. At closing of the acquisition, we repaid all of PNGS’s outstanding debt. Mr. Temple had a profits interest in Vulcan Gas Storage from September 2008 until December 2009. The Board of Directors appointed a conflicts committee in connection with this transaction. After engaging in a process of review and deliberation, the conflicts committee determined that the transaction was fair and reasonable. See “—Review, Approval or Ratification of Transactions with Related Persons” below.

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PAA Natural Gas Storage, L.P.

PNG IPO. On May 5, 2010, PNG completed its IPO of 13,478,000 common units representing limited partner interests. The common units offered represented approximately 23% of the outstanding equity of PNG. We retained the remaining 77% equity interest in PNG.

Prior to the PNG IPO, we owned 100% of the natural gas storage business of PNG’s predecessor, PNGS. Immediately prior to the closing of the PNG IPO, we contributed 100% of the equity interests in PNGS and its subsidiaries to PNG in exchange for approximately 18.1 million common units, approximately 13.9 million series A subordinated units, 11.5 million series B subordinated units and a 2% general partner interest and incentive distribution rights. In August 2010, the capital structure of PNG was modified to reduce the number of series A subordinated units by 2 million and increase the number of series B subordinated units by the same amount. As of December 31, 2010, we owned approximately 18.1 million common units, approximately 11.9 million series A subordinated units and 13.5 million series B subordinated units of PNG.

PNG Common Unit Private Placement. In February 2011, in connection with the Southern Pines acquisition, PNG completed a private placement of approximately 17.4 million PNG common units for net proceeds of approximately $370 million. Investors included funds managed by Kayne Anderson Capital Advisors and various third-party investors. In addition, we purchased approximately 10.2 million PNG common units for a total of approximately $230 million, including our proportionate 2% general partner contribution. As a result of these transactions, our aggregate ownership interest in PNG decreased to approximately 64% from 77%.

We also provided debt financing to PNG in the form of a $200 million three-year senior unsecured loan that bears interest at 5.25%.

Omnibus Agreement. In conjunction with PNG’s IPO, we entered into an omnibus agreement with PNG, pursuant to which we agreed upon certain aspects of our relationship with PNG, including, among other things (i) the provision by our general partner to PNG of certain general and administrative services and PNG’s agreement to reimburse our general partner for such services, (ii) the provision by our general partner of such personnel as may be necessary to operate and manage PNG’s business, and PNG’s agreement to reimburse our general partner for the expenses associated with such personnel, (iii) certain indemnification obligations, and (iv) PNG’s use of the name “PAA” and related marks. Under this agreement, we indemnify PNG for certain environmental liabilities, tax matters, and title or permitting defects generally for a period of three years after the closing of PNG’s IPO. The environmental indemnifications are subject to a cap of $15 million and require PNG to pay the first $250 thousand of costs incurred. In addition, PNG has indemnified us from any losses, costs or damages incurred by us or our general partner that are attributable to the ownership and operation of PNG’s assets following the closing of the IPO.

Tax Sharing Agreement. In conjunction with PNG’s IPO, we entered into a tax sharing agreement with PNG, pursuant to which we and PNG agreed on the method of allocation among us and our subsidiaries (other than PNG and its subsidiaries), on the one hand, and PNG and its subsidiaries on the other, of the responsibilities, liabilities and benefits relating to any taxes for which a combined return is filed for taxable periods including or beginning on May 5, 2010.

Other

During 2010, 2009 and 2008, we purchased approximately $2.7 million, $2.2 million and $3.6 million, respectively, of oil from companies owned and controlled by funds managed by KACALP. We pay the same amount per barrel to these companies that we pay to other producers in the area.

During 2010, 2009 and 2008, we received sales and transportation and storage revenues of approximately $2.2 billion, $0.2 billion and $0.2 billion, respectively, from companies affiliated with Oxy.

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During 2010, 2009 and 2008, we also purchased approximately $0.2 billion, $0.2 billion and $0.2 billion, respectively, of petroleum products from companies associated with Oxy.

Review, Approval or Ratification of Transactions with Related Persons

Pursuant to our Governance Guidelines, a director is expected to bring to the attention of the CEO or the board any conflict or potential conflict of interest that may arise between the director or any affiliate of the director, on the one hand, and the Partnership or GP LLC on the other. The resolution of any such conflict or potential conflict should, at the discretion of the board in light of the circumstances, be determined by a majority of the disinterested directors.

If a conflict or potential conflict of interest arises between the Partnership and GP LLC, the resolution of any such conflict or potential conflict should be addressed by the board in accordance with the provisions of the Partnership Agreement. At the discretion of the board in light of the circumstances, the resolution may be determined by the board in its entirety or by a “conflicts committee” meeting the definitional requirements for such a committee under the Partnership Agreement. Such resolution may include resolution of any derivative conflicts created by an executive officer’s ownership of interests in GP LLC or a director’s appointment by an owner of GP LLC.

Pursuant to our Code of Business Conduct, any executive officer must avoid conflicts of interest unless approved by the board of directors.

In the case of any sale of equity by the Partnership in which an owner or affiliate of an owner of our general partner participates, our practice is to obtain general approval of the full board for the transaction. The board typically delegates authority to set the specific terms to a pricing committee, consisting of the CEO and one independent director. Actions by the pricing committee require unanimous approval.

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Item 14. Principal Accountant Fees and Services

The following table details the aggregate fees billed for professional services rendered by our independent auditor for services provided to us and to our consolidated subsidiaries (in millions):

	Year Ended December 31,
	2010		2009
Audit fees(1)	$	3.4	$	3.7
Audit-related fees(2)	0.1		0.2
Tax fees(3)	1.5		0.8
All other fees(4)	1.2		0.2
Total	$	6.2	$	4.9

(1) Audit fees include those related to (a) our annual audit (including internal control evaluation and reporting), (b) the annual audit of PNG; (c) the audit of our general partner and certain joint ventures of which we are the operator, and (d) work performed on our registration of publicly held debt and equity, including fees associated with work performed in conjunction with the initial public offering of PNG. Amounts reported for 2009 have been revised to include fees associated with the audits of PNG predecessor entities for periods prior to our consolidation of PNG and other fees associated with the initial public offering of PNG.

(2) Audit-related fees primarily relate to audits of our benefit plans.

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

(4) All other fees primarily consist of those associated with due diligence performed on our behalf and evaluating potential acquisitions.

Pre-Approval Policy

As discussed above, we have an audit committee that reviews our external financial reporting, engages our independent auditors and reviews the adequacy of our internal accounting controls. Our consolidated subsidiary, PNG, also has an audit committee that performs similar functions on PNG’s behalf. All services provided by our independent auditor are subject to pre-approval by our audit committee or the audit committee of PNG (for services provided to PNG). The audit committees have instituted policies that describe certain pre-approved non-audit services. We believe that the descriptions of services are designed to be sufficiently detailed as to particular services provided, such that (i) management is not required to exercise judgment as to whether a proposed service fits within the description and (ii) the audit committee knows what services it is being asked to pre-approve. The audit committees are informed of each engagement of the independent auditor to provide services under the respective policy. All services provided by our independent auditor during the years ended December 31, 2010 and 2009 were approved in advance by the applicable audit committee.

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PART IV

Item 15. Exhibits and Financial Statement Schedules

(a) (1) Financial Statements

See “Index to the Consolidated Financial Statements” set forth on Page F-1.

(2) Financial Statement Schedules

All schedules are omitted because they are either not applicable or the required information is shown in the consolidated financial statements or notes thereto.

(3) Exhibits

3.1		—	Third Amended and Restated Agreement of Limited Partnership of Plains All American Pipeline, L.P. dated as of June 27, 2001 (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed August 27, 2001).

3.2		—	Amendment No. 1 dated April 15, 2004 to the Third Amended and Restated Agreement of Limited Partnership of Plains All American Pipeline, L.P. (incorporated by reference to Exhibit 3.1 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2004).

3.3		—	Amendment No. 2 dated November 15, 2006 to Third Amended and Restated Agreement of Limited Partnership of Plains All American Pipeline, L.P. (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed November 21, 2006).

3.4		—	Amendment No. 3 dated August 16, 2007 to Third Amended and Restated Agreement of Limited Partnership of Plains All American Pipeline, L.P. (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed August 22, 2007).

3.5		—	Amendment No. 4 effective as of January 1, 2007 to Third Amended and Restated Agreement of Limited Partnership of Plains All American Pipeline, L.P. (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed April 15, 2008).

3.6		—	Amendment No. 5 dated May 28, 2008 to Third Amended and Restated Agreement of Limited Partnership of Plains All American Pipeline, L.P. (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed May 30, 2008).

3.7		—	Amendment No. 6 dated September 3, 2009 to Third Amended and Restated Agreement of Limited Partnership of Plains All American Pipeline, L.P. (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed September 3, 2009).

3.8		—	Third Amended and Restated Agreement of Limited Partnership of Plains Marketing, L.P. dated as of April 1, 2004 (incorporated by reference to Exhibit 3.2 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2004).

3.9	†	—	Amendment No. 1 dated December 31, 2010 to the Third Amended and Restated Agreement of Limited Partnership of Plains Marketing, L.P.

3.10	†	—	Amendment No. 2 dated January 1, 2011 to the Third Amended and Restated Agreement of Limited Partnership of Plains Marketing, L.P.

3.11		—	Third Amended and Restated Agreement of Limited Partnership of Plains Pipeline, L.P. dated as of April 1, 2004 (incorporated by reference to Exhibit 3.3 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2004).

3.12		—	Fifth Amended and Restated Limited Liability Company Agreement of Plains All American GP LLC dated December 23, 2010 (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed December 30, 2010).

3.13		—	Sixth Amended and Restated Limited Partnership Agreement of Plains AAP, L.P. dated December 23, 2010 (incorporated by reference to Exhibit 3.2 to the Current Report on Form 8-K filed December 30, 2010).

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3.14	—	Certificate of Incorporation of PAA Finance Corp (f/k/a Pacific Energy Finance Corporation, successor-by-merger to PAA Finance Corp.) (incorporated by reference to Exhibit 3.10 to the Annual Report on Form 10-K for the year ended December 31, 2006).

3.15	—	Bylaws of PAA Finance Corp (f/k/a Pacific Energy Finance Corporation, successor-by-merger to PAA Finance Corp.) (incorporated by reference to Exhibit 3.11 to the Annual Report on Form 10-K for the year ended December 31, 2006).

3.16	—	Limited Liability Company Agreement of PAA GP LLC dated December 28, 2007 (incorporated by reference to Exhibit 3.3 to the Current Report on Form 8-K filed January 4, 2008).

4.1	—	Indenture dated September 25, 2002 among Plains All American Pipeline, L.P., PAA Finance Corp. and Wachovia Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2002).

4.2	—	First Supplemental Indenture (Series A and Series B 7.75% Senior Notes due 2012) dated as of September 25, 2002 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and Wachovia Bank, National Association, as trustee (incorporated by reference to Exhibit 4.2 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2002).

4.3	—	Second Supplemental Indenture (Series A and Series B 5.625% Senior Notes due 2013) dated as of December 10, 2003 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and Wachovia Bank, National Association, as trustee (incorporated by reference to Exhibit 4.4 to the Annual Report on Form 10-K for the year ended December 31, 2003).

4.4	—	Fourth Supplemental Indenture (Series A and Series B 5.875% Senior Notes due 2016) dated August 12, 2004 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and Wachovia Bank, National Association, as trustee (incorporated by reference to Exhibit 4.5 to the Registration Statement on Form S-4, File No. 333-121168).

4.5	—	Fifth Supplemental Indenture (Series A and Series B 5.25% Senior Notes due 2015) dated May 27, 2005 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and Wachovia Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed May 31, 2005).

4.6	—	Sixth Supplemental Indenture (Series A and Series B 6.70% Senior Notes due 2036) dated May 12, 2006 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and Wachovia Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed May 12, 2006).

4.7	—	Seventh Supplemental Indenture dated May 12, 2006 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and Wachovia Bank, National Association, as trustee (incorporated by reference to Exhibit 4.3 to the Current Report on Form 8-K filed May 12, 2006).

4.8	—	Eighth Supplemental Indenture dated August 25, 2006 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and Wachovia Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed August 25, 2006).

4.9	—	Ninth Supplemental Indenture (Series A and Series B 6.125% Senior Notes due 2017) dated October 30, 2006 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed October 30, 2006).

4.10	—	Tenth Supplemental Indenture (Series A and Series B 6.650% Senior Notes due 2037) dated October 30, 2006 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to

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		Exhibit 4.2 to the Current Report on Form 8-K filed October 30, 2006).

4.11	—	Eleventh Supplemental Indenture dated November 15, 2006 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed November 21, 2006).

4.12	—	Twelfth Supplemental Indenture dated January 1, 2008 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.21 to the Annual Report on Form 10-K for the year ended December 31, 2007).

4.13	—	Thirteenth Supplemental Indenture (Series A and Series B 6.5% Senior Notes due 2018) dated April 23, 2008 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed April 23, 2008).

4.14	—	Fourteenth Supplemental Indenture dated July 1, 2008 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.15 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2008).

4.15	—	Fifteenth Supplemental Indenture (8.75% Senior Notes due 2019) dated April 20, 2009 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed April 20, 2009).

4.16	—	Sixteenth Supplemental Indenture (4.25% Senior Notes due 2012) dated July 23, 2009 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed July 23, 2009).

4.17	—	Seventeenth Supplemental Indenture (5.75% Senior Notes due 2020) dated September 4, 2009 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed September 4, 2009).

4.18	—	Eighteenth Supplemental Indenture (3.95% Senior Notes due 2015) dated July 14, 2010 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed July 13, 2010).

4.19	—	Nineteenth Supplemental Indenture (5.00% Senior Notes due 2021) dated January 14, 2011 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed January 11, 2011).

4.20	—	Registration Rights Agreement dated September 3, 2009 by and between Plains All American Pipeline, L.P. and Vulcan Gas Storage LLC (incorporated by reference to Exhibit 4.1 to the Registration Statement on Form S-3, File No. 333-162477).

10.1	—	Second Amended and Restated Credit Agreement dated as of July 31, 2006 by and among Plains All American Pipeline, L.P., as US Borrower; PMC (Nova Scotia) Company and Plains Marketing Canada, L.P., as Canadian Borrowers; Bank of America, N.A., as Administrative Agent; Bank of America, N.A., acting through its Canada Branch, as Canadian Administrative Agent; Wachovia Bank, National Association and J. P. Morgan Chase Bank, N.A., as Co-Syndication Agents; Fortis Capital Corp., Citibank, N.A., BNP Paribas, UBS Securities LLC, SunTrust Bank, and The Bank of Nova Scotia, as Co-Documentation Agents; the Lenders party thereto; and Banc of America Securities LLC

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			and Wachovia Capital Markets, LLC, as Joint Lead Arrangers and Joint Book Managers (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed August 4, 2006).

10.2		—	Amended and Restated Crude Oil Marketing Agreement dated as of July 23, 2004, among Plains Resources Inc., Calumet Florida Inc. and Plains Marketing, L.P. (incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2004).

10.3		—	Amended and Restated Omnibus Agreement dated as of July 23, 2004, among Plains Resources Inc., Plains All American Pipeline, L.P., Plains Marketing, L.P., Plains Pipeline, L.P. and Plains All American GP LLC (incorporated by reference to Exhibit 10.3 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2004).

10.4		—	Contribution, Assignment and Amendment Agreement dated as of June 27, 2001, among Plains All American Pipeline, L.P., Plains Marketing, L.P., All American Pipeline, L.P., Plains AAP, L.P., Plains All American GP LLC and Plains Marketing GP Inc. (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed June 27, 2001).

10.5		—	Contribution, Assignment and Amendment Agreement dated as of June 8, 2001, among Plains All American Inc., Plains AAP, L.P. and Plains All American GP LLC (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed June 11, 2001).

10.6		—	Separation Agreement dated as of June 8, 2001 among Plains Resources Inc., Plains All American Inc., Plains All American GP LLC, Plains AAP, L.P. and Plains All American Pipeline, L.P. (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed June 11, 2001).

10.7	**	—	Pension and Employee Benefits Assumption and Transition Agreement dated as of June 8, 2001 among Plains Resources Inc., Plains All American Inc. and Plains All American GP LLC (incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K filed June 11, 2001).

10.8	**	—	Plains All American GP LLC 2005 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed January 26, 2005).

10.9	**	—	Plains All American GP LLC 1998 Long-Term Incentive Plan (incorporated by reference to Exhibit 99.1 to Registration Statement on Form S-8, File No. 333-74920) as amended June 27, 2003 (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2003).

10.10	**	—	Plains All American 2001 Performance Option Plan (incorporated by reference to Exhibit 99.2 to the Registration Statement on Form S-8 filed December 11, 2001, File No. 333-74920).

10.11	**	—	Amended and Restated Employment Agreement between Plains All American GP LLC and Greg L. Armstrong dated as of June 30, 2001 (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2001).

10.12	**	—	Amended and Restated Employment Agreement between Plains All American GP LLC and Harry N. Pefanis dated as of June 30, 2001 (incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2001).

10.13		—	Asset Purchase and Sale Agreement dated February 28, 2001 between Murphy Oil Company Ltd. and Plains Marketing Canada, L.P. (incorporated by reference to Exhibit 99.1 to the Current Report on Form 8-K filed May 10, 2001).

10.14		—	Transportation Agreement dated July 30, 1993, between All American Pipeline Company and Exxon Company, U.S.A. (incorporated by reference to Exhibit 10.9 to the Registration Statement on Form S-1 filed September 23, 1998, File No. 333-64107).

10.15		—	Transportation Agreement dated August 2, 1993, among All American Pipeline Company, Texaco Trading and Transportation Inc., Chevron U.S.A. and Sun Operating Limited Partnership (incorporated by reference to Exhibit 10.10 to the Registration Statement on Form S-1 filed September 23, 1998, File

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			No. 333-64107).

10.16		—	First Amendment to Contribution, Conveyance and Assumption Agreement dated as of December 15, 1998 (incorporated by reference to Exhibit 10.13 to the Annual Report on Form 10-K for the year ended December 31, 1998).

10.17		—	Agreement for Purchase and Sale of Membership Interest in Scurlock Permian LLC between Marathon Ashland LLC and Plains Marketing, L.P. dated as of March 17, 1999 (incorporated by reference to Exhibit 10.16 to the Annual Report on Form 10-K for the year ended December 31, 1998).

10.18	**	—	Plains All American Inc. 1998 Management Incentive Plan (incorporated by reference to Exhibit 10.5 to the Annual Report on Form 10-K for the year ended December 31, 1998).

10.19	**	—	PMC (Nova Scotia) Company Bonus Program (incorporated by reference to Exhibit 10.20 to the Annual Report on Form 10-K for the year ended December 31, 2004).

10.20	**	—	Quarterly Bonus Program Summary (incorporated by reference to Exhibit 10.21 to the Annual Report on Form 10-K for the year ended December 31, 2005).

10.21	**†	—	Directors’ Compensation Summary.

10.22		—	Master Railcar Leasing Agreement dated as of May 25, 1998 (effective June 1, 1998), between Pivotal Enterprises Corporation and CANPET Energy Group, Inc., (incorporated by reference to Exhibit 10.16 to the Annual Report on Form 10-K for the year ended December 31, 2001).

10.23	**	—	Form of LTIP Grant Letter (Armstrong/Pefanis) (incorporated by reference to Exhibit 10.24 to the Annual Report on Form 10-K for the year ended December 31, 2005).

10.24	**	—	Form of LTIP Grant Letter (executive officers) (incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K filed April 1, 2005).

10.25	**	—	Form of LTIP Grant Letter (independent directors) (incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K filed February 23, 2005).

10.26	**	—	Form of LTIP Grant Letter (designated directors) (incorporated by reference to Exhibit 10.4 to the Current Report on Form 8-K filed February 23, 2005).

10.27	**	—	Form of LTIP Grant Letter (payment to entity) (incorporated by reference to Exhibit 10.5 to the Current Report on Form 8-K filed February 23, 2005).

10.28	**	—	Form of Performance Option Grant Letter (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed April 1, 2005).

10.29		—	Administrative Services Agreement between Plains All American GP LLC and Vulcan Energy Corporation dated October 14, 2005 (incorporated by reference to Exhibit 1.1 to the Current Report on Form 8-K filed October 19, 2005).

10.30		—	Membership Interest Purchase Agreement by and between Sempra Energy Trading Corp. and PAA/Vulcan Gas Storage, LLC dated August 19, 2005 (incorporated by reference to Exhibit 1.2 to the Current Report on Form 8-K filed September 19, 2005).

10.31	**†	—	Waiver Agreement dated as of December 23, 2010 between Plains All American GP LLC and Greg L. Armstrong.

10.32	**†	—	Waiver Agreement dated as of December 23, 2010 between Plains All American GP LLC and Harry N. Pefanis.

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10.33		—	Excess Voting Rights Agreement dated as of August 12, 2005 between Vulcan Energy GP Holdings Inc. and Plains All American GP LLC (incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K filed August 16, 2005).

10.34		—	Excess Voting Rights Agreement dated as of August 12, 2005 between Lynx Holdings I, LLC and Plains All American GP LLC (incorporated by reference to Exhibit 10.4 to the Current Report on Form 8-K filed August 16, 2005).

10.35	**	—	Form of LTIP Grant Letter (executive officers) (incorporated by reference to Exhibit 10.39 to the Annual Report on Form 10-K for the year ended December 31, 2005).

10.36	**	—	Employment Agreement between Plains All American GP LLC and John P. vonBerg dated December 18, 2001 (incorporated by reference to Exhibit 10.40 to the Annual Report on Form 10-K for the year ended December 31, 2005).

10.37	**	—	Form of LTIP Grant Letter (audit committee members) (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed August 23, 2006).

10.38	**	—	Plains All American PPX Successor Long-Term Incentive Plan (incorporated by reference to Exhibit 10.45 to the Annual Report on Form 10-K for the year ended December 31, 2006).

10.39	**	—	Forms of LTIP Grant Letters dated February 22, 2007 (Named Executive Officers) (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2007).

10.40		—	First Amendment dated July 31, 2007 to the Second Amended and Restated Credit Agreement [US/Canada Facilities] by and between Plains All American Pipeline, L.P., PMC (Nova Scotia) Company, Plains Marketing Canada, L.P., Rangeland Pipeline Company, Bank of America, N.A., as Administrative Agent, and the Lenders party thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed August 6, 2007).

10.41	**	—	Separation and Release Agreement dated August 21, 2007 between Plains All American GP LLC and George R. Coiner (incorporated by reference to Exhibit 10.3 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2007).

10.42	**	—	Form of Plains AAP, L.P. Class B Restricted Units Agreement (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed January 4, 2008).

10.43		—	Second Restated Credit Agreement dated as of November 6, 2008 by among Plains Marketing, L.P., Bank of America, N.A., as Administrative Agent, and the Lenders party there to (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed November 7, 2008).

10.44		—	Second Amendment to Second Restated Credit Agreement dated as of October 25, 2010, by and among Plains Marketing, L.P., Bank of America, N.A., as Administrative Agent, and the Lenders party thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed October 28, 2010).

10.45		—	Restated Guaranty Agreement dated November 6, 2008 by Plains All American Pipeline, L.P. in favor of Bank of America, N.A., as Administrative Agent (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed November 7, 2008).

10.46		—	Contribution and Assumption Agreement dated December 28, 2007, by and between Plains AAP, L.P. and PAA GP LLC (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed January 4, 2008).

10.47		—	Assumption, Ratification and Confirmation Agreement dated January 1, 2008 by Plains Midstream Canada ULC in favor of the Lenders party to the Second Amended and Restated Credit Agreement [US/Canada Facilities], as amended (incorporated by reference to Exhibit 10.54 to the Annual Report on Form 10-K for the year ended December 31, 2007).

10.48	†	—	Assumption, Ratification and Confirmation Agreement dated January 1, 2011 by Plains Midstream

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			Canada ULC in favor of the Lenders party to the Second Amended and Restated Credit Agreement [US/Canada Facilities], as amended.

10.49	**	—	First Amendment to Amended and Restated Employment Agreement dated December 4, 2008 between Plains All American GP LLC and Greg L. Armstrong (incorporated by reference to Exhibit 10.49 to the Annual Report on Form 10-K for the year ended December 31, 2008).

10.50	**	—	First Amendment to Amended and Restated Employment Agreement dated December 4, 2008 between Plains All American GP LLC and Harry N. Pefanis (incorporated by reference to Exhibit 10.50 to the Annual Report on Form 10-K for the year ended December 31, 2008).

10.51	**	—	First Amendment to Plains All American GP LLC 2005 Long-Term Incentive Plan dated December 4, 2008 (incorporated by reference to Exhibit 10.51 to the Annual Report on Form 10-K for the year ended December 31, 2008).

10.52	**	—	Second Amendment to Plains All American GP LLC 1998 Long-Term Incentive Plan dated December 4, 2008 (incorporated by reference to Exhibit 10.52 to the Annual Report on Form 10-K for the year ended December 31, 2008).

10.53	**	—	Form of Amendment to LTIP grant letters (executive officers) (incorporated by reference to Exhibit 10.53 to the Annual Report on Form 10-K for the year ended December 31, 2008).

10.54	**	—	Form of Amendment to LTIP grant letters (directors) (incorporated by reference to Exhibit 10.54 to the Annual Report on Form 10-K for the year ended December 31, 2008).

10.55		—	Contribution Agreement dated as of April 29, 2010 by and among PAA Natural Gas Storage, L.P., PNGS GP LLC, Plains All American Pipeline, L.P., PAA Natural Gas Storage, LLC, PAA/Vulcan Gas Storage, LLC, Plains Marketing, L.P. and Plains Marketing GP Inc. (incorporated by reference to Exhibit 10.1 to PNG’s Current Report on Form 8-K filed May 4, 2010).

10.56		—	Omnibus Agreement dated May 5, 2010 by and among Plains All American GP LLC, Plains All American Pipeline, L.P., PNGS GP LLC and PAA Natural Gas Storage, L.P. (incorporated by reference to Exhibit 10.1 to PNG’s Current Report on Form 8-K filed May 11, 2010).

10.57	**	—	Form of Transaction Grant Agreement (incorporated by reference to Exhibit 10.3 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2010).

10.58	**†	—	Form of 2010 LTIP Grant Letters.

10.59	**†	—	Employment Agreement between Plains All American GP LLC and John R. Rutherford dated September 27, 2010.

10.60		—	364-Day Credit Agreement dated January 3, 2011 among Plains All American Pipeline, L.P., as Borrower; Bank of America, N.A., as Administrative Agent; DnB NOR Bank ASA and JPMorgan Chase Bank NA, as Co-Syndication Agents; SunTrust Bank and Wells Fargo Bank, National Association, as Co-Documentation Agents; the Lenders party thereto; and Merrill Lynch, Pierce, Fenner & Smith Incorporated, DnB NOR Markets, Inc. and J.P. Morgan Securities LLC, as Joint Lead Arrangers and Joint Book Managers (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed January 7, 2011).

12.1	†	—	Computation of Ratio of Earnings to Fixed Charges

21.1	†	—	List of Subsidiaries of Plains All American Pipeline, L.P.

23.1	†	—	Consent of PricewaterhouseCoopers LLP.

31.1	†	—	Certification of Principal Executive Officer pursuant to Exchange Act Rules 13a-14(a) and 15d-14(a).

31.2	†	—	Certification of Principal Financial Officer pursuant to Exchange Act Rules 13a-14(a) and 15d-14(a).

32.1	†	—	Certification of Principal Executive Officer pursuant to 18 U.S.C. 1350

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32.2	†	—	Certification of Principal Financial Officer pursuant to 18 U.S.C. 1350

101	†	—	The following financial information from the annual report on Form 10-K of Plains All American Pipeline, L.P. for the year ended December 31, 2010, formatted in XBRL (extensible Business Reporting Language): (i) Consolidated Statements of Operations, (ii) Consolidated Balance Sheets, (iii) Consolidated Statements of Cash Flows, (iv) Consolidated Statements of Changes in Partners’ Capital, (v) Consolidated Statements of Comprehensive Income, (vi) Consolidated Statements of Changes in Accumulated Other Comprehensive Income and (vii) Notes to the Consolidated Financial Statements.

† Filed herewith

** Management compensatory plan or arrangement

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	PLAINS ALL AMERICAN PIPELINE, L.P.

	By:	PAA GP LLC,
		its general partner

	By:	Plains AAP, L.P.,
		its sole member

	By:	PLAINS ALL AMERICAN GP LLC,
		its general partner

	By:	/s/ GREG L. ARMSTRONG
		Greg L. Armstrong, Chairman of the Board, Chief Executive Officer and Director of Plains All American GP LLC (Principal Executive Officer)

February 25, 2011

	By:	/s/ AL SWANSON
		Al Swanson, Executive Vice President and Chief Financial Officer of Plains All American GP LLC (Principal Financial Officer)

February 25, 2011

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Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Name	Title	Date

/s/ GREG L. ARMSTRONG	Chairman of the Board, Chief Executive Officer and Director of Plains All American GP LLC (Principal Executive Officer)	February 25, 2011
Greg L. Armstrong		February 25, 2011

/s/ HARRY N. PEFANIS	President and Chief Operating Officer of Plains All American GP LLC	February 25, 2011
Harry N. Pefanis		February 25, 2011

/s/ AL SWANSON	Executive Vice President and Chief Financial Officer of Plains All American GP LLC (Principal Financial Officer)	February 25, 2011
Al Swanson		February 25, 2011

/s/ CHRIS HERBOLD	Vice President—Accounting and Chief Accounting Officer of Plains All American GP LLC (Principal Accounting Officer)	February 25, 2011
Chris Herbold		February 25, 2011

/s/ EVERARDO GOYANES	Director of Plains All American GP LLC	February 25, 2011
Everardo Goyanes

/s/ GARY R. PETERSEN	Director of Plains All American GP LLC	February 25, 2011
Gary R. Petersen

/s/ JOHN T. RAYMOND	Director of Plains All American GP LLC	February 25, 2011
John T. Raymond

/s/ ROBERT V. SINNOTT	Director of Plains All American GP LLC	February 25, 2011
Robert V. Sinnott

/s/ VICKY SUTIL	Director of Plains All American GP LLC	February 25, 2011
Vicky Sutil

/s/ J. TAFT SYMONDS	Director of Plains All American GP LLC	February 25, 2011
J. Taft Symonds

/s/ CHRISTOPHER M. TEMPLE	Director of Plains All American GP LLC	February 25, 2011
Christopher M. Temple

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

INDEX TO THE CONSOLIDATED FINANCIAL STATEMENTS

	Page
Consolidated Financial Statements
Management’s Report on Internal Control Over Financial Reporting	F-2
Report of Independent Registered Public Accounting Firm	F-3
Consolidated Balance Sheets as of December 31, 2010 and 2009	F-4
Consolidated Statements of Operations for the years ended December 31, 2010, 2009 and 2008	F-5
Consolidated Statements of Cash Flows for the years ended December 31, 2010, 2009 and 2008	F-6
Consolidated Statements of Changes in Partners’ Capital for the years ended December 31, 2010, 2009 and 2008	F-7
Consolidated Statements of Comprehensive Income for the years ended December 31, 2010, 2009 and 2008	F-8
Consolidated Statements of Changes in Accumulated Other Comprehensive Income for the years ended December 31, 2010, 2009 and 2008	F-8
Notes to the Consolidated Financial Statements	F-9

F-1

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MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Plains All American Pipeline, L.P.’s management is responsible for establishing and maintaining adequate internal control over financial reporting. Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

Internal control over financial reporting cannot provide absolute assurance of achieving financial reporting objectives because of its inherent limitations. Internal control over financial reporting is a process that involves human diligence and compliance and is subject to lapses in judgment and breakdowns resulting from human failures. Internal control over financial reporting also can be circumvented by collusion or improper management override. Because of such limitations, there is a risk that material misstatements may not be prevented or detected on a timely basis by internal control over financial reporting. However, these inherent limitations are known features of the financial reporting process. Therefore, it is possible to design into the process safeguards to reduce, though not eliminate, this risk.

Management has used the framework set forth in the report entitled “Internal Control—Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) to evaluate the effectiveness of the Partnership’s internal control over financial reporting. Based on that evaluation, management has concluded that the Partnership’s internal control over financial reporting was effective as of December 31, 2010.

The effectiveness of the Partnership’s internal control over financial reporting as of December 31, 2010 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears on Page F-3.

	/s/ GREG L. ARMSTRONG
	Greg L. Armstrong Chairman of the Board, Chief Executive Officer and Director of Plains All American GP LLC (Principal Executive Officer)

	/s/ AL SWANSON
	Al Swanson Executive Vice President and Chief Financial Officer of Plains All American GP LLC (Principal Financial Officer)

February 25, 2011

F-2

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Report of Independent Registered Public Accounting Firm

To the Board of Directors of the General Partner and Unitholders of

Plains All American Pipeline, L.P.:

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, of cash flows, of changes in partners’ capital, of comprehensive income, and of changes in accumulated other comprehensive income, present fairly, in all material respects, the financial position of Plains All American Pipeline, L.P. and its subsidiaries at December 31, 2010 and 2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Partnership’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express opinions on these financial statements and on the Partnership’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Houston, Texas	PricewaterhouseCoopers LLP
February 25, 2011

F-3

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in millions, except units)

	December 31,			December 31,
	2010			2009
ASSETS

CURRENT ASSETS
Cash and cash equivalents	$	36		$	25
Restricted cash	20			—
Trade accounts receivable and other receivables, net	2,746			2,253
Inventory	1,491			1,157
Other current assets	88			223
Total current assets	4,381			3,658

PROPERTY AND EQUIPMENT	7,814			7,240
Accumulated depreciation	(1,123		)	(900		)
	6,691			6,340

OTHER ASSETS
Goodwill	1,376			1,287
Linefill and base gas	519			501
Long-term inventory	154			121
Investments in unconsolidated entities	200			82
Other, net	382			369
Total assets	$	13,703		$	12,358

LIABILITIES AND PARTNERS’ CAPITAL

CURRENT LIABILITIES
Accounts payable and accrued liabilities	$	2,738		$	2,295
Short-term debt	1,326			1,074
Other current liabilities	151			413
Total current liabilities	4,215			3,782

LONG-TERM LIABILITIES
Senior notes, net of unamortized discount of $12 and $14, respectively	4,363			4,136
Long-term debt under credit facilities and other	268			6
Other long-term liabilities and deferred credits	284			275
Total long-term liabilities	4,915			4,417

COMMITMENTS AND CONTINGENCIES (NOTE 11)

PARTNERS’ CAPITAL
Common unitholders (141,199,175 and 136,135,988 units outstanding, respectively)	4,234			4,002
General partner	108			94
Total partners’ capital excluding noncontrolling interests	4,342			4,096
Noncontrolling interests	231			63
Total partners’ capital	4,573			4,159
Total liabilities and partners’ capital	$	13,703		$	12,358

The accompanying notes are an integral part of these consolidated financial statements.

F-4

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in millions, except per unit data)

	Year Ended December 31,
	2010			2009			2008
REVENUES
Supply & Logistics segment revenues	$	24,989		$	17,757		$	29,348
Transportation segment revenues	565			536			556
Facilities segment revenues	339			227			157
Total revenues	25,893			18,520			30,061

COSTS AND EXPENSES
Purchases and related costs	23,921			16,656			28,479
Field operating costs	689			638			617
General and administrative expenses	260			211			160
Depreciation and amortization	256			236			211
Total costs and expenses	25,126			17,741			29,467

OPERATING INCOME	767			779			594

OTHER INCOME/(EXPENSE)
Equity earnings in unconsolidated entities	3			15			14
Interest expense (net of capitalized interest of $16, $15 and $17, respectively)	(248		)	(224		)	(196		)
Other income/(expense), net	(9		)	16			33

INCOME BEFORE TAX	513			586			445
Current income tax (expense)/benefit	1			(15		)	(9		)
Deferred income tax benefit	—			9			1

NET INCOME	514			580			437
Less: Net income attributable to noncontrolling interests	(9		)	(1		)	—
NET INCOME ATTRIBUTABLE TO PLAINS	$	505		$	579		$	437

NET INCOME ATTRIBUTABLE TO PLAINS:
LIMITED PARTNERS	$	338		$	443		$	325
GENERAL PARTNER	$	167		$	136		$	112

BASIC NET INCOME PER LIMITED PARTNER UNIT	$	2.41		$	3.34		$	2.66

DILUTED NET INCOME PER LIMITED PARTNER UNIT	$	2.40		$	3.32		$	2.64

BASIC WEIGHTED AVERAGE UNITS OUTSTANDING	137			130			120

DILUTED WEIGHTED AVERAGE UNITS OUTSTANDING	138			131			121

The accompanying notes are an integral part of these consolidated financial statements.

F-5

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)

	Year Ended December 31,
	2010			2009			2008
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	514		$	580		$	437
Reconciliation of net income to net cash provided by operating activities:
Depreciation and amortization	256			236			211
Equity compensation expense	98			68			24
Inventory valulation adjustments	3			—			168
Gain on sale of linefill	(21		)	(4		)	(3		)
Gain on sale of investment assets	—			—			(12		)
Deferred income tax benefit	—			(9		)	(1		)
(Gain)/loss on foreign currency revaluation	(2		)	(13		)	22
Equity earnings in unconsolidated entities, net of distributions	6			(8		)	(4		)
Net cash received/(paid) for terminated interest rate and foreign currency hedging instruments	—			(9		)	15
Net gain on purchase of remaining 50% interest in PAA/Vulcan	—			(9		)	—
Other	10			(6		)	2
Changes in assets and liabilities, net of acquisitions:
Trade accounts receivable and other	(59		)	(744		)	668
Inventory	(336		)	(319		)	(120		)
Accounts payable and other current liabilities	(210		)	602			(550		)
Net cash provided by operating activities	259			365			857

CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid in connection with acquisitions, net of cash acquired (Note 3)	(407		)	(219		)	(709		)
Restricted cash in escrow for acquisitions	(20		)	—			—
Additions to property, equipment and other	(451		)	(460		)	(589		)
Investment in unconsolidated entities	—			(4		)	(37		)
Net cash received/(paid) for sales and purchases of linefill and base gas	25			(9		)	(55		)
Cash received for sale of noncontrolling interest in a subsidiary	268			26			—
Proceeds from sales of assets and other investing activities	2			6			51
Net cash used in investing activities	(583		)	(660		)	(1,339		)

CASH FLOWS FROM FINANCING ACTIVITIES
Net borrowings/(repayments) on PAA’s revolving credit facility	49			(19		)	286
Net borrowings on PNG’s revolving credit facility	260			—			—
Net borrowings/(repayments) on PAA’s hedged inventory facility	200			20			(196		)
Repayment of PNGS debt	—			(446		)	—
Proceeds from the issuance of senior notes	400			1,346			597
Repayments of senior notes	(175		)	(430		)	—
Net proceeds from the issuance of common units (Note 5)	296			458			315
Distributions paid to common unitholders (Note 5)	(512		)	(468		)	(418		)
Distributions paid to general partner (Note 5)	(170		)	(137		)	(114		)
Distributions to noncontrolling interests (Note 5)	(10		)	(2		)	—
Other financing activities	(2		)	(10		)	(6		)
Net cash provided by financing activities	336			312			464

Effect of translation adjustment on cash	(1		)	(3		)	5

Net increase/(decrease) in cash and cash equivalents	11			14			(13		)
Cash and cash equivalents, beginning of period	25			11			24
Cash and cash equivalents, end of period	$	36		$	25		$	11

Cash paid for interest, net of amounts capitalized	$	253		$	214		$	206

Cash paid for income taxes, net of amounts refunded	$	21		$	(5	)	$	15

The accompanying notes are an integral part of these consolidated financial statements.

F-6

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS’ CAPITAL

(in millions)

								Partners’ Capital
								Excluding
	Common Units				General			Noncontrolling			Noncontrolling			Partners’
	Units	Amount			Partner			Interests			Interests			Capital
Balance at December 31, 2007	116	$	3,343		$	81		$	3,424		$	—		$	3,424

Net income	—	325			112			437			—			437
Distributions	—	(418		)	(114		)	(532		)	—			(532		)
Issuance of common units	7	309			6			315			—			315
Issuance of common units under Long Term Incentive Plans (“LTIP”)	—	1			—			1			—			1
Class B Units of Plains AAP, L.P. (Note 10)	—	12			—			12			—			12
Other comprehensive loss	—	(103		)	(2		)	(105		)	—			(105		)
Balance at December 31, 2008	123	$	3,469		$	83		$	3,552		$	—		$	3,552

Sale of noncontrolling interest in a subsidiary	—	(37		)	(1		)	(38		)	64			26
Net income	—	443			136			579			1			580
Distributions	—	(468		)	(137		)	(605		)	(2		)	(607		)
Issuance of common units	11	447			9			456			—			456
Issuance of common units in connection with the PNGS Acquisition	2	91			2			93			—			93
Issuance of common units under LTIP	—	12			—			12			—			12
Class B Units of Plains AAP, L.P. (Note 10)	—	2			3			5			—			5
Other comprehensive income	—	46			2			48			—			48
Other	—	(3		)	(3		)	(6		)	—			(6		)
Balance at December 31, 2009	136	$	4,002		$	94		$	4,096		$	63		$	4,159

Sale of noncontrolling interest in a subsidiary	—	99			2			101			167			268
Net income	—	338			167			505			9			514
Distributions	—	(512		)	(170		)	(682		)	(10		)	(692		)
Issuance of common units	5	290			6			296			—			296
Issuance of common units under LTIP	—	16			—			16			—			16
Equity compensation expense under LTIP	—	4			—			4			3			7
Class B Units of Plains AAP, L.P. (Note 10)	—	—			9			9			—			9
Other comprehensive loss	—	(5		)	—			(5		)	—			(5		)
Other	—	2			—			2			(1		)	1
Balance at December 31, 2010	141	$	4,234		$	108		$	4,342		$	231		$	4,573

The accompanying notes are an integral part of these consolidated financial statements.

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(in millions)

	Year Ended December 31,
	2010			2009			2008
Net income	$	514		$	580		$	437
Other comprehensive income/(loss)	(5		)	48			(105		)
Comprehensive income	509			628			332
Less: Comprehensive income attributable to noncontrolling interests	(9		)	(1		)	—
Comprehensive income attributable to Plains	$	500		$	627		$	332

CONSOLIDATED STATEMENTS OF CHANGES IN ACCUMULATED
OTHER COMPREHENSIVE INCOME

(in millions)

	Derivative			Translation
	Instruments			Adjustments			Other			Total
Balance at December 31, 2007	$	4		$	176		$	—		$	180

Reclassification adjustments	46			—			—			46
Net deferred gain on cash flow hedges	111			—			—			111
Currency translation adjustment	—			(262		)	—			(262		)
2008 Activity	157			(262		)	—			(105		)
Balance at December 31, 2008	$	161		$	(86	)	$	—		$	75

Reclassification adjustments	8			—			—			8
Net deferred loss on cash flow hedges	(151		)	—			—			(151		)
Currency translation adjustment	—			192			—			192
Proportionate share of our unconsolidated entities’ other comprehensive loss	—			—			(1		)	(1		)
2009 Activity	(143		)	192			(1		)	48
Balance at December 31, 2009	$	18		$	106		$	(1	)	$	123

Reclassification adjustments	(24		)	—			—			(24		)
Deferred loss on cash flow hedges, net of tax benefit	(73		)	—			—			(73		)
Currency translation adjustment	—			92			—			92
2010 Activity	(97		)	92			—			(5		)
Balance at December 31, 2010	$	(79	)	$	198		$	(1	)	$	118

The accompanying notes are an integral part of these consolidated financial statements.

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Note 1—Organization and Basis of Presentation

Organization

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, the terms “Partnership,” “Plains,” “PAA,” “we,” “us,” “our,” “ours” and similar terms refer to Plains All American Pipeline, L.P. and its subsidiaries, unless the context indicates otherwise.

We engage in the transportation, storage, terminalling and marketing of crude oil, refined products and LPG. Through our general partner interest and majority equity ownership position in PAA Natural Gas Storage, L.P. (NYSE: PNG), we also engage in the development and operation of natural gas storage facilities. Our business activities are conducted through three operating segments: (i) Transportation, (ii) Facilities and (iii) Supply and Logistics. See Note 15 for further discussion of our three operating segments.

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. Plains All American GP LLC manages our operations and activities and employs our domestic officers and personnel. Our Canadian officers and personnel are employed by our subsidiary Plains Midstream Canada ULC. 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 essentially held by 18 owners with interests ranging from approximately 35% to less than 1%.

Definitions

The following additional defined terms are used in this Part IV and shall have the meanings indicated below:

AOCI	=	Accumulated other comprehensive income
Bcf	=	Billion cubic feet
Btu	=	British thermal unit
CAD	=	Canadian dollar
CERCLA	=	Federal Comprehensive Environmental Response, Compensation and Liability Act, as amended
DERs	=	Distribution equivalent rights
EBITDA	=	Earnings before interest taxes depreciation and amortization
FASB	=	Financial Accounting Standards Board
FERC	=	Federal Energy Regulatory Commission
GAAP	=	Generally accepted accounting principles in the United States
GATX	=	GATX Corporation
HEP	=	Holly Energy Partners-Operating, L.P.
ICE	=	IntercontinentalExchange
IPO	=	Initial public offering
LIBOR	=	London Interbank Offered Rate
Link	=	Link Energy LLC
LPG	=	Liquefied petroleum gas and other natural gas-related petroleum products
LTIP	=	Long-term incentive plan
Mcf	=	Thousand cubic feet

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MLP	=	Master limited partnership
MTBE	=	Methyl tertiary-butyl ether
MQD	=	Minimum quarterly distribution
Nexen	=	Nexen Holdings U.S.A. Inc.
NJDEP	=	New Jersey Department of Environmental Protection
NPNS	=	Normal purchase normal sale
NYMEX	=	New York Mercantile Exchange
PAA/Vulcan	=	PAA/Vulcan Gas Storage, LLC
Pacific	=	Pacific Energy Partners, L.P.
PLA	=	Pipeline loss allowance
PNG	=	PAA Natural Gas Storage, L.P.
PNGS	=	PAA Natural Gas Storage, LLC
PPT	=	Plains Products Terminals LLC (formerly known as Pacific Atlantic Terminals LLC)
Rainbow	=	Rainbow Pipe Line Company, Ltd.
RCRA	=	Federal Resource Conservation and Recovery Act, as amended
RMPS	=	Rocky Mountain Pipeline System
SG Resources	=	SG Resources Mississippi, LLC
SLC Pipeline	=	SLC Pipeline LLC
SOP	=	Shell Oil Products
TNM	=	Texas New Mexico
USD	=	United States dollar
VIE	=	Variable interest entity
White Cliffs	=	White Cliffs Pipeline, LLC
WTI	=	West Texas Intermediate
WTS	=	West Texas Sour

Basis of Consolidation and Presentation

The accompanying financial statements and related notes present and discuss our consolidated financial position as of December 31, 2010 and 2009, and the consolidated results of our operations, cash flows, changes in partners’ capital, comprehensive income and changes in accumulated other comprehensive income for the years ended December 31, 2010, 2009 and 2008. All significant intercompany transactions have been eliminated in consolidation, and certain reclassifications have been made to information from previous years to conform to the current presentation. These reclassifications do not affect net income attributable to Plains. The accompanying consolidated financial statements include Plains and all of its wholly owned subsidiaries. Investments in entities over which we have significant influence but not control are accounted for by the equity method. We evaluate our equity investments for impairment in accordance with FASB guidance with respect to the equity method of accounting for investments in common stock. An impairment of an equity investment results when factors indicate that the investment’s fair value is less than its carrying value and the reduction in value is other than temporary in nature.

Subsequent events have been evaluated through the financial statements issuance date and have been included within the following footnotes where applicable.

Note 2—Summary of Significant Accounting Policies

Use of Estimates

The preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. We make significant estimates with respect to (i) purchases and sales accruals, (ii) estimated fair value of assets and liabilities acquired and identification of associated goodwill and intangible assets, (iii) mark-to-market gains and losses on derivative instruments (pursuant to guidance issued by the FASB regarding fair value measurements), (iv) accruals and contingent liabilities, (v) equity compensation plan accruals, (vi) property and equipment and depreciation expense and (vii) allowance for doubtful accounts. Although we believe these estimates are reasonable, actual results could differ from these estimates.

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Revenue Recognition

Supply and Logistics Segment Revenues. Revenues from sales of crude oil, LPG and refined products are recognized at the time title to the product sold transfers to the purchaser, which occurs upon delivery of the product to the purchaser or its designee. Sales of crude oil, LPG and refined products consist of outright sales contracts and buy/sell arrangements as well as exchanges. Inventory purchases and sales under buy/sell transactions are treated as inventory exchanges and are presented net within Supply and Logistics segment revenues in our consolidated statements of operations.

Additionally, we may utilize derivatives in connection with the transactions described above. For commodity derivatives that are designated as cash flow hedges, derivative gains and losses are deferred to AOCI and recognized in revenues in the periods during which the underlying physical hedged transaction impacts earnings. Also, the ineffective portion of the change in fair value of cash flow hedges is recognized in revenues each period along with the change in fair value of derivatives that do not qualify for hedge accounting or are not designated for hedge accounting.

Transportation Segment Revenues. Revenues from pipeline tariffs and fees are associated with the transportation of crude oil and refined products at a published tariff, as well as revenues associated with line leases for committed space on a particular system that may or may not be utilized. Tariff revenues are recognized either at the point of delivery or at the point of receipt pursuant to specifications outlined in the regulated and non-regulated tariffs. Revenues associated with line-lease fees are recognized in the month to which the lease applies, whether or not the space is actually utilized, and are subject to make up rights for take or pay arrangements. All pipeline tariff and fee revenues are based on actual volumes and rates. As is common in the industry, our tariffs incorporate a loss allowance factor that is intended to, among other things, offset losses due to evaporation, measurement and other losses in transit. We value the variance of allowance volumes to actual losses at the estimated net realizable value (including the impact of gains and losses from derivative related activities) at the time the variance occurred and the result is recorded as either an increase or decrease to tariff revenues. In addition, we have certain agreements that require counterparties to ship a minimum volume over an agreed upon period. Revenue is recognized at the latter of when the volume is shipped (pursuant to specifications outlined in the tariffs) or when the counterparty’s ability to make up the minimum volume has expired.

Facilities Segment Revenues. Storage and terminalling revenues include (i) storage fees that are generated when we lease storage capacity, (ii) terminalling fees, or throughput fees, that are generated when we receive crude oil, refined products, LPG or natural gas from one connecting pipeline and redeliver the applicable product to another connecting carrier, (iii) hub service fees for the movement of natural gas across our header systems and (iv) fees from LPG fractionation and isomerization services. We generate revenue through a combination of month-to-month and multi-year leases and processing arrangements. Storage fees resulting from short-term and long-term contracts are typically recognized in revenue ratably over the term of the contract regardless of the actual storage capacity utilized. Terminal fees are recognized as the crude oil, LPG or refined product exits the terminal and is delivered to the connecting carrier or third-party terminal. Hub service fees are recognized in the period the natural gas moves across our header system. In addition, we have certain agreements that require counterparties to throughput a minimum volume over an agreed upon period. Revenue is recognized at the latter of when the volume exits the terminal or when the counterparty’s ability to make up the minimum volume has expired.

Purchases and Related Costs

Purchases and related costs include (i) the cost of crude oil, LPG and refined products obtained in outright purchases, (ii) fees incurred for third-party transportation and storage, whether by pipeline, truck, ship or barge, (iii) interest cost attributable to borrowings for inventory stored in a contango market and (iv) performance-related bonus accruals. These costs are recognized when incurred except in the case of products purchased, which are recognized at the time title transfers to us.

Field Operating Costs and General and Administrative Expenses

Field operating costs consist of various field operating expenses, including fuel and power costs, telecommunications, payroll and benefit costs (including equity compensation expense) for truck drivers and field personnel, maintenance and integrity management costs, regulatory compliance, environmental remediation, insurance, vehicle leases, and property taxes. General and administrative expenses consist primarily of payroll and benefit costs (including equity compensation expense), certain information systems and legal costs, office rent, contract and consultant costs and audit and tax fees.

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Foreign Currency Transactions

Certain of our subsidiaries are based in Canada and use the Canadian dollar as their functional currency. Assets and liabilities of subsidiaries with a Canadian dollar functional currency are translated at period-end rates of exchange, and revenues and expenses are translated at average exchange rates prevailing for each month. The resulting translation adjustments are made directly to a separate component of other comprehensive income in Partners’ Capital reflected on our consolidated balance sheet.

Certain of our subsidiaries also enter into transactions and have monetary assets and liabilities that are denominated in a currency other than the entities’ respective functional currencies. Gains and losses from the revaluation of foreign currency transactions and monetary assets and liabilities are included in the consolidated statements of operations. The revaluation of foreign currency transactions and monetary assets and liabilities resulted in a gain of approximately $2 million for the year ended December 31, 2010, a gain of approximately $13 million for the year ended December 31, 2009 and a loss of approximately $22 million for the year ended December 31, 2008.

Cash and Cash Equivalents

Cash and cash equivalents consist of all unrestricted demand deposits and funds invested in highly liquid instruments with original maturities of three months or less and typically exceed federally insured limits. We periodically assess the financial condition of the institutions where these funds are held and believe that our credit risk is minimal. In accordance with our policy, outstanding checks are classified as accounts payable rather than negative cash. As of December 31, 2010 and 2009, accounts payable included approximately $40 million and $50 million, respectively, of outstanding checks that were reclassified from cash and cash equivalents.

Restricted Cash

Restricted cash at December 31, 2010 consists of $20 million held by an escrow agent in connection with PNG’s acquisition of SG Resources. See Note 3 for further discussion of this acquisition. We had no restricted cash at December 31, 2009.

Accounts Receivable

Our accounts receivable are primarily from purchasers and shippers of crude oil and, to a lesser extent, purchasers of LPG, refined products and natural gas storage. These purchasers include, but are not limited to refineries, producers, marketing and trading companies and financial institutions that are active in the physical and financial commodity markets. The majority of our accounts receivable relate to our crude oil supply and logistics activities that can generally be described as high volume and low margin activities, in many cases involving exchanges of crude oil volumes.

During 2008 and 2009, U.S. and world financial markets and energy prices were extremely volatile and global economies substantially weakened. During 2010, such financial markets and energy prices were not as volatile; however, there continues to be relatively weak economic growth and varied predictions regarding future economic recovery. This financial market volatility and fluctuation in energy prices primarily experienced during 2008 and 2009 coupled with the relatively weak economic recovery that persists has caused liquidity issues impacting many companies, which in turn have increased the potential credit risks associated with certain counterparties with which we do business.

To mitigate such credit risks, we have in place a rigorous credit review process. We closely monitor these conditions in order to make a determination with respect to the amount, if any, of credit to be extended to any given customer and the form and amount of financial performance assurances we require. Such financial assurances are commonly provided to us in the form of standby letters of credit, “parental” guarantees or advance cash payments. At December 31, 2010 and 2009, we had received approximately $197 million and $212 million, respectively, of advance cash payments from third parties to mitigate credit risk. In addition, we enter into netting arrangements (contractual agreements that allow us and the counterparty to offset receivables and payables between the two) that cover a significant part of our transactions and also serve to mitigate credit risk.

We review all outstanding accounts receivable balances on a monthly basis and record a reserve for amounts that we expect will not be fully recovered. We do not apply actual balances against the reserve until we have exhausted substantially all collection efforts. At December 31, 2010 and 2009, substantially all of our accounts receivable (net of allowance for doubtful accounts) were less than 60 days past their scheduled invoice date. Our allowance for doubtful accounts receivable totaled $5 million and $9 million at December 31, 2010 and 2009, respectively. The decrease in our allowance for doubtful

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accounts receivable balance during the year ended December 31, 2010 primarily is due to the collection and related settlement of claims for receivables that had been reserved for during the years ended December 31, 2009 and 2008. Although we consider our allowance for doubtful trade accounts receivable to be adequate, actual amounts could vary significantly from estimated amounts.

Inventory, Linefill, Base Gas and Long-term Inventory

Inventory primarily consists of crude oil, LPG, refined products and natural gas in pipelines, storage facilities and rail cars that are valued at the lower of cost or market, with cost determined using an average cost method within specific inventory pools.

At the end of each reporting period, we assess the carrying value of our inventory and make any adjustments necessary to reduce the carrying value to the applicable net realizable value. During 2010 and 2008, we recorded non-cash charges of approximately $3 million and $168 million, respectively, related to the writedown of such inventory. We recognized no such writedowns during 2009. Linefill, base gas and minimum working inventory requirements in assets we own are recorded at historical cost and consist of crude oil, LPG and natural gas. We classify as linefill those barrels (i) used to pack the pipeline such that when an incremental product is injected into or enters a pipeline it forces product out at another location and (ii) that represent the minimum working requirements in tanks that we own. Base gas requirements of natural gas, as well as the minimum amount of crude oil and refined products, are used to operate our storage and terminalling facilities, similar to linefill in the pipelines. During 2010, 2009 and 2008, we recorded gains of approximately $21 million, $4 million and $3 million, respectively, on the sale of pipeline linefill for proceeds of approximately $72 million, $24 million and $23 million, respectively.

Minimum working inventory requirements in third-party assets and other working inventory in our assets that is needed for our commercial operations are included within specific inventory pools in inventory (a current asset) in determining the average cost of operating inventory. At the end of each period, we reclassify the inventory not expected to be liquidated within the succeeding twelve months out of inventory, at average cost, and into long-term inventory, which is reflected as a separate line item within other assets on the consolidated balance sheet.

Inventory, linefill, base gas and long-term inventory consisted of the following (barrels in thousands, natural gas volumes in millions and total value in millions):

	December 31, 2010						December 31, 2009
	Volumes	Unit of Measure	Total Value		Price/ Unit (1)		Volumes	Unit of Measure	Total Value		Price/ Unit (1)
Inventory
Crude oil	14,132	barrels	$	1,100	$	77.84	12,232	barrels	$	886	$	72.43
LPG	7,395	barrels	366		$	49.49	6,051	barrels	247		$	40.82
Refined products	271	barrels	22		$	81.18	283	barrels	21		$	74.20
Natural gas (2)	13	mcf	—		$	3.87	181	mcf	1		$	3.30
Parts and supplies	N/A		3		N/A		N/A		2		N/A
Inventory subtotal			1,491						1,157

Linefill and base gas
Crude oil	9,159	barrels	478		$	52.19	9,404	barrels	471		$	50.09
Natural gas (2)	11,194	mcf	37		$	3.31	9,194	mcf	28		$	3.04
LPG	77	barrels	4		$	51.95	52	barrels	2		$	38.46
Linefill and base gas subtotal			519						501

Long-term inventory
Crude oil	1,761	barrels	128		$	72.69	1,497	barrels	103		$	68.80
LPG	505	barrels	26		$	51.49	458	barrels	18		$	39.30
Long-term inventory subtotal			154						121

Total			$	2,164					$	1,779

(1) Price per unit represents a weighted average associated with various grades, qualities and locations; accordingly, these prices may not be comparable to published benchmarks for such products.

(2) The volumetric ratio of mcf of natural gas to crude Btu equivalent is 6:1; thus, natural gas volumes can be converted to barrels by dividing by 6.

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Property and Equipment

In accordance with our capitalization policy, costs associated with acquisitions and improvements that expand our existing capacity, including related interest costs, are capitalized. For the years ended December 31, 2010, 2009 and 2008, capitalized interest was $16 million, $15 million and $17 million, respectively. We also capitalize expenditures for the replacement of partially or fully depreciated assets in order to maintain the service capability, level of production and/or functionality of our existing assets. Repair and maintenance expenditures incurred in order to maintain the day to day operation of our existing assets are expensed as incurred.

Property and equipment, net is stated at cost and consisted of the following (in millions):

	Estimated Useful	December 31,
	Lives (Years)	2010			2009
Crude oil pipelines and facilities	30 - 70	$	4,303		$	4,265
Storage and terminal facilities	30 - 70	2,740			2,079
Trucking equipment and other	5 - 15	106			110
Construction in progress	-	304			476
Office property and equipment	2 - 50	95			84
Land and other	N/A	266			226
		7,814			7,240
Accumulated depreciation		(1,123		)	(900		)

Property and equipment, net		$	6,691		$	6,340

Depreciation expense for the years ended December 31, 2010, 2009 and 2008 was $235 million, $216 million and $196 million, respectively.

We calculate our depreciation using the straight-line method, based on estimated useful lives and salvage values of our assets. During 2010, we extended the depreciable lives of several of our crude oil and other storage facilities and pipeline systems based on an ongoing review to assess the useful lives of our property and equipment and to adjust those lives, if appropriate, to reflect current expectations given actual experience and current technology. These depreciable life extensions will prospectively reduce depreciation expense. For the year ended December 31, 2010, these extensions reduced depreciation expense by approximately $23 million. Any historical adjustments to useful lives have not had a material impact on our aggregate depreciation levels from year to year. We also classify gains and losses on sales of assets and asset impairments as a component of depreciation and amortization in the consolidated statements of operations.

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Equity Method of Accounting

Our investments in the following entities are accounted for under the equity method of accounting:

Entity	Type of Operation	Our Ownership Interest
Settoon Towing, LLC	Barge Transportation Services	50	%
White Cliffs Pipeline, LLC	Crude Oil Pipeline	34	%
Frontier Pipeline Company	Crude Oil Pipeline	22	%
Butte Pipe Line Company	Crude Oil Pipeline	22	%

We do not consolidate any part of the assets or liabilities of our equity investees. Our share of net income or loss is reflected as one line item on the income statement and will increase or decrease, as applicable, the carrying value of our investments on the balance sheet. In addition, we include a proportionate share of our equity method investees’ unrealized gains and losses in other comprehensive income on our consolidated balance sheet. We also adjust our investment balances in these investees by the like amount. Distributions to the Partnership will reduce the carrying value of our investments and will be reflected on our cash flow statement netted against equity in earnings. In turn, contributions will increase the carrying value of our investments and will be reflected on our cash flow statement within investing activities.

Noncontrolling Interests

We account for noncontrolling interests in subsidiaries in accordance with FASB guidance specific to noncontrolling interests. FASB guidance requires all entities to report noncontrolling interests in subsidiaries (formerly referred to as minority interest) as a component of equity in the consolidated financial statements. Noncontrolling interest represents the portion of assets and liabilities in a subsidiary that is owned by a third-party. See Note 5 for additional discussion regarding our noncontrolling interests.

Asset Retirement Obligations

FASB guidance establishes accounting requirements for retirement obligations associated with tangible long-lived assets, including estimates related to (i) the time of the liability recognition, (ii) initial measurement of the liability, (iii) allocation of asset retirement cost to expense, (iv) subsequent measurement of the liability and (v) financial statement disclosures. FASB guidance also requires that the cost for asset retirement should be capitalized as part of the cost of the related long-lived asset and subsequently allocated to expense using a systematic and rational method.

Some of our assets, primarily related to our transportation and facilities segments, have contractual or regulatory obligations to perform remediation and, in some instances, dismantlement and removal activities when the assets are abandoned. These obligations include varying levels of activity including disconnecting inactive assets from active assets, cleaning and purging assets, and in some cases, completely removing the assets and returning the land to its original state. These assets have been in existence for many years and with regular maintenance will continue to be in service for many years to come. It is not possible to predict when demand for these transportation or storage services will cease, and we do not believe that such demand will cease for the foreseeable future. Accordingly, we believe the date when these assets will be abandoned is indeterminate. With no reasonably determinable abandonment date, we cannot reasonably estimate the fair value of the associated asset retirement obligations. We will record asset retirement obligations for these assets in the period in which sufficient information becomes available for us to reasonably determine the settlement dates.

A small portion of our contractual or regulatory obligations is related to assets that are inactive or that we plan to take out of service and, although the ultimate timing and costs to settle these obligations are not known with certainty, we have recorded a reasonable estimate of these obligations. We have estimated that the fair value of these obligations was approximately $5 million at both December 31, 2010 and 2009.

Impairment of Long-Lived Assets

Long-lived assets with recorded values that are not expected to be recovered through future cash flows are written down to estimated fair value in accordance with FASB guidance with respect to the accounting for the impairment or disposal of long-lived assets. Under this guidance, a long-lived asset is tested for impairment when events or circumstances indicate that its carrying value may not be recoverable. The carrying value of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. If the

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carrying value exceeds the sum of the undiscounted cash flows, an impairment loss equal to the amount by which the carrying value exceeds the fair value of the asset is recognized.

We periodically evaluate property and equipment for impairment when events or circumstances indicate that the carrying value of these assets may not be recoverable. The evaluation is highly dependent on the underlying assumptions of related cash flows. The subjective assumptions used to determine the existence of an impairment in carrying value include:

· whether there is an indication of impairment;

· the grouping of assets;

· the intention of “holding” versus “selling” an asset;

· the forecast of undiscounted expected future cash flow over the asset’s estimated useful life; and

· if an impairment exists, the fair value of the asset or asset group.

During 2010, we recognized impairments of approximately $13 million for assets taken out of service. Impairments of less than $1 million and approximately $5 million were recognized during 2009 and 2008, respectively, and were predominantly related to assets that were taken out of service. These assets did not support spending the capital necessary to continue service, and we utilized other assets to handle these activities.

Goodwill

In accordance with FASB guidance, we test goodwill at least annually (as of June 30) and on an interim basis if a triggering event occurs, such as an adverse change in business climate, to determine whether an impairment has occurred. Goodwill is tested for impairment at a level of reporting referred to as a reporting unit. A reporting unit is an operating segment or one level below an operating segment for which discrete financial information is available and regularly reviewed by segment management. Our reporting units are our operating segments. FASB guidance requires a two step approach to testing goodwill for impairment. In Step 1, we compare the fair value of the reporting unit with the respective book values, including goodwill, by using an income approach based on a discounted cash flow analysis. This approach requires us to make long-term forecasts of future revenues, expenses and other expenditures. Those forecasts require the use of various assumptions and estimates, the most significant of which are net revenues (total revenues less purchases and related costs), operating expenses, general and administrative expenses and the weighted average cost of capital. Fair value of the reporting units is determined using significant unobservable inputs, or level 3 inputs in the fair value hierarchy. When the fair value is greater than book value, then the reporting unit’s goodwill is not considered impaired. If the book value is greater than fair value, then we proceed to Step 2. In Step 2, we compare the implied fair value of the reporting unit’s goodwill with the book value. A goodwill impairment loss is recognized if the carrying amount exceeds its fair value.

In addition, there is a potential indicator of impairment if a company’s market capitalization is less than its book equity. Periodically, we compare our market capitalization to our book equity to determine if there is an indicator of potential impairment. Throughout 2010, our market capitalization exceeded the book value of our equity and thus, this indicated that there was no triggering event. There were no other triggering events or indicators of potential impairment of our goodwill during 2010.

Through Step 1 of our annual testing of goodwill for potential impairment, which also includes a sensitivity analysis regarding the excess of our reporting unit’s fair value over book value, we determined that the fair value of each reporting unit was substantially greater than its respective book value, and therefore goodwill was not considered impaired. We will continue to monitor various potential indicators (including the financial markets) to determine if a triggering event occurs and will perform another goodwill impairment analysis if necessary. We have not recognized any impairment of goodwill during the last three years.

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The table below reflects our changes in goodwill (in millions):

	Transportation			Facilities		Supply & Logistics		Total (1)

Balance at December 31, 2008	$	562		$	283	$	365	$	1,210

2009 Goodwill Related Activity :
PNGS acquisition	—			25		—		25
Other acquisitions	24			—		—		24
Purchase price accounting adjustments (2)	(3		)	—		—		(3		)
Foreign currency translation adjustments	25			—		6		31

Balance at December 31, 2009	$	608		$	308	$	371	$	1,287

2010 Goodwill Related Activity:
Nexen acquisition	18			—		54		72
Purchase price accounting adjustments (2)	3			—		—		3
Foreign currency translation adjustments	11			—		3		14

Balance at December 31, 2010	$	640		$	308	$	428	$	1,376

(1) As of December 31, 2010, we do not have any accumulated impairment losses.

(2) Goodwill is recorded at the acquisition date based on a preliminary purchase price allocation. This preliminary goodwill balance may be adjusted when the purchase price allocation is finalized. See Note 3 for additional discussion of our acquisitions.

Other Assets, Net

Other assets, net of accumulated amortization consist of the following (in millions):

	December 31,
	2010			2009
Debt issue costs	$	47		$	42
Fair value of derivative instruments	20			77
Intangible assets	311			239
Other	58			65
	436			423
Accumulated amortization	(54		)	(54		)
	$	382		$	369

Costs incurred in connection with the issuance of long-term debt and amendments to our credit facilities are capitalized and amortized using the straight-line method over the term of the related debt. Use of the straight-line method does not differ materially from the “effective interest” method of amortization. Fully amortized debt issue costs and the related accumulated amortization are written off in conjunction with the refinancing or termination of the applicable debt arrangement. We capitalized debt issue costs of approximately $7 million and $12 million in 2010 and 2009, respectively.

Amortization expense related to other assets (including finite-lived intangible assets) for the three years ended December 31, 2010, 2009 and 2008 was $22 million, $19 million and $21 million, respectively. Our amortization expense for finite-lived intangible assets for the years ended December 31, 2010, 2009 and 2008 was $14 million, $14 million and $15 million, respectively.

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Intangible assets that have finite lives are tested for impairment when events or circumstances indicate that the carrying value may not be recoverable. Our intangible assets that have finite lives consist of the following (in millions):

		December 31, 2010							December 31, 2009
	Estimated Useful			Accumulated							Accumulated
	Lives (Years)	Cost		Amortization			Net		Cost		Amortization			Net
Customer contracts and relationships	1-30	$	243	$	(35	)	$	208	$	171	$	(36	)	$	135
Emission reduction credits (1)	N/A	45		—			45		45		—			45
Property tax abatement	13	23		(2		)	21		23		(1		)	22
		$	311	$	(37	)	$	274	$	239	$	(37	)	$	202

(1) Emission reduction credits are finite lived and are subject to amortization from the date that they are first utilized. At December 31, 2010, none of our emission reduction credits were being utilized because the projects for which they were acquired are not in service.

We estimate that our amortization expense related to finite-lived intangible assets for the next five years will be as follows (in millions):

2011	$	20
2012	$	19
2013	$	17
2014	$	17
2015	$	16

Environmental Matters

We record environmental liabilities when environmental assessments and/or remedial efforts are probable and we can reasonably estimate the costs. Generally, our recording of these accruals coincides with our completion of a feasibility study or our commitment to a formal plan of action. We do not discount our environmental remediation liabilities to present value. We also record receivables for amounts recoverable from insurance or from third parties under indemnification agreements in the period that we determine the costs are probable of recovery.

We expense expenditures that relate to an existing condition caused by past operations that do not contribute to current or future profitability. We record environmental liabilities assumed in business combinations based on the estimated fair value of the environmental obligations caused by past operations of the acquired company. See Note 12 for further discussion of environmental remediation matters.

Income and Other Taxes

We estimate (i) income taxes in the jurisdictions in which we operate, (ii) net deferred tax assets and liabilities based on temporary differences that are expected to be recovered or settled at the enacted tax rates expected in future periods, (iii) valuation allowances for deferred tax assets and (iv) contingent tax liabilities for estimated exposures related to our current tax positions.

We adopted the provisions of the FASB guidance related to accounting for uncertainty in income taxes on January 1, 2007. Pursuant to this guidance, we must recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities, based on the technical merits of the tax position and also the past administrative practices and precedents of the taxing authority. As of December 31, 2010 and 2009, we have not recognized any material amounts in connection with uncertainty in income taxes.

See Note 7 for discussion of U.S. federal and state taxes and Canadian federal and provincial taxes.

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Derivative Instruments and Hedging Activities

We record all open derivative instruments on the balance sheet as either assets or liabilities measured at their fair value per the guidance issued by the FASB. This guidance requires that changes in the fair value of derivative instruments be recognized currently in earnings unless specific hedge accounting criteria are met. For cash flow hedges, the effective portion of the change in fair value is deferred in AOCI and reclassified into earnings when the underlying transaction affects earnings. For fair value hedges, the change in fair value of the derivative instrument is recognized in earnings. Additionally, the change in fair value of the hedged item, attributable to the hedged risk, is recognized as a basis adjustment to the hedged item and is also offset in earnings. See Note 6 for further discussion.

Equity Compensation

See Note 10 for information regarding our accounting for equity compensation awards.

Net Income Per Limited Partner Unit

Basic and diluted net income per unit is determined by dividing our limited partners’ interest in net income by the weighted average number of limited partner units outstanding during the period. Pursuant to guidance issued by the FASB on the application of the two-class method for MLPs, the limited partners’ interest in net income attributable to Plains is calculated by first reducing net income by the distribution pertaining to the current period’s net income, which is to be paid in the subsequent quarter (including the incentive distribution interest in excess of the 2% general partner interest). Then, the remaining undistributed earnings or excess distributions over earnings, if any, are allocated to the general partner and limited partners in accordance with the contractual terms of the partnership agreement. The adoption of this guidance resulted in a change to our calculation of earnings per unit by using distributions applicable to the period rather than distributions paid in the period (applicable to the previous period). Also, in accordance with this guidance, earnings per unit for prior periods were recast to conform to this revised calculation.

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The following table sets forth the computation of basic and diluted earnings per limited partner unit for the years ended 2010, 2009 and 2008:

	Year Ended December 31,
	2010			2009			2008
Numerator for basic and diluted earnings per limited partner unit:
Net income attributable to Plains	$	505		$	579		$	437
Less: General partner’s incentive distribution paid (1)	(160		)	(127		)	(106		)
Subtotal	345			452			331
Less: General partner 2% ownership (1)	(7		)	(9		)	(6		)
Net income available to limited partners	338			443			325
Adjustment in accordance with application of the two-class method for MLPs (1)	(8		)	(9		)	(5		)
Net income available to limited partners in accordance with the application of the two-class method for MLPs	$	330		$	434		$	320

Denominator:
Basic weighted average number of limited partner units outstanding	137			130			120
Effect of dilutive securities:
Weighted average LTIP units (2)	1			1			1
Diluted weighted average number of limited partner units outstanding	138			131			121

Basic net income per limited partner unit	$	2.41		$	3.34		$	2.66

Diluted net income per limited partner unit	$	2.40		$	3.32		$	2.64

(1) We calculate net income available to limited partners based on the distribution paid during the current quarter (including the incentive distribution interest in excess of the 2% general partner interest). However, FASB guidance requires that the distribution pertaining to the current period’s net income, which is to be paid in the subsequent quarter, be utilized in the earnings per unit calculation. After adjusting for this distribution, the remaining undistributed earnings or excess distributions over earnings, if any, are allocated to the general partner and limited partners in accordance with the contractual terms of the partnership agreement for earnings per unit calculation purposes. We reflect the impact of the difference in (i) the distribution utilized and (ii) the calculation of the excess 2% general partner interest as the “Adjustment in accordance with application of the two-class method for MLPs.”

(2) Our LTIP awards (described in Note 10) that contemplate the issuance of common units are considered dilutive unless (i) vesting occurs only upon the satisfaction of a performance condition and (ii) that performance condition has yet to be satisfied. LTIP awards that are deemed to be dilutive are reduced by a hypothetical unit repurchase based on the remaining unamortized fair value, as prescribed by the treasury stock method in guidance issued by the FASB.

Recent Accounting Pronouncements

In December 2010, the FASB issued updated accounting guidance related to the calculation of the carrying amount of a reporting unit when performing the first step of a goodwill impairment test. More specifically, this update will require an entity to use an equity premise when performing the first step of a goodwill impairment test, and if a reporting unit has a zero or negative carrying amount, the entity must assess and consider qualitative factors to determine whether it is more likely than not that a goodwill impairment exists. The new accounting guidance is effective for public entities, for impairment tests performed during entities’ fiscal years (and interim periods within those years) that begin after December 15, 2010. Early application is not permitted. We will adopt the new guidance in the first quarter of 2011; however, as we currently do not have any reporting units with a zero or negative carrying amount, we do not expect the adoption of this guidance to have an impact on our financial position, results of operations or cash flows.

In December 2010, the FASB issued updated accounting guidance to clarify that pro forma disclosures should be presented as if a business combination that is determined to be material on an individual or aggregate basis occurred at the beginning of the prior annual period for purposes of preparing both the current reporting period and the prior reporting period pro forma financial information. These disclosures should be accompanied by a narrative description about the nature and amount of material, nonrecurring pro forma adjustments. The new accounting guidance is effective for business combinations consummated in periods beginning after December 15, 2010 and should be applied prospectively as of the date of adoption. Early adoption is permitted. We will adopt the new disclosures in the first quarter of 2011. We do not believe that the adoption of this guidance will have a material impact to our financial position, results of operations or cash flows.

In January 2010, the FASB issued guidance to enhance disclosures related to the existing fair value hierarchy disclosure requirements. A fair value measurement is designated as level 1, 2 or 3 within the hierarchy based on the nature of the inputs used in the valuation process. Level 1 measurements generally reflect quoted market prices in active markets for identical assets or liabilities, level 2 measurements generally reflect the use of significant observable inputs and level 3 measurements typically utilize significant unobservable inputs. This new guidance requires additional disclosures regarding transfers into and out of level 1 and level 2 measurements and requires a gross presentation of activities within the level 3 roll forward. This guidance was effective for the first interim or annual reporting period beginning after December 15, 2009, except for the gross presentation of the level 3 roll forward, which is required for annual reporting periods beginning after December 15, 2010 and for interim reporting periods within those years. We adopted the guidance relating to level 1 and level 2 transfers as of January 1, 2010, and we adopted the guidance relating to level 3 measurements on January 1, 2011. Our adoption did not have any material impact on our financial position, results of operations or cash flows.

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In June 2009, the FASB issued guidance that requires an enterprise to perform an analysis to determine whether the enterprise’s variable interest(s) provide a controlling financial interest in a VIE. This analysis identifies the primary beneficiary of a VIE as the enterprise that has (i) the power to direct the activities of a VIE that most significantly impact the entity’s economic performance and (ii) the obligation to absorb losses of the entity, or the right to receive benefits from the entity, that could potentially be significant to the VIE. This guidance also (i) requires such assessments to be ongoing, (ii) amends certain guidance for determining whether an entity is a VIE and (iii) enhances disclosures that will provide users of financial statements with more transparent information regarding an enterprise’s involvement in a VIE. We adopted this guidance as of January 1, 2010. Our adoption did not have any material impact on our financial position, results of operations or cash flows.

In June 2009, the FASB issued guidance to establish the source of authoritative GAAP to be applied by nongovernmental entities in the preparation of financial statements. As this guidance is meant to establish the source of authoritative GAAP and to better organize current accounting guidance, it only affects the referencing to applicable guidance throughout the accompanying consolidated financial statements and the notes thereto. This guidance was effective for interim or annual periods ending after September 15, 2009; therefore, we adopted this guidance as of July 1, 2009. Our adoption did not have any material impact on our financial position, results of operations or cash flows.

In May 2009, the FASB issued guidance that establishes general standards of accounting for and disclosure of subsequent events or events that occur after the balance sheet date but before financial statements are issued. This guidance sets forth (i) the period after the balance sheet date during which management shall evaluate events or transactions that may occur for potential recognition or disclosure in the financial statements, (ii) the circumstances under which an entity shall recognize events or transactions occurring after the balance sheet date in its financial statements and (iii) the disclosures that an entity shall make about events or transactions that occurred after the balance sheet date. This guidance was effective for interim or annual periods ending after June 15, 2009; therefore, we adopted this guidance as of April 1, 2009. Adoption did not have any material impact on our financial position, results of operations or cash flows.

In April 2009, the FASB issued guidance that increases the frequency of fair value disclosures from annual to quarterly in an effort to provide financial statement users with more timely and transparent information about the effects of current market conditions on financial instruments. This is intended to address concerns raised by some financial statement users about the lack of comparability resulting from the use of different measurement attributes for financial instruments. These disclosures are also intended to stimulate more robust discussions about financial instrument valuations between users and reporting entities. We adopted this guidance as of April 1, 2009. Adoption did not have any material impact on our financial position, results of operations or cash flows.

In November 2008, the FASB issued guidance that addresses certain accounting considerations, including initial measurement, decreases in investment value, and changes in the level of ownership or degree of influence related to equity method investments. We adopted this guidance as of January 1, 2009. Adoption did not have any material impact on our financial position, results of operations or cash flows.

In April 2008, the FASB issued guidance that amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under previous guidance over goodwill and other intangible assets. The intent of this guidance is to improve the consistency between the useful life of a recognized intangible asset and the period of expected cash flows used to measure the fair value of the asset under GAAP. We adopted this guidance as of January 1, 2009. Adoption did not have any material impact on our financial position, results of operations or cash flows.

In March 2008, the FASB issued guidance that amends previous guidance with respect to disclosures of derivative instruments and hedging activities. This guidance requires enhanced disclosures about (i) how and why an entity uses derivative instruments, (ii) how derivative instruments and related hedged items are accounted for under the guidance and its related interpretations and (iii) how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. The provisions of this guidance were effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. We adopted this guidance as of January 1, 2009. Adoption did not have any material impact on our financial position, results of operations or cash flows. See Note 6 for enhanced disclosure of derivative instruments and hedging activities.

In March 2008, the FASB issued guidance that addresses the application of the two-class method in determining income per unit for MLPs having multiple classes of securities that may participate in partnership distributions. The two-class method is an earnings allocation formula that determines earnings per unit for each class of common units and participating securities according to participation rights in undistributed earnings. We adopted this guidance as of January 1, 2009. This guidance has been applied retrospectively for all financial statement periods presented. Adoption impacted the net income available to limited partners used in our computation of earnings per unit, but did not impact our net income, distributions to limited partners, financial position, results of operations or cash flows.

Note 3—Acquisitions and Dispositions

The following acquisitions were accounted for using the purchase method of accounting and the purchase price was allocated in accordance with such method.

Acquisitions Closed Subsequent to December 31, 2010

In February 2011, PNG completed the acquisition of SG Resources from SGR Holdings, L.L.C. (“Southern Pines Acquisition”) for consideration of approximately $746 million, subject to certain post closing adjustments. The primary asset of SG Resources is the Southern Pines Energy Center (“Southern Pines”), a FERC-regulated, salt-cavern natural gas storage facility located at Greene County, Mississippi. Southern Pines is permitted for 40 Bcf of working gas capacity from four storage caverns. This acquisition will be reflected within our facilities segment.

In connection with the transaction, PNG completed a private placement of PNG common units to third-party purchasers and we purchased additional common units. See Note 5 for further discussion.

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2010 Acquisitions

Nexen Acquisition. On December 30, 2010, we acquired from Nexen Holdings U.S.A. Inc. entities that hold crude oil gathering and transportation assets that primarily service Bakken area producers. The purchase price was approximately $229 million, in cash, including approximately $170 million for the business and physical assets and approximately $59 million for approximately 460,000 barrels of inventory and other working capital adjustments. The assets are primarily located in Northwestern North Dakota and Northeastern Montana and include (i) a lease gathering business that currently handles approximately 55,000 barrels per day, (ii) the Robinson Lake pipeline, a FERC-regulated 20-mile, 8-inch pipeline that currently handles approximately 30,000 barrels per day, (iii) eight truck terminals and (iv) various other contractual rights. These assets are included within our transportation and supply and logistics segments. We recognized goodwill of approximately $72 million associated with this acquisition; however, such purchase price amounts are preliminary and may change as a result of our final valuation.

Other 2010 Acquisitions. During 2010, we completed five additional acquisitions for aggregate consideration of approximately $178 million. These acquisitions included (i) a 34% interest in White Cliffs that is reflected within our transportation segment, (ii) an additional 11% interest in Capline pipeline that is reflected within our transportation segment and (iii) various other assets reflected within both our transportation and facilities segments. We did not recognize any goodwill for these acquisitions.

2009 Acquisitions

PNGS Acquisition. On September 3, 2009, we acquired the remaining 50% indirect interest in PAA/Vulcan for an aggregate purchase price of $215 million (“PNGS Acquisition”). The $215 million purchase price consisted of $90 million in cash paid at closing, approximately $91 million in equivalent value of PAA common units (1,907,305 PAA common units based on a 20 business-day average closing price per unit) issued to Vulcan Gas Storage LLC at closing, and up to $40 million of deferred/contingent cash consideration. The deferred/contingent consideration is payable in cash in two installments of $20 million each upon the achievement of certain performance milestones and events expected to occur over the next several years. Upon completion of the PNG IPO in May 2010, we paid the first $20 million installment. See Note 5 for additional discussion of the PNG IPO. The fair value of the remaining contingent consideration is approximately $17 million at December 31, 2010.

As a result of the transaction, we owned 100% of PNGS’s natural gas storage business and related operating entities, which were accounted for on a consolidated basis beginning in September 2009. We historically accounted for our 50% indirect interest in PAA/Vulcan under the equity method. We recorded a net gain of approximately $9 million, recorded in other income, in connection with (i) adjusting our previously owned 50% investment in PAA/Vulcan to fair value and (ii) terminating an agreement to supply natural gas to PNGS.

At the time of the PNGS Acquisition, PNGS owned and operated two natural gas storage facilities located in Louisiana and Michigan that had an aggregate working gas storage capacity of 40 Bcf and an aggregate peak injection and withdrawal capacity of 1.7 Bcf per day and 3.2 Bcf per day, respectively. Substantially all of PNGS’s revenues were derived from the provision of firm storage services under multi-year, fee-based contracts. The gas storage operations are reflected in our facilities segment.

The purchase price consisted of the following (in millions):

Cash	$	90
PAA equity	91
Paid at closing	181
Fair value of contingent consideration (1)	34
Total purchase price	$	215

(1) The deferred contingent cash consideration is payable in cash in two installments of $20 million each upon the achievement of certain performance milestones and events expected to occur over the next several years. The fair value of the deferred contingent cash consideration was based on a discounted cash flow model utilizing a discount rate of approximately 9%. Upon completion of the PNG IPO in May 2010, we paid the first $20 million contingent consideration installment.

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The allocation of fair value to the assets and liabilities related to the PNGS Acquisition was as follows (in millions):

Property, plant and equipment	$	791
Base gas	28
Goodwill	25
Intangible assets	23
Working capital and other long-term assets and liabilities	9
Debt	(446		)
Total	$	430

Other 2009 Acquisitions. During 2009, we completed six additional acquisitions for an aggregate consideration of approximately $178 million. These acquisitions included an additional 21% undivided joint interest in Capline and associated tankage, as well as various crude oil pipelines and pipeline systems that are all included within our transportation segment. We also acquired a natural gas processing business, a refined products terminal and various crude oil storage tanks and other related assets that are all included within our facilities segment. The goodwill associated with such acquisitions was approximately $27 million as of December 31, 2010.

2008 Acquisitions

Rainbow. In May 2008, we completed the acquisition of Rainbow for approximately $687 million (CAD to USD foreign exchange rate at the date of closing was $0.993:1). The assets acquired include approximately (i) 480 miles of mainline crude oil pipelines, (ii) 119 miles of gathering pipelines, (iii) 570,000 barrels of tankage along the system and (iv) 1 million barrels of crude oil linefill. The system has a throughput capacity of approximately 200,000 barrels per day. The acquired operations are reflected primarily in our transportation segment. The goodwill associated with this acquisition was approximately $191 million. In anticipation of closing the Rainbow acquisition, we entered into forward currency exchange contracts, which exchanged CAD and USD, to hedge the foreign currency exchange risk inherent in the acquisition price. Additionally, we entered into a financial option strategy, whereby we established a minimum and maximum per barrel price to hedge the commodity price risk associated with the anticipated purchase of crude oil linefill. We recognized a gain on those positions of approximately $8 million and $3 million, respectively, which is reflected in our 2008 consolidated results of operations in the “Other income/(expense), net” line.

The purchase price consisted of the following (in millions):

Cash payment to sellers	$	659
Assumption of Rainbow debt (at estimated fair value)	26
Estimated transaction costs	2

Total purchase price	$	687

The purchase price allocation was as follows (in millions):

Property, plant and equipment	$	425
Pipeline linefill in owned assets	143
Intangible assets	52
Goodwill	191
Future income tax liability	(110		)
Assumption of working capital and other long-term assets and liabilities, including cash (1)	(14		)

Total	$	687

(1) Includes approximately $16 million associated with environmental liabilities.

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During 2008, we completed one additional acquisition for aggregate consideration of approximately $44 million. This acquisition is reflected in our facilities segment and included the purchase of a storage facility and other assets. There was no goodwill associated with this acquisition.

Dispositions

During 2010, 2009 and 2008, we sold various property and equipment for proceeds totaling approximately $3 million, $4 million and $12 million, respectively. A gain of less than $1 million, a loss of less than $1 million and a gain of approximately $6 million were recognized in 2010, 2009 and 2008, respectively, related to these sales.

Note 4—Debt

Debt consisted of the following (in millions):

	December 31,			December 31,
	2010			2009
SHORT-TERM DEBT
Credit Facilities:
Senior secured hedged inventory facility bearing interest at a rate of 2.1% and 2.5% at December 31, 2010 and 2009, respectively	$	500		$	300
PAA senior unsecured revolving credit facility, bearing interest at a rate of 0.7% and 0.8% at December 31, 2010 and 2009, respectively (1)	824			772
Other	2			2
Total short-term debt	1,326			1,074

LONG-TERM DEBT
Senior Notes:
4.25% senior notes due September 2012	500			500
7.75% senior notes due October 2012	200			200
5.63% senior notes due December 2013	250			250
5.25% senior notes due June 2015	150			150
3.95% senior notes due September 2015	400			—
6.25% senior notes due September 2015	—			175
5.88% senior notes due August 2016	175			175
6.13% senior notes due January 2017	400			400
6.50% senior notes due May 2018	600			600
8.75% senior notes due May 2019	350			350
5.75% senior notes due January 2020	500			500
6.70% senior notes due May 2036	250			250
6.65% senior notes due January 2037	600			600
Unamortized discounts	(12		)	(14		)
Senior notes, net of unamortized discounts	4,363			4,136
Credit Facilities and Other:
PNG senior unsecured revolving credit facility, bearing interest at a rate of 3.2% at December 31, 2010	260			—
Other	8			6
Total long-term debt (1) (2)	4,631			4,142
Total debt	$	5,957		$	5,216

(1) We classify as short-term our borrowings under our PAA senior unsecured revolving credit facility. These borrowings are designated as working capital borrowings, must be repaid within one year and are primarily for hedged LPG and crude oil inventory and NYMEX and ICE margin deposits.

(2) Our fixed-rate senior notes have a face value of approximately $4.4 billion as of December 31, 2010. We estimate the aggregate fair value of these notes to be approximately $4.7 billion and $4.4 billion at December 31, 2010 and 2009, respectively. Our fixed-rate senior notes are traded among institutions, which trades are routinely published by a reporting service. Our determination of fair value is based on reported trading activity near year end.

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Credit Facilities

PAA Senior Secured Hedged Inventory Facility. In October 2010, we renewed our 364-day committed hedged inventory credit facility, which matures in October 2011. The facility has a borrowing capacity of $500 million, which may be increased to $1.2 billion, subject to obtaining additional lender commitments. Borrowings under this facility will be used to finance (i) the purchase of hedged crude oil inventory for storage activities and (ii) foreign import activities. At December 31, 2010, borrowings of approximately $500 million were outstanding under this facility. At December 31, 2009, borrowings of approximately $300 million were outstanding under our previous committed hedged inventory facility.

PAA Senior Unsecured Revolving Credit Facility. As of both December 31, 2010 and 2009, the aggregate borrowing capacity of our senior unsecured revolving credit facility was $1.6 billion (including the respective sub-facility for Canadian borrowings of $400 million and $600 million). This credit facility has a maximum debt-to-EBITDA coverage ratio of 4.75 to 1.00 (5.50 to 1.00 during an acquisition period) and a maturity date of July 2012. Also, the senior unsecured revolving credit facility can be expanded to $2.0 billion, subject to additional lender commitments. At December 31, 2010 and 2009, amounts outstanding under this facility and together with committed letters of credit were $899 million and $848 million, respectively.

This credit facility restricts, among other things, PNG’s ability to make distributions of available cash to unitholders if any default or event of default, as defined in the credit agreement, exists or would result therefrom. In addition, the credit facility contains restrictive covenants, including those that restrict PNG’s ability to incur additional indebtedness, engage in certain transactions with affiliates, grant (or permit to exist) liens or enter into certain restricted contracts, make any material change to the nature of PNG’s business, make a disposition of all or substantially all of PNG’s assets or enter into a merger, consolidate, liquidate, wind up or dissolve. Also, the credit facility contains certain financial covenants which, among other things, requires PNG to maintain a debt-to-EBITDA coverage ratio that will not be greater than 4.75 to 1.00 on outstanding debt (5.50 to 1.00 on all outstanding debt during an acquisition period) and also requires that PNG maintain an EBITDA-to-interest coverage ratio that will not be less than 3.00 to 1.00, as such terms are defined in the credit agreement.

PAA 364-Day Credit Agreement. In January 2011, we entered into a 364-day senior unsecured credit facility with an aggregate borrowing capacity of $500 million. This credit facility has a maximum debt-to-EBITDA coverage ratio of 4.75 to 1.00 (5.50 to 1.00 during an acquisition period) and matures in January 2012. Borrowings under this facility may be used for any partnership purpose, including financing the Southern Pines Acquisition. See Note 3 for discussion regarding this acquisition.

Senior Note Issuances

In January 2011, we completed the issuance of $600 million of 5.00% senior notes due February 1, 2021. The senior notes were sold at 99.521% of face value. Interest payments are due on February 1 and August 1 of each year, beginning on August 1, 2011. We used the net proceeds from this offering to reduce outstanding borrowings under our credit facilities and for general partnership purposes. Amounts repaid under our credit facilities may be reborrowed, as necessary, to fund our ongoing expansion capital program, future acquisitions, retirement of other long-term debt, investments in PNG, including for purposes of financing the Southern Pines Acquisition, or for general partnership purposes.

In July 2010, we completed the issuance of $400 million of 3.95% senior notes due September 15, 2015. The senior notes were sold at 99.889% of face value. Interest payments are due on March 15 and September 15 of each year, which began on September 15, 2010. We used the net proceeds from this offering to repay outstanding indebtedness under our credit facilities.

In September 2009, we completed the issuance of $500 million of 5.75% senior notes due January 15, 2020. The senior notes were sold at 99.523% of face value. Interest payments are due on January 15 and July 15 of each year, which began on January 15, 2010. We used the net proceeds from this offering to repay outstanding borrowings under our credit facilities, a portion of which was used to fund the cash requirements of the PNGS Acquisition (which included repayment of all of PNGS’s debt). See Note 3 for further discussion of the PNGS Acquisition.

In July 2009, we completed the issuance of $500 million of 4.25% senior notes due September 1, 2012. The senior notes were sold at 99.802% of face value. Interest payments are due on March 1 and September 1 of each year, which began on March 1, 2010. We use the net proceeds from this offering to supplement the capital available from our existing senior secured hedged inventory facility to fund working capital needs associated with base levels of routine foreign crude oil import and for seasonal LPG inventory requirements. As of December 31, 2010 and 2009, approximately $466 million and $222 million, respectively, had been used to fund hedged inventory and would be reclassified as short-term debt if funded on our credit facilities. Concurrent with the issuance of these senior notes, we entered into interest rate swaps whereby we

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receive fixed payments at 4.25% and pay three-month LIBOR plus a spread on a notional principal amount of $150 million maturing in two years and an additional $150 million notional principal amount maturing in three years.

In April 2009, we completed the issuance of $350 million of 8.75% senior notes due May 1, 2019. The senior notes were sold at 99.994% of face value. Interest payments are due on May 1 and November 1 of each year, which began on November 1, 2009. We used the net proceeds from this offering to reduce outstanding borrowings under our credit facilities.

In each instance, the notes were co-issued by Plains All American Pipeline, L.P. and a 100% owned consolidated finance subsidiary (neither of which have independent assets or operations) and are fully and unconditionally guaranteed, jointly and severally, by certain of our subsidiaries. See Note 13 for information regarding our guarantor and non-guarantor subsidiaries.

Senior Note Repayments and Redemptions

On February 7, 2011, our $200 million 7.75% senior notes due 2012 were redeemed in full. In conjunction with the early redemption, we recognized a loss of approximately $23 million in the first quarter of 2011. We utilized cash on hand and available capacity under our credit facilities to redeem these notes.

On September 15, 2010, our $175 million, 6.25% senior notes due 2015 were redeemed in full. In conjunction with the early redemption, we recognized a loss of approximately $6 million. We utilized cash on hand and available capacity under our credit facilities to redeem these notes.

On August 15, 2009, we repaid our $175 million 4.75% senior notes that matured on that date. Additionally, on October 5, 2009, we redeemed all of our outstanding $250 million 7.13% senior notes due 2014. In conjunction with the early redemption, we recognized a loss of approximately $4 million.

Maturities

The weighted average life of our long-term debt outstanding at December 31, 2010 was approximately 9 years and the aggregate maturities for the next five years and thereafter are as follows (in millions):

Calendar Year	Payment
2011	$	—
2012 (1)	700
2013	510
2014	—
2015	550
Thereafter	2,875
Total (2)	$	4,635

(1) During February 2011, we redeemed our $200 million 7.75% senior notes due 2012.

(2) Excludes aggregate unamortized net discount of $12 million, a basis adjustment of $4 million related to fair value hedge accounting requirements and other long-term obligations of $4 million.

Covenants and Compliance

Our credit agreements and the indentures governing the senior notes contain cross-default provisions. 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.

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Our PAA senior unsecured revolving credit facility treats a change of control as an event of default and also requires us to maintain a debt-to-EBITDA coverage ratio that will not be greater than 4.75 to 1.00 on outstanding debt, and 5.50 to 1.00 on all outstanding debt during an acquisition period (generally, the period consisting of three fiscal quarters following an acquisition greater than $50 million).

For covenant compliance purposes, letters of credit and borrowings to fund hedged inventory and margin requirements are excluded when calculating the debt coverage ratio.

A default under our credit facilities would permit the lenders to accelerate the maturity of the outstanding debt. As long as we are in compliance with our credit agreements, our ability to make distributions of available cash is not restricted. As of December 31, 2010, we were in compliance with the covenants contained in our credit agreements and indentures.

Letters of Credit

In connection with our crude oil supply and logistics activities, we provide certain suppliers with irrevocable standby letters of credit to secure our obligation for the purchase of crude oil. These letters of credit are issued under our PAA senior unsecured revolving credit facility, and our liabilities with respect to these purchase obligations are recorded in accounts payable on our balance sheet in the month the crude oil is purchased. Generally, these letters of credit are issued for periods of up to seventy days and are terminated upon completion of each transaction. At December 31, 2010 and 2009, we had outstanding letters of credit of approximately $75 million and $76 million, respectively.

Note 5—Partners’ Capital and Distributions

Units Outstanding

Partners’ capital at December 31, 2010 consists of 141,199,175 common units outstanding, representing a 98% effective aggregate ownership interest in the Partnership and its subsidiaries after giving effect to the 2% general partner interest.

Distributions

We distribute 100% of our available cash within 45 days after the end of each quarter to unitholders of record and to our general partner. Available cash is generally defined as all of our cash and cash equivalents on hand at the end of each quarter, less reserves established by our general partner for future requirements.

General Partner Incentive Distributions

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, the general partner is typically entitled, without duplication, to 15% of amounts we distribute in excess of $0.450 per unit, referred to as our MQD, 25% of the amounts we distribute in excess of $0.495 per unit and 50% of amounts we distribute in excess of $0.675 per unit (referred to as “incentive distributions”).

Per unit cash distributions on our outstanding units and the portion of the distributions representing an excess over the MQD were as follows:

	Year
	2010				2009				2008
			Excess				Excess				Excess
	Distribution (1)		over MQD		Distribution (1)		over MQD		Distribution (1)		over MQD
First Quarter	$	0.9275	$	0.4775	$	0.8925	$	0.4425	$	0.8500	$	0.4000
Second Quarter	$	0.9350	$	0.4850	$	0.9050	$	0.4550	$	0.8650	$	0.4150
Third Quarter	$	0.9425	$	0.4925	$	0.9050	$	0.4550	$	0.8875	$	0.4375
Fourth Quarter	$	0.9500	$	0.5000	$	0.9200	$	0.4700	$	0.8925	$	0.4425

(1) Distributions represent those declared and paid in the applicable period.

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November 2006, the Rainbow acquisition in May 2008 and the PNGS Acquisition in September 2009, our general partner agreed to reduce the amounts due to it as incentive distributions. The total reduction in incentive distributions related to the Pacific, Rainbow and PNGS acquisitions is $83 million as displayed on an annual basis in the following table (in millions):

Acquisition	2007		2008		2009		2010		2011		Total
Pacific	$	20	$	15	$	15	$	10	$	5	$	65
Rainbow	—		3		6		1		—		10
PNGS	—		—		1		5		2		8
Total	$	20	$	18	$	22	$	16	$	7	$	83

Following the distribution in February 2011 (as discussed below), the aggregate remaining incentive distribution reductions are approximately $5 million.

Total cash distributions made were as follows (in millions, except per unit amounts):

	Distributions Paid								Distributions per
	Common		General Partner						limited partner
Year	Units		Incentive		2%		Total		unit
2010	$	512	$	160	$	10	$	682	$	3.76
2009	$	468	$	127	$	10	$	605	$	3.62
2008	$	418	$	106	$	8	$	532	$	3.50

On January 12, 2011, we declared a cash distribution of $0.9575 per unit on our outstanding common units. The distribution was paid on February 14, 2011 to unitholders of record on February 4, 2011, for the period October 1, 2010 through December 31, 2010. The total distribution paid was approximately $184 million, with approximately $135 million paid to our common unitholders and $3 million and $46 million paid to our general partner for its general partner and incentive distribution interests, respectively.

Noncontrolling Interests in a Subsidiary

As of December 31, 2010, the noncontrolling interests consisted of the following: (i) the approximate 23% limited partner interest in PNG and (ii) the 25% interest in SLC Pipeline.

PNG Initial Public Offering

On May 5, 2010, PNG completed its IPO of 13,478,000 common units representing limited partner interests at $21.50 per common unit. The number of units issued at closing included 1,758,000 common units issued pursuant to the full exercise of the underwriters’ over-allotment option. Net proceeds received by PNG from the sale of the 13,478,000 common units were approximately $268 million and were used to repay amounts outstanding under our credit facilities and for general partnership purposes. The common units offered represented approximately 23% of the outstanding equity of PNG. We own the remaining 77% equity interest in PNG. We continue to control the entity, and therefore, consolidate the financial results.

Prior to the PNG IPO, we owned 100% of PNGS’ natural gas storage business, the predecessor of PNG, and related operating entities. Immediately prior to the closing of the IPO, we contributed 100% of the equity interests in PNGS and its subsidiaries to PNG in exchange for approximately 18.1 million common units, approximately 13.9 million Series A subordinated units, 11.5 million Series B subordinated units and a 2% general partner interest and incentive distribution rights. In conjunction with the offering, we recorded noncontrolling interest of $167 million associated with the book value of PNG sold to the public. We also recorded an increase to our partners’ capital of approximately $101 million associated with the net increase from our share of the proceeds received in the offering partially offset by the dilution of our interest in PNG resulting from the IPO.

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PAA Modification of Holdings in PNG Subordinated Units

On August 16, 2010, the Amended and Restated Agreement of Limited Partnership of PNG was amended and restated (the “Second Amended and Restated Agreement”) to reduce the number of Series A subordinated units by 2.0 million and increase the number of Series B subordinated units by an equivalent amount. The Second Amended and Restated Agreement also increased the number of potential conversion tranches on Series B subordinated units from three to five. In addition, the terms of the Series B subordinated units were modified to extend the conversion period by raising the operating and financial performance benchmarks of approximately one-third of the Series B subordinated units outstanding prior to this modification. This amendment was intended to increase the distribution coverage and organic growth profile of PNG’s common and Series A subordinated units and improve PNG’s posture with respect to potential acquisitions. We accounted for this transaction as an exchange between entities under common control and accordingly, we reclassified the book value of the 2.0 million Series A subordinated units at the time of the modification to Series B subordinated units.

The following table sets forth the changes made to our holdings in the limited partner units of PNG from May 5, 2010 through December 31, 2010 (units in millions):

	Prior to Modification	Modification		Post Modification
PNG Units Owned by PAA:
Common Units	18.1	—		18.1
Series A Subordinated Units	13.9	(2.0	)	11.9
Common & Series A Subordinated Unit Subtotal	32.0	(2.0	)	30.0
Series B Subordinated Units (Performance Thresholds):
Tranche 1 ($1.44 / 29.6 Bcf)	4.6	(2.0	)	2.6
Tranche 2 ($1.53 / 35.6 Bcf)	3.8	(1.0	)	2.8
Tranche 3 ($1.63 / 41.6 Bcf)	3.1	(1.0	)	2.1
Tranche 4 ($1.71 / 48.0 Bcf)	—	3.0		3.0
Tranche 5 ($1.80 / 48.0 Bcf)	—	3.0		3.0
Series B Subordinated Unit Subtotal	11.5	2.0		13.5
Total PNG Units Owned by PAA (1)	43.5	—		43.5

(1) See “PNG Transaction Grants” in Note 10.

Series A and Series B Subordinated Units. The Series A subordinated units are not entitled to receive any distributions until the common units have received the MQD ($1.35 on an annualized basis) plus any arrearages in the payment of the MQD from prior quarters. The Series A subordinated units will convert to common units once certain earnings and distribution targets are met for three consecutive, non-overlapping four-quarter periods. The Series B subordinated units are not entitled to participate in quarterly distributions until they convert into Series A subordinated units. The Series B subordinated units will convert into Series A subordinated units upon satisfaction of the following operational and financial conditions:

· 2,600,000 Series B subordinated units will convert into Series A subordinated units on a one-for-one basis if (a) the aggregate amount of working gas storage capacity at Pine Prairie that has been placed into service totals at least 29.6 Bcf, (b) PNG generates distributable cash flow for two consecutive quarters sufficient to pay a quarterly distribution of at least $0.36 per unit (representing an annualized distribution of $1.44 per unit) on the weighted average number of outstanding common units and Series A subordinated units and all of such Series B subordinated units and (c) PNG makes a quarterly distribution of available cash of at least $0.36 per quarter for two consecutive quarters on all outstanding common units and Series A subordinated units and the corresponding distributions on PNG’s general partner’s 2% interest and the related distributions on the incentive distribution rights;

· 2,833,333 Series B subordinated units will convert into Series A subordinated units on a one-for-one basis if (a) the aggregate amount of working gas storage capacity at Pine Prairie that has been placed into service totals at least 35.6 Bcf, (b) PNG generates distributable cash flow for two consecutive quarters sufficient to pay a quarterly distribution of at least $0.3825 per unit (representing an annualized distribution of $1.53 per unit) on the weighted average number of outstanding common units and Series A subordinated units and all of such Series B subordinated units and, if any, the Series B subordinated units described in the prior bullet and (c) PNG makes a quarterly distribution of available cash of at least $0.3825 per quarter for two consecutive quarters on all outstanding common units and

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Series A subordinated units and the corresponding distributions on PNG’s general partner’s 2% interest and the related distributions on the incentive distribution rights;

· 2,066,667 Series B subordinated units will convert into Series A subordinated units on a one-for-one basis if (a) the aggregate amount of working gas storage capacity at Pine Prairie that has been placed into service totals at least 41.6 Bcf, (b) PNG generates distributable cash flow for two consecutive quarters sufficient to pay a quarterly distribution of at least $0.4075 per unit (representing an annualized distribution of $1.63 per unit) on the weighted average number of outstanding common units and Series A subordinated units and all of such Series B subordinated units and, if any, the Series B subordinated units described in the prior two bullets and (c) PNG makes a quarterly distribution of available cash of at least $0.4075 per quarter for two consecutive quarters on all outstanding common units and Series A subordinated units and the corresponding distributions on PNG’s general partner’s 2% interest and the related distributions on the incentive distribution rights;

· 3,000,000 Series B subordinated units will convert into Series A subordinated units on a one-for-one basis if (a) the aggregate amount of working gas storage capacity at Pine Prairie that has been placed into service totals at least 48.0 Bcf, (b) PNG generates distributable cash flow for two consecutive quarters sufficient to pay a quarterly distribution of at least $0.4275 per unit (representing an annualized distribution of $1.71 per unit) on the weighted average number of outstanding common units and Series A subordinated units and all of such Series B subordinated units and, if any, the Series B subordinated units described in the prior three bullets and (c) PNG makes a quarterly distribution of available cash of at least $0.4275 per quarter for two consecutive quarters on all outstanding common units and Series A subordinated units and the corresponding distributions on PNG’s general partner’s 2% interest and the related distributions on the incentive distribution rights; and

· 3,000,000 Series B subordinated units will convert into Series A subordinated units on a one-for-one basis if (a) the aggregate amount of working gas storage capacity at Pine Prairie that has been placed into service totals at least 48.0 Bcf, (b) PNG generates distributable cash flow for two consecutive quarters sufficient to pay a quarterly distribution of at least $0.45 per unit (representing an annualized distribution of $1.80 per unit) on the weighted average number of outstanding common units and Series A subordinated units and all of such Series B subordinated units and, if any, the Series B subordinated units described in the prior four bullets and (c) PNG makes a quarterly distribution of available cash of at least $0.45 per quarter for two consecutive quarters on all outstanding common units and Series A subordinated units and the corresponding distributions on PNG’s general partner’s 2% interest and the related distributions on the incentive distribution rights.

PNG’s general partner will determine whether the in-service operational tests set forth above have been satisfied. To the extent that the operational tests described above are satisfied prior to or during the two-quarter period applicable to the financial tests described above, the holder of the Series B subordinated units subject to conversion will be entitled to receive the quarterly distribution payable with respect to the second quarter of such two-quarter period. In all other circumstances, where the operational tests are satisfied following the two-quarter period applicable to the financial tests, the holder of the Series B subordinated units subject to conversion will be entitled to receive any distribution payable following the satisfaction of such operational tests.

Any Series B subordinated units that remain outstanding as of December 31, 2018 will automatically be cancelled.

Following conversion of any Series B subordinated units into Series A subordinated units, such converted Series B subordinated units will further convert into common units (together with any other outstanding Series A subordinated units) to the extent that the tests for conversion of the Series A subordinated units are satisfied. In determining whether such conversion tests have been satisfied, the Series B subordinated units that have converted into Series A subordinated units will be treated as Series A subordinated units from and after the date of their conversion into Series A subordinated units.

If at the time the above operational and financial tests are satisfied, the subordination period has already ended and all outstanding Series A subordinated units have converted into common units, the Series B subordinated units will instead convert directly into common units on a one-for-one basis and participate in the quarterly distribution payable to common units.

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PNG transactions subsequent to December 31, 2010

PNG Common Unit Issuance. During February 2011, in connection with the Southern Pines Acquisition, PNG completed a private placement of approximately 17.4 million PNG common units to third-party purchasers for net proceeds of approximately $370 million. In addition, we purchased approximately 10.2 million PNG common units for approximately $230 million, including our proportionate general partner contribution of $12 million. As a result of these transactions, our aggregate ownership interest in PNG decreased from approximately 77% to approximately 64%.

Formation of SLC Pipeline LLC

During the fourth quarter of 2008, we completed construction on a 94-mile expansion of the Salt Lake City Area system from Wahsatch, Utah to Salt Lake City. During the first quarter of 2009, this pipeline became fully operational. Pursuant to a master formation agreement, we contributed the pipeline with a book value of approximately $254 million to a newly formed joint venture, SLC Pipeline. HEP contributed approximately $26 million in cash for a 25% ownership in SLC Pipeline. We own the remaining 75% interest in SLC Pipeline and control the joint venture, and therefore, have consolidated the financial results. We recognized a loss in partners’ capital of approximately $38 million related to the formation of the SLC Pipeline joint venture during 2009. This loss represented the difference between HEP’s contribution of cash and the book value of its 25% interest in the net assets of SLC Pipeline.

Noncontrolling Interests Rollforward

The following table reflects the changes in the noncontrolling interests in partners’ capital (in millions):

	For the Year Ended December 31,
	2010			2009
Beginning balance	$	63		$	—
Sale of noncontrolling interests in subsidiaries	167			64
Net income attributable to noncontrolling interests	9			1
Distributions to noncontrolling interests	(10		)	(2		)
Equity compensation expense	3			—
Other	(1		)	—
Ending Balance	$	231		$	63

Equity Offerings

During the three years ended December 31, 2010, we completed the following equity offerings of our common units as shown in the table below (in millions, except unit and per unit data). See “PNGS Acquisition” below for discussion of additional common units issued in 2009 in connection with such acquisition.

						General
		Gross		Proceeds		Partner					Net
Period	Units Issued	Unit Price		from Sale		Contribution		Costs			Proceeds
November 2010 (1)	4,780,000	$	62.60	$	299	$	6	$	(9	)	$	296
2010 Total	4,780,000			$	299	$	6	$	(9	)	$	296

September 2009 (1)	5,290,000	$	46.70	$	247	$	5	$	(6	)	$	246
March 2009 (1)	5,750,000	36.90		212		4		(6		)	210
2009 Total	11,040,000			$	459	$	9	$	(12	)	$	456

May 2008 (1)	6,900,000	$	46.31	$	320	$	6	$	(11	)	$	315
2008 Total	6,900,000			$	320	$	6	$	(11	)	$	315

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(1) These offerings of common units were underwritten transactions that required us to pay a gross spread. The net proceeds from these offerings were used to reduce outstanding borrowings under our credit facilities and for general partnership purposes.

PNGS Acquisition

In September 2009, we issued 1,907,305 common units valued at approximately $91 million in order to satisfy a portion of the PNGS Acquisition purchase price. In conjunction with the issuance, we received a contribution from our general partner of approximately $2 million. See Note 3 for further discussion.

Class B Units of Plains AAP, L.P.

In August 2007, the owners of Plains AAP, L.P. authorized the board of directors of Plains All American GP LLC to issue Class B units of Plains AAP, L.P. (“AAP LP Class B units”). At December 31, 2010, approximately 175,500 AAP LP Class B units were outstanding, of which 80,063 were earned. A total of 24,500 AAP LP Class B units are reserved for future issuances. See Note 10 for further discussion of the AAP LP Class B units.

Canadian Withholding Tax

For federal income tax purposes, we are treated as a partnership. Our unitholders are required to report their share of our income, gains, losses and deductions on their federal income tax return. In certain cases, we are subject to, and have paid, Canadian income and withholding taxes. The withholding tax payments are considered to be paid on behalf of our unitholders and thus are treated as distributions for financial reporting purposes. During 2009, we paid approximately $6 million of Canadian withholding taxes.

Note 6—Derivatives and Hedging Instruments

We identify the risks that underlie our core business activities and use risk management strategies to mitigate those risks when we determine that there is value in doing so. Our policy is to use derivative instruments only for risk management purposes. We use various derivative instruments to (i) manage our exposure to commodity price risk as well as to optimize our profits, (ii) manage our exposure to interest rate risk and (iii) manage our exposure to currency exchange rate risk. Our commodity risk management policies and procedures are designed to help ensure that our hedging activities address our risks by monitoring NYMEX, ICE and over-the-counter positions, as well as physical volumes, grades, locations, delivery schedules and storage capacity. Our interest rate and currency exchange rate risk management policies and procedures are designed to monitor our positions and ensure that those positions are consistent with our objectives and approved strategies. Our policy is to formally document all relationships between hedging instruments and hedged items, as well as our risk management objectives and strategies for undertaking the hedge. This process includes specific identification of the hedging instrument and the hedged transaction, the nature of the risk being hedged and how the hedging instrument’s effectiveness will be assessed. Both at the inception of the hedge and on an ongoing basis, we assess whether the derivatives used in a transaction are highly effective in offsetting changes in cash flows or the fair value of hedged items.

Commodity Price Risk Hedging

Our core business activities contain certain commodity price-related risks that we manage in various ways, including the use of derivative instruments. Our policy is (i) to only purchase product for which we have a market, (ii) to structure our sales contracts so that price fluctuations do not materially affect our operating income and (iii) not to acquire and hold physical inventory or derivatives for the purpose of speculating on commodity price changes. The material commodity related risks inherent in our business activities can be summarized into the following general categories:

Commodity Purchases and Sales — In the normal course of our operations, we purchase and sell commodities. We use derivatives to manage the associated risks and to optimize profits. As of December 31, 2010, net derivative positions related to these activities included:

· An approximate 176,700 barrels per day net long position (total of 5.3 million barrels) associated with our crude oil activities, which was unwound ratably during January 2011 to match monthly average pricing.

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· A net short spread position averaging approximately 40,600 barrels per day (total of 28 million barrels), which hedges a portion of our anticipated crude oil lease gathering purchases through December 2012. These derivatives also hedge the margin associated with anticipated crude oil purchases. These derivatives in the aggregate do not result in exposure to outright price movements.

· A net short spread position averaging approximately 13,200 barrels per day (total of 4.8 million barrels) of calendar spread call options for the period February 2011 through January 2012. These derivatives also hedge the margin associated with anticipated crude oil purchases. These derivatives in the aggregate do not result in exposure to outright price movements.

· Approximately 4,400 barrels per day on average (total of 3.1 million barrels) of WTS/WTI crude oil basis swaps through December 2012, which hedge anticipated sales of crude oil (WTI).

Storage Capacity Utilization — We own approximately 65 million barrels of crude oil, LPG and refined products storage capacity that is not used in our transportation operations. This storage may be leased to third parties or utilized in our own supply and logistics activities, including for the storage of inventory in a contango market. For capacity allocated to our supply and logistics operations, we have utilization risk if the market structure is backwardated. As of December 31, 2010, we used derivatives to manage the risk of not utilizing approximately 2.4 million barrels per month of storage capacity through 2012. These positions are a combination of calendar spread options and NYMEX futures contracts. These positions involve no outright price exposure, but instead represent potential offsetting purchases and sales between time periods (first month versus second month for example).

Inventory Storage — At times, we elect to purchase and store crude oil, LPG, natural gas and refined products inventory in conjunction with our supply and logistics activities. When we purchase and store inventory, we enter into physical sales contracts or use derivatives to mitigate price risk associated with the inventory. As of December 31, 2010, we had derivatives totaling approximately 16.7 million barrels hedging our inventory.

We also purchase foreign cargoes of crude oil and may enter into derivatives to mitigate various price risks associated with the purchase and ultimate sale of foreign crude inventory. As of December 31, 2010, we had approximately 1.6 million barrels of crude oil derivatives hedging the anticipated sale of foreign crude inventory.

Pipeline Loss Allowance Oil — As is common in the pipeline transportation industry, our tariffs incorporate a loss allowance factor that is intended to, among other things, offset losses due to evaporation, measurement and other losses in transit. We utilize derivative instruments to hedge a portion of the anticipated sales of the allowance oil that is to be collected under our tariffs. As of December 31, 2010, we had PLA hedges consisting of (i) a net short position consisting of crude oil futures and swaps for an average of approximately 2,600 barrels per day (total of 1.8 million barrels) through December 2012, (ii) a long put option position of approximately 0.4 million barrels through December 2012 and (iii) a long call option position of approximately 1.1 million barrels through December 2012.

Natural Gas Purchases and Sales — Our gas storage facilities require minimum levels of natural gas (“base gas”) to operate. For our natural gas storage facilities that are under construction, we anticipate purchasing base gas in future periods as construction is completed. We use derivatives to hedge such anticipated purchases of natural gas. As of December 31, 2010, we had a long position of approximately 1 Bcf consisting of natural gas futures contracts through August 2011 and natural gas call options for approximately 1 Bcf through August 2011. Additionally, we use derivatives to hedge anticipated sales of operational gas when that gas is no longer needed for cavern development purposes.

All of our commodity derivatives that qualify for hedge accounting are designated as cash flow hedges. We have determined that substantially all of our physical purchase and sale agreements qualify for the NPNS exclusion. Physical commodity contracts that meet the definition of a derivative but are ineligible, or not designated, for the NPNS scope exception are recorded on the balance sheet at fair value, with changes in fair value recognized in earnings.

Interest Rate Risk Hedging

We use interest rate derivatives to hedge interest rate risk associated with anticipated debt issuances and outstanding debt instruments. The derivative instruments we use to manage this risk consist primarily of interest rate swaps and treasury locks. As of December 31, 2010, AOCI includes deferred losses of $8 million that relate to terminated interest rate swaps and treasury locks that were designated for hedge accounting. These terminated interest rate derivatives

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were cash-settled in connection with the issuance or refinancing of debt agreements. The deferred loss related to these instruments is being amortized to interest expense over the original terms of the hedged debt instruments.

During July 2009, we entered into four interest rate swaps. For the interest rate swaps, we receive fixed interest payments and pay floating-rate interest payments based on three-month LIBOR plus an average spread of 2.42% on a semi-annual basis. The swaps have an aggregate notional amount of $300 million with fixed rates of 4.25%. Two of the swaps terminate in 2011 and two of the swaps terminate in 2012. The swaps that terminate in 2012 are designated as a fair value hedge.

During October 2010, we entered into three forward starting interest rate swaps to hedge the underlying benchmark interest rate related to forecasted debt issuances through 2013. The following table summarizes the terms of our forward starting interest rate swaps (notional amounts in millions):

Hedged Transaction

Number and
Types of
Derivatives
Employed

Notional
Amount

Mandatory
Termination Date

Average Rate
Locked

Accounting
Treatment

Anticipated debt offering

1 forward starting swap (30-year)

12/15/2013

3.87

Cash flow hedge

Anticipated debt offering

2 forward starting swaps (10-year)

10/15/2012

3.30

Cash flow hedge

These swaps were terminated in January 2011.

Currency Exchange Rate Risk Hedging

Because a significant portion of our Canadian business is conducted in CAD and, at times, a portion of our debt is denominated in CAD, we use foreign currency derivatives to minimize the risks of unfavorable changes in exchange rates. These instruments include foreign currency exchange contracts, forwards and options. As of December 31, 2010, AOCI includes net deferred gains of $15 million that relate to open and settled foreign currency derivatives that were designated for hedge accounting. These foreign currency derivatives hedge the cash flow variability associated with CAD-denominated interest payments on a CAD-denominated intercompany note as a result of changes in the exchange rate.

As of December 31, 2010, our outstanding foreign currency derivatives also include derivatives we use to hedge USD-denominated crude oil purchases and sales in Canada. In addition, we may from time to time hedge the commodity price risk associated with a CAD-denominated commodity transaction with a USD-denominated commodity derivative. In conjunction with entering into the commodity derivative, we may enter into a foreign currency derivative to hedge the resulting foreign currency risk. These foreign currency derivatives are generally short-term in nature and are not designated for hedge accounting.

At December 31, 2010, our open foreign currency derivatives included forward exchange contracts that exchange CAD for USD on a net basis as follows (in millions):

	CAD		USD		Average Exchange Rate
2011	$	15	$	15	CAD $1.01 to US $1.00
2012	$	15	$	15	CAD $1.01 to US $1.00
2013	$	9	$	9	CAD $1.00 to US $1.00

Summary of Financial Impact

For derivatives that qualify as a cash flow hedge, changes in fair value of the effective portion of the hedges are deferred to AOCI and recognized in earnings in the periods during which the underlying physical transactions impact earnings. For our interest rate swaps that qualify as a fair value hedge, changes in the fair value of the derivative and changes in the fair value of the underlying hedged item, attributable to the hedged risk, are recognized in earnings each period. Derivatives that do not qualify for hedge accounting and the portion of cash flow hedges that are not highly effective in offsetting changes in cash flows of the hedged items are recognized in earnings each period. Cash settlements associated with our derivative activities are reflected as operating cash flows in our consolidated statements of cash flows.

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A summary of the impact of our derivative activities recognized in earnings for the years ended December 31, 2010 and 2009 is as follows (in millions):

	Year Ended December 31, 2010								Year Ended December 31, 2009
			Derivatives						Derivatives in			Derivatives
	Derivatives in		Not						Cash Flow			Not
	Hedging		Designated						Hedging			Designated
Location of gain/(loss)	Relationships (1) (2) (3)		as a Hedge (4)			Total			Relationships (1) (2)			as a Hedge (4)			Total
Commodity Derivatives

Supply and Logistics segment revenues	$	14	$	2		$	16		$	(98	)	$	(10	)	$	(108	)

Transportation segment revenues	2		—			2			4			—			4

Facilities segment revenues	—		—			—			(1		)	—			(1		)

Purchases and related costs	8		(12		)	(4		)	69			122			191

Field operating costs	—		3			3			—			—			—

Interest Rate Derivatives

Other income, net	—		—			—			—			(1		)	(1		)

Interest expense	1		2			3			(1		)	3			2

Foreign Exchange Derivatives

Supply and Logistics segment revenues	—		2			2			—			7			7

Purchases and related costs	—		2			2			1			3			4

Other income, net	—		(1		)	(1		)	10			(7		)	3

Total Gain/(Loss) on Derivatives Recognized in Income	$	25	$	(2	)	$	23		$	(16	)	$	117		$	101

(1) Amounts represent derivative gains and losses that were reclassified from AOCI to earnings during the period to coincide with the earnings impact of the respective hedged transaction.

(2) Amounts include losses of approximately $1 million and $8 million for the years ended December 31, 2010 and December 31, 2009 respectively, that represent the ineffective portion of our cash flow hedges. These amounts relate to commodity derivatives and are recognized in Supply and Logistics segment revenues during such periods.

(3) Interest expense includes a net gain of approximately $1 million associated with outstanding interest rate swaps, which are designated as a fair value hedge.

(4) Includes realized and unrealized gains or losses for derivatives not designated for hedge accounting during the period.

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The following table summarizes the derivative assets and liabilities on our consolidated balance sheet on a gross basis as of December 31, 2010 (in millions):

	Asset Derivatives			Liability Derivatives
	Balance Sheet			Balance Sheet
	Location	Fair Value		Location	Fair Value
Derivatives designated as hedging instruments:
Commodity derivatives	Other current assets	$	71	Other current assets	$	(70	)
				Other long-term assets	(1		)
				Other current liabilities	(1		)
Interest rate derivatives	Other current assets	10
Total derivatives designated as hedging instruments		$	81		$	(72	)

Derivatives not designated as hedging instruments:
Commodity derivatives	Other current assets	$	11	Other current assets	$	(68	)
	Other long-term assets	20
	Other current liabilities	2		Other current liabilities	(10		)
Interest rate derivatives	Other current assets	4
	Other long-term assets	1
Foreign currency derivatives	Other current assets	1
Total derivatives not designated as hedging instruments		$	39		$	(78	)

Total derivatives		$	120		$	(150	)

The following table summarizes the derivative assets and liabilities on our consolidated balance sheet on a gross basis as of December 31, 2009 (in millions):

	Asset Derivatives			Liability Derivatives
	Balance Sheet			Balance Sheet
	Location	Fair Value		Location	Fair Value
Derivatives designated as hedging instruments:
Commodity derivatives	Other current assets	$	153	Other current liabilities	$	(140	)
	Other long-term assets	34		Other long-term liabilities	(1		)
Foreign currency derivatives	Other long-term assets	2
Total derivatives designated as hedging instruments		$	189		$	(141	)

Derivatives not designated as hedging instruments:
Commodity derivatives	Other current assets	$	34	Other current liabilities	$	(91	)
	Other long-term assets	41		Other long-term liabilities	(34		)
Interest rate derivatives	Other current assets	1
	Other long-term assets	1
Foreign currency derivatives	Other current assets	2		Other current liabilities	(3		)
Total derivatives not designated as hedging instruments		$	79		$	(128	)

Total derivatives		$	268		$	(269	)

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As of December 31, 2010, there was a net loss of $79 million deferred in AOCI. The total amount of deferred net loss recorded in AOCI is expected to be reclassified to future earnings contemporaneously with (i) the earnings recognition of the underlying hedged commodity transaction, (ii) interest expense accruals associated with underlying debt instruments or (iii) the recognition of a foreign currency gain or loss upon the remeasurement of certain CAD-denominated intercompany balances. Of the total net loss deferred in AOCI at December 31, 2010, we expect to reclassify a net loss of approximately $88 million to earnings in the next twelve months. Of the remaining deferred gain in AOCI, approximately $12 million is expected to be reclassified to earnings prior to 2014 with the remaining deferred loss being reclassified to earnings through 2019. These amounts are predominately based on market prices at the current period end, thus actual amounts to be reclassified will differ and could vary materially as a result of changes in market conditions.

During the twelve months ended December 31, 2009, we discontinued a cash flow hedge as a result of the hedged transaction becoming no longer probable of occurring and reclassified a deferred gain of approximately $5 million from AOCI to other income. During the twelve months ended December 31, 2010, all of our hedged transactions were probable of occurring.

The net deferred gain/(loss) recognized in AOCI for derivatives during the twelve months ended December 31, 2010 and 2009 are as follows (in millions):

	For the Years Ended December 31,
	2010			2009
Commodity derivatives	$	(82	)	$	(145	)
Foreign currency derivatives	(2		)	(4		)
Interest rate derivatives	8			(2		)
Total	$	(76	)	$	(151	)

Our accounting policy is to offset derivative assets and liabilities executed with the same counterparty when a master netting agreement exists. Accordingly, we also offset derivative assets and liabilities with amounts associated with cash margin. Our exchange-traded derivatives are transacted through brokerage accounts and are subject to margin requirements as established by the respective exchange. On a daily basis, our account equity (consisting of the sum of our cash balance and the fair value of our open derivatives) is compared to our initial margin requirement resulting in the payment or return of variation margin. As of December 31, 2010, we had a net broker receivable of approximately $99 million (consisting of initial margin of $56 million increased by $43 million of variation margin that had been posted by us). As of December 31, 2009, we had a net broker receivable of approximately $53 million (consisting of initial margin of $71 million reduced by $18 million of variation margin that had been returned to us). At December 31, 2010 and 2009, none of our outstanding derivatives contained credit-risk related contingent features that would result in a material adverse impact to us upon any change in our credit ratings.

The following table sets forth by level within the fair value hierarchy our financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2010. Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, which does affect the placement of assets and liabilities within the fair value hierarchy levels.

	Fair Value as of December 31, 2010 (in millions)											Fair Value as of December 31, 2009 (in millions)
Recurring Fair Value Measures (1)	Level 1			Level 2		Level 3			Total			Level 1		Level 2		Level 3			Total
Commodity derivatives	$	(16	)	$	—	$	(30	)	$	(46	)	$	27	$	—	$	(31	)	$	(4	)
Interest rate derivatives	—			—		15			15			—		—		2			2
Foreign currency derivatives	—			—		1			1			—		—		1			1
Total	$	(16	)	$	—	$	(14	)	$	(30	)	$	27	$	—	$	(28	)	$	(1	)

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

The determination of the fair values above includes not only the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits and letters of credit) but also the impact of our nonperformance risk on our liabilities. The fair value of our commodity derivatives, interest-rate derivatives and foreign currency derivatives includes adjustments for credit risk. We measure credit risk by deriving a probability of default from market-observed credit default swap spreads as of the measurement date. The probability of default is applied to the net credit exposure of each of

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our counterparties and includes a recovery rate adjustment. The recovery rate is an estimate of what would ultimately be recovered through a bankruptcy proceeding in the event of default. There were no changes to any of our valuation techniques during the period.

Level 1

Included within level 1 of the fair value hierarchy are exchange-traded commodity derivatives such as futures, options and swaps. The fair value of exchange-traded commodity derivatives is based on unadjusted quoted prices in active markets and is therefore classified within level 1 of the fair value hierarchy.

Level 2

There was no activity during the period within level 2 of the fair value hierarchy.

Level 3

Included within level 3 of the fair value hierarchy are the following derivatives:

· Commodity Derivatives: Level 3 commodity derivatives include over-the-counter commodity derivatives such as forwards, swaps and options and certain physical commodity contracts. The fair value of our level 3 commodity derivatives is based on either an indicative broker or dealer price quotation or a valuation model. Our valuation models utilize inputs such as forward price and volatility but do not involve significant management judgments.

· Interest Rate Derivatives: Level 3 interest rate derivatives include interest rate swaps. The fair value of our interest rate derivatives is based on indicative broker or dealer price quotations. Broker or dealer price quotations are corroborated with objective inputs including forward interest rates obtained from pricing services.

· Foreign Currency Derivatives: Level 3 foreign currency derivatives include foreign currency swaps, forward exchange contracts and options. The fair value of our foreign currency derivatives is based on indicative broker or dealer price quotations. Broker or dealer price quotations are corroborated with objective inputs including forward CAD/USD forward exchange rates obtained from pricing services.

The majority of our level 3 derivatives are classified as such because the broker or dealer price quotations used to measure fair value and the pricing services used to corroborate the quotations are indicative quotations rather than quotations whereby the broker or dealer is ready and willing to transact. However, the fair value of these level 3 derivatives is not based upon significant management assumptions or subjective inputs.

Rollforward of Level 3 Net Liability

The following table provides a reconciliation of changes in fair value of the beginning and ending balances for our derivatives classified as level 3 (in millions):

	Year Ended December 31,
	2010			2009
Beginning Balance	$	(28	)	$	74
Unrealized gains/(losses):
Included in earnings (1)	(22		)	46
Included in other comprehensive income	3			(43		)
Settlements and derivatives entered into during the period	33			(105		)
Ending Balance	$	(14	)	$	(28	)

Change in unrealized gains/(losses) included in earnings relating to level 3 derivatives still held at the end of the periods	$	(27	)	$	31

(1) We reported unrealized gains and losses associated with level 3 commodity derivatives in our consolidated statements of operations as Supply and Logistics segment revenues. Gains and losses associated with interest rate derivatives are

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reported in our consolidated statements of operations as Interest expense. Gains and losses associated with foreign currency derivatives are reported in our consolidated statements of operations as either Supply and Logistics segment revenues, Purchases and related costs, or Other income, net.

We believe that a proper analysis of our level 3 gains or losses must incorporate the understanding that these items are generally used to hedge our commodity price risk, interest rate risk and foreign currency exchange risk and will therefore be offset by gains or losses on the underlying transactions.

Note 7—Income Taxes

U.S. Federal and State Taxes

As an MLP, we are not subject to U.S. federal income taxes; rather the tax effect of our operations is passed through to our unitholders. Although we are subject to state income taxes in some states, the impact to the years ended December 31, 2010, 2009 and 2008 was immaterial.

Canadian Federal and Provincial Taxes

In 2010 and prior years, our Canadian operations were operated through a combination of corporate entities subject to Canadian federal and provincial taxes and a limited partnership which was treated as a flow-through entity for tax purposes. Due to changes in Canadian legislation and the Fifth Protocol to the U.S./Canada Tax Treaty, we restructured our Canadian investment on January 1, 2011. As of this date, all of our Canadian operations are conducted within entities that are treated as corporations for Canadian tax purposes (flow through for U.S. tax purposes) and that are subject to Canadian federal and provincial taxes. Payments of interest and dividends from Canada to other Plains entities will be subject to Canadian withholding tax that is treated as a distribution to unitholders.

Tax Components

Components of income tax expense are as follows (in millions):

	Year Ended December 31,
	2010			2009			2008
Current tax (benefit)/expense:
State income tax	$	1		$	2		$	1
Canadian federal and provincial income tax	(2		)	13			8
Total current tax (benefit)/expense	$	(1	)	$	15		$	9

Deferred tax (benefit)/expense:
State income tax	$	1		$	—		$	—
Canadian federal and provincial income tax	(1		)	(9		)	(1		)
Total deferred tax (benefit)/expense	$	—		$	(9	)	$	(1	)
Total income tax (benefit)/expense	$	(1	)	$	6		$	8

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The difference between tax expense based on the statutory federal income tax rate and our effective tax expense is summarized as follows (in millions):

	Year Ended December 31,
	2010			2009			2008
Income before tax	$	513		$	586		$	445
Partnership earnings not subject to current Canadian tax	(509		)	(585		)	(422		)
	$	4		$	1		$	23
Canadian federal and provincial corporate tax rate	28.0		%	29.0		%	29.5		%
Income tax at statutory rate	$	1		$	—		$	7

Current tax expense:
Canadian period tax as a result of book versus tax differences	—			4			4
Canadian permanent differences between book and tax	(3		)	9			(3		)
State income tax	1			2			1
Current income tax (benefit)/expense	$	(1	)	$	15		$	9

Deferred tax expense:
State deferred income tax	1			—			—
Canadian deferred tax (benefit)/expense as a result of book versus tax differences	(1		)	(9		)	(1		)
Deferred income tax (benefit)/expense	$	—		$	(9	)	$	(1	)
Total income tax (benefit)/expense	$	(1	)	$	6		$	8

Deferred tax assets and liabilities, which are included net within other long-term liabilities and deferred credits in our consolidated balance sheet, result from the following (in millions):

	December 31,
	2010			2009
Deferred tax assets:
Book accruals in excess of current tax deductions	$	4		$	13
Total deferred tax assets	4			13

Deferred tax liabilities:
Property, plant and equipment in excess of tax values	(128		)	(134		)
Total deferred tax liabilities	(128		)	(134		)
Net deferred tax liabilities	$	(124	)	$	(121	)

Generally, tax returns for our Canadian entities are open to audit from 2006 through 2010. Our U.S. and state tax years are open to examination from 2006 to 2010.

Note 8—Major Customers and Concentration of Credit Risk

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Financial instruments that potentially subject us to concentrations of credit risk consist principally of trade receivables. Our accounts receivable are primarily from purchasers and shippers of crude oil. This industry concentration has the potential to impact our overall exposure to credit risk in that the customers may be similarly affected by changes in economic, industry or other conditions. We review credit exposure and financial information of our counterparties and generally require letters of credit for receivables from customers that are not considered creditworthy, unless the credit risk can otherwise be reduced. See Note 2 for additional discussion of our accounts receivable and our review of credit exposure.

Note 9—Related Party Transactions

Reimbursement of Expenses of Our General Partner and its Affiliates

We do not pay our general partner a management fee, but we do reimburse our general partner for all direct and indirect costs of services provided to us or incurred on our behalf, including the costs of employee, officer and director compensation and benefits allocable to us as well as all other expenses necessary or appropriate to the conduct of our business (other than expenses related to grants of AAP LP Class B units). We record these costs on the accrual basis in the period in which our general partner incurs them. Our partnership agreement provides that our general partner will determine the expenses that are allocable to us in any reasonable manner determined by our general partner in its sole discretion. Total costs reimbursed by us to our general partner for the years ended December 31, 2010, 2009 and 2008 were $374 million, $328 million and $289 million, respectively.

Vulcan Energy Corporation

In December 2010, Vulcan Energy Corporation (“Vulcan Energy”) sold its 50.1% ownership interest in our general partner. Substantially all of the interest sold was acquired by existing owners of our general partner or their affiliates. Vulcan Energy retained its limited partner interest in us. As of December 31, 2010, Vulcan Energy owned approximately 9% of our outstanding limited partner units.

Voting Agreements. In August 2005, in connection with an increase in Vulcan Energy’s ownership interest in our general partner, Vulcan Energy entered into a voting agreement that restricted its ability to unilaterally elect or remove the independent directors serving on our audit committee. Lynx Holdings I, LLC, also agreed to restrict certain of its voting rights with respect to its membership interest in Plains All American GP LLC. Our Chief Executive Officer and Chief Operating Officer agreed, subject to certain ongoing conditions, to waive certain change-of-control payment rights that would otherwise have been triggered by the increase in Vulcan Energy’s ownership interest.

Administrative Services Agreement. On October 14, 2005, Plains All American GP LLC and Vulcan Energy entered into an Administrative Services Agreement, effective as of September 1, 2005 (the “Services Agreement”). Pursuant to the Services Agreement, Plains All American GP LLC provided administrative services to Vulcan Energy for consideration of an annual fee of $1 million, plus certain expenses. The Services Agreement was terminated in December 2010 in connection with the sale by Vulcan Energy of its 50.1% interest in our general partner. However, we have agreed to provide transition services and assistance to Vulcan Energy until June 2011 for consideration of a $1 million fee.

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Occidental Petroleum Corporation

As of December 31, 2010, a subsidiary of Occidental Petroleum Corporation (“Oxy”) owned approximately 35% of our general partner interest and had a representative on the board of directors of Plains All American GP LLC. During the three years ended December 31, 2010, we received sales and transportation storage revenues and purchased petroleum products from companies associated with Oxy, as detailed below (in millions):

	For the Year Ended December 31,
	2010		2009		2008
Total revenues	$	2,189	$	181	$	159

Purchases and related costs	$	221	$	164	$	224

We currently have a netting arrangement with Oxy. Our gross receivable and payable amounts with affiliates of Oxy were as follows (in millions):

	At December 31,
	2010		2009
Trade accounts receivable and other receivables, net	$	379	$	82

Accounts payable	$	124	$	103

Natural Gas Storage Investment

In September 2005, we and Vulcan Gas Storage LLC, a subsidiary of Vulcan LLC, an investment arm of Paul G. Allen, formed PAA/Vulcan to acquire ECI (subsequently known as PAA Natural Gas Storage, LLC or “PNGS”), an indirect subsidiary of Sempra Energy, for approximately $250 million. We and Vulcan Gas Storage each made an initial cash investment of approximately $113 million and Bluewater Natural Gas Storage, LLC, a subsidiary of PAA/Vulcan, entered into a $90 million credit facility contemporaneously with closing.

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Note 10—Equity Compensation Plans

PAA Long-Term Incentive Plan Awards

Our general partner has adopted the Plains All American GP LLC 1998 Long-Term Incentive Plan (the “1998 Plan”), the 2005 Long-Term Incentive Plan (the “2005 Plan”) and the PPX Successor Long-Term Incentive Plan (the “PPX Successor Plan”) for employees and directors, as well as the Plains All American GP LLC 2006 Long-Term Incentive Tracking Unit Plan (the “2006 Plan”) for non-officer employees. The 1998 Plan, 2005 Plan and PPX Successor Plan authorize the issuance of an aggregate of 5.4 million common units deliverable upon vesting. Although other types of awards are contemplated under the plans, currently outstanding awards are limited to “phantom units,” which mature into the right to receive common units of PAA (or cash equivalent) upon vesting. Some awards also include distribution equivalent rights (“DERs”). Subject to applicable vesting criteria, a DER entitles the grantee to a cash payment equal to the cash distribution paid on an outstanding common unit. The 2006 Plan authorizes the grant of approximately 2.1 million “tracking units” which, upon vesting, represent the right to receive a cash payment in an amount based upon the market value of a common unit at the time of vesting. Our general partner is entitled to reimbursement by us for any costs incurred in settling obligations under the plans.

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At December 31, 2010, the following LTIP awards, denominated in PAA units, were outstanding (units in millions):

LTIP Units		PAA Distribution	Estimated Unit Vesting Date
Outstanding		Required	2011	2012	2013	2014	2015
2.8	(1)	$3.50 - $4.45	0.4	0.8	0.5	0.6	0.5
1.6	(2)	$3.50 - $4.25	0.2	0.8	0.3	0.2	0.1
4.4	(3) (4)		0.6	1.6	0.8	0.8	0.6

(1) These LTIP awards have performance conditions requiring the attainment of an annualized PAA distribution of between $3.50 and $4.45 and vest upon the later of a certain date or the attainment of such levels. If the performance conditions are not attained while the grantee remains employed by us, or the grantee does not meet employment requirements, these awards will be forfeited. For purposes of this disclosure, vesting dates are based on an estimate of future distribution levels and assume that all grantees remain employed by us through the vesting date.

(2) These LTIP awards have performance conditions requiring the attainment of an annualized PAA distribution of between $3.50 and $4.25. For these LTIP awards, fifty percent will vest at specified dates regardless of whether the performance conditions are attained. For purposes of this disclosure, vesting dates are based on an estimate of future distribution levels and assume that all grantees remain employed by us through the vesting date.

(3) Approximately 2.4 million of our approximately 4.4 million outstanding LTIP awards also include DERs, of which 0.9 million are currently vested.

(4) LTIP units outstanding do not include Class B units of Plains AAP, L.P. (“AAP LP Class B units”) described below.

PNG Long-Term Incentive Plan Awards

During April 2010, PNG’s general partner adopted the PAA Natural Gas Storage, L.P. 2010 Long Term Incentive Plan (the “PNG Plan”) for employees, directors and consultants. The PNG Plan limits the number of PNG common units that may be delivered pursuant to awards under the plan to 3 million units. Although other types of awards are contemplated under the plan, currently outstanding awards are limited to phantom units, which mature into the right to receive common units of PNG (or cash equivalent) upon vesting. Some awards also include DERs.

At December 31, 2010, the following LTIP awards, denominated in PNG units, were outstanding (units in millions):

LTIP Units		PNG Distribution	Estimated Unit Vesting Date
Outstanding		Required	2011	2012	2013	2014	2015
0.3	(1)	$1.55 - $1.90	—	—	0.1	—	0.2
0.3	(2)	Other	0.1	0.1	0.1	—	—
0.6	(3) (4)		0.1	0.1	0.2	—	0.2

(1) These LTIP awards have performance conditions requiring the attainment of an annualized PNG distribution of between $1.55 and $1.90 and vest upon the later of a certain date or the attainment of such levels. For purposes of this disclosure, vesting dates are based on an estimate of future distribution levels and assume that all grantees remain employed by us through the vesting date.

(2) These LTIP awards have performance conditions requiring the conversion of PNG’s Series A and Series B subordinated units (see Note 5). For purposes of this disclosure, vesting dates are based on an estimate of future distribution levels and assume that all grantees remain employed by us through the vesting date.

(3) Approximately 0.3 million of these LTIP awards also include DERs, of which none are currently vested.

(4) LTIP units outstanding do not include the PNG Transaction Grants or Class B units of PNGS GP LLC described below.

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Our LTIP awards include both liability classified and equity classified awards. In accordance with FASB guidance regarding share-based payments, the fair value of our liability classified LTIP awards is calculated based on the closing market price of the underlying PAA or PNG units at each balance sheet date and adjusted for the present value of any distributions that are estimated to occur on the underlying units over the vesting period that will not be received by the award recipients. The fair value of our equity classified LTIP awards is calculated based on the closing market price of the PAA or PNG units on the respective grant dates and adjusted for the present value of any distributions that are estimated to occur on the underlying units over the vesting period that will not be received by the award recipient. This fair value is recognized as compensation expense over the service period.

Our LTIP awards typically contain performance conditions based on the attainment of certain annualized distribution levels and vest upon the later of a certain date or the attainment of such levels. For awards with performance conditions (such as distribution targets), expense is accrued over the service period only if the performance condition is considered to be probable of occurring. When awards with performance conditions that were previously considered improbable become probable, we incur additional expense in the period that our probability assessment changes. This is necessary to bring the accrued liability associated with these awards up to the level it would be as if we had been accruing for these awards since the grant date. Our DER awards typically contain performance conditions based on the attainment of certain annualized distribution levels and become earned upon the attainment of such levels. The DERs terminate with the vesting or forfeiture of the underlying LTIP award. For liability classified awards, we recognize DER payments in the period the payment is earned as compensation expense. For equity classified awards, we recognize DER payments in the period it is paid as a reduction of partners’ capital.

Prior to PNG’s IPO and adoption of the PNG Plan, certain PNG officers and other individuals were granted LTIP awards under the PAA LTIP Plans. In connection with the adoption of the PNG plan, substantially all of the then outstanding PAA LTIP awards held by PNG officers were converted to PNG LTIP awards. We recognized incremental compensation expense of less than $1 million during the twelve months ended December 31, 2010 as a result of this modification.

Our accrued liability at December 31, 2010 related to all outstanding LTIP awards and DERs is approximately $102 million. This liability includes accruals associated with our assessments that the following performance conditions are probable of occurring: (i) an annualized PAA distribution of $4.00, (ii) an annualized PNG distribution of $1.45 and (iii) the conversion of PNG’s Series A subordinated units and the first tranche of PNG’s Series B subordinated units. At December 31, 2009, the accrued liability was approximately $87 million, which includes accruals associated with our assessment that an annualized PAA distribution of $3.90 was probable of occurring.

PNG Transaction Grants

During September 2010, we entered into agreements with certain of our officers, pursuant to which these officers acquired an aggregate of 375,000 phantom common units, phantom Series A subordinated units, and phantom Series B subordinated units representing a portion of the limited partner interests of PNG issued to us in the IPO. The awards, referred to herein as “PNG Transaction Grants,” will vest upon the completion of the service period and certain performance conditions, including the conversion of PNG’s Series A subordinated units into common units of PNG and the conversion of PNG’s Series B subordinated units into Series A subordinated units of PNG. Upon vesting, these awards will be settled with outstanding common or Series A subordinated units of PNG currently owned by us, resulting in a dilution of our interest in PNG.

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Our equity compensation activity for awards denominated in PAA and PNG units is summarized in the following table (units in millions):

	PAA Units (1)				PNG Units (2)(3)
			Weighted Average				Weighted Average
			Grant Date				Grant Date
	Units		Fair Value per Unit		Units		Fair Value per Unit
Outstanding, December 31, 2007	3.6		$	37.75	—		$	—
Granted	0.5		$	31.79	—		$	—
Vested	(0.1	)	$	32.44	—		$	—
Cancelled or forfeited	(0.1	)	$	36.14	—		$	—
Outstanding, December 31, 2008	3.9		$	36.44	—		$	—
Granted	0.6		$	32.20	—		$	—
Vested	(0.6	)	$	34.55	—		$	—
Cancelled or forfeited	(0.1	)	$	37.82	—		$	—
Acquired	0.1		$	26.24	—		$	—
Outstanding, December 31, 2009	3.9		$	36.40	—		$	—
Granted	2.0		$	45.66	1.1		$	20.49
Vested	(1.1	)	$	32.20	—		$	—
Cancelled or forfeited	(0.4	)	$	35.62	(0.1	)	$	19.22
Outstanding, December 31, 2010	4.4		$	41.69	1.0		$	20.55

(1) Amounts do not include Class B units of Plains AAP, L.P. as discussed below.

(2) Amounts do not include Class B units of PNGS GP LLC as discussed below.

(3) Amounts include PNG Transaction Grants.

Class B Units of Plains AAP, L.P.

In August 2007, the owners of Plains AAP, L.P. authorized the issuance of up to 200,000 “AAP LP Class B Units”. AAP LP Class B units become earned in various increments upon the achievement of PAA distribution levels of between $3.50 and $4.50 (or in some cases, within six months thereof). When earned, the AAP LP Class B unit awards are entitled to participate in distributions paid by Plains AAP, L.P. in excess of $11 million (as adjusted for debt service costs and excluding special distributions funded by debt) per quarter. Assuming all 200,000 AAP LP Class B units were granted and earned, the maximum participation would be 8% of Plains AAP, L.P.’s distribution in excess of $11 million (as adjusted) each quarter. The following table contains a summary of AAP LP Class B unit awards:

	Reserved for Future Grants		Outstanding		Outstanding Units Earned	Grant Date Fair Value Of Outstanding Class B Units (1)
						(in millions)
Balance as of December 31, 2009	34,500		165,500		38,500	$	36
Class B unit issuance	(13,000	)	13,000		—	5
Class B unit forfeitures	3,000		(3,000	)		(1		)
Class B units earned	—		—		41,563	—
Balance as of December 31, 2010	24,500		175,500		80,063	$	40

(1) Of the grant date fair value, approximately $9 million and $5 million was recognized as expense during the years ended December 31, 2010 and 2009, respectively.

Although the entire economic burden of the AAP LP Class B units, which are equity classified, is borne solely by Plains AAP, L.P. and does not impact our cash or units outstanding, the intent of the AAP LP Class B units is to provide a performance incentive and encourage retention for certain members of our senior management. Therefore, we recognize the grant date fair value of the AAP LP Class B units as compensation expense over the service period. The expense is also reflected as a capital contribution and thus, results in a corresponding credit to Partners’ Capital in our Consolidated Financial Statements.

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Class B Units of PNGS GP LLC

During July 2010, the Board of Directors of PNG’s general partner authorized the issuance of 165,000 Class B units of PNGS GP LLC (“PNGS GP LLC Class B units”). Approximately 90,750 PNGS GP LLC Class B units were awarded and the remaining units are reserved for future grants. The PNGS GP LLC Class B units earn the right to participate in distributions (i.e. become “earned”) in 25% increments 180 days following annualized PNG distribution levels of $2.00, $2.30, $2.50 and $2.70. In addition, 50% of the applicable earned units vest immediately upon becoming earned units and the remaining 50% vest on the fifth anniversary of the date of grant. If PNGS GP LLC Class B units become earned units after the fifth anniversary of the date of grant, 100% of such units will vest immediately upon becoming earned units. When earned, the PNGS GP LLC Class B units participate in quarterly distributions paid to PNG’s general partner to the extent such distributions exceed $2.5 million per quarter. Assuming all 165,000 PNGS GP LLC Class B units were granted and earned, the maximum participation rate would be 6% of PNG’s quarterly general partner distribution in excess of $2.5 million. As the PNG distribution levels required for vesting are not currently considered to be probable of occurring, no expense was recognized for the PNGS GP LLC Class B Units during the year ended December 31, 2010.

Other Consolidated Equity Compensation Information

We refer to our LTIP Plans, PNG Transaction Grants, AAP LP Class B units and PNGS GP LLC Class B units collectively as “Equity compensation plans.” The table below summarizes the expense recognized and the value of vesting (settled both in units and cash) related to our equity compensation plans (in millions):

	2010		2009		2008
Equity compensation expense	$	98	$	68	$	24
LTIP unit settled vestings (1)	$	26	$	19	$	1
LTIP cash settled vestings	$	36	$	8	$	2
DER cash payments	$	4	$	4	$	4

(1) All unit vestings were settled with PAA units.

Approximately 0.5 million, 0.5 million and 0.1 million PAA units were issued net of tax withholding in 2010, 2009 and 2008 respectively, in connection with the settlement of vested awards. The remaining 0.6 million and 0.1 million of awards that vested during 2010 and 2009 respectively, were settled in cash. Based on the December 31, 2010 fair value measurement and probability assessment regarding future distributions, we expect to recognize approximately $84 million of additional expense over the life of our outstanding awards related to the remaining unrecognized fair value. Actual amounts may differ materially as a result of a change in the market price of our units and/or probability assessments regarding future distributions. We estimate that the remaining fair value will be recognized in expense as shown below (in millions):

	Equity Compensation
	Plan Fair Value
Year	Amortization (1) (2)
2011	$	46
2012	28
2013	7
2014	2
2015	1
Total	$	84

(1) Amounts do not include fair value associated with awards containing performance conditions that are not considered to be probable of occurring at December 31, 2010.

(2) Includes unamortized fair value associated with AAP LP Class B units, PNGS GP LLC Class B units and PNG Transaction Grants.

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Note 11—Commitments and Contingencies

Commitments

We lease certain real property, equipment and operating facilities under various operating and capital leases. We also incur costs associated with leased land, rights-of-way, permits and regulatory fees, the contracts for which generally extend beyond one year but can be cancelled at any time should they not be required for operations. Future non-cancelable commitments related to these items at December 31, 2010, are summarized below (in millions):

2011	$		77
2012	62
2013	40
2014	27
2015	20
Thereafter	277
Total	$	503

Expenditures related to leases for 2010, 2009 and 2008 were $97 million, $90 million and $82 million, respectively.

Litigation

SemCrude L.P., et al — Debtors/Samson Resources Company (U.S. Bankruptcy Court — Delaware). We will from time to time have claims relating to insolvent suppliers, customers or counterparties, such as the bankruptcy proceedings of SemCrude, which commenced in July 2008. Statutory protections and our contractual rights of setoff covered substantially all of our pre-petition claims against SemCrude and such claims have now been resolved. In separate actions certain creditors of SemCrude, led by Samson Resources Company, have also filed state court actions alleging a producer’s lien on crude oil sold to SemCrude and its affiliates, and the continuation of such lien when SemCrude and its affiliates subsequently sold the oil to purchasers such as us. On May 29, 2009, we filed a complaint for declaratory relief to resolve these claims. Fourteen state court actions have been consolidated in Bankruptcy Court. One action is in Federal Court in New Mexico. We intend to vigorously defend our contractual and statutory rights.

ExxonMobil Corp. v. GATX Corp. (Superior Court of New Jersey — Gloucester County). This Pacific legacy matter was filed by ExxonMobil in April 2003 and involves the allocation of responsibility for remediation of MTBE and other petroleum product contamination at our terminal facility in Paulsboro, New Jersey, which we acquired in the Pacific merger. We estimate that the cost to effectively remediate will be approximately $3.5 million, which amount may be higher or lower depending on the nature and extent of the cleanup. Both ExxonMobil and GATX were prior owners of the terminal. We contend that ExxonMobil and/or GATX are primarily responsible for the majority of the remediation costs. We are in dispute with Kinder Morgan (as successor in interest to GATX) regarding the indemnity by GATX in favor of Pacific in connection with Pacific’s purchase of the facility. We are vigorously defending against any claim that PPT is directly or indirectly liable for damages or costs associated with the MTBE contamination.

New Jersey Department of Environmental Protection v. ExxonMobil Corp. et al. In a matter related to ExxonMobil v. GATX, in June 2007, the NJDEP brought suit against GATX, ExxonMobil and Plains Products Terminals LLC (formerly Pacific Atlantic Terminals LLC) to recover natural resources damages associated with, and to require remediation of, the contamination. ExxonMobil and GATX have filed third-party demands against PPT, seeking indemnity and contribution. The

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natural resources damages have been settled and set at $1.1 million payable to the State of New Jersey; however, PPT’s allocated share of this liability is being disputed by PPT with GATX. Court approval of the settlement is pending.

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 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.

Environmental

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Insurance

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. With respect to all of our coverage, we may not be able to maintain adequate insurance in the future at rates we consider reasonable. As a result, we may elect to self-insure or utilize higher deductibles in certain insurance programs. In addition, although we believe that we have established adequate reserves to the extent that 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.

Note 12—Environmental Remediation

We currently own or lease, and in the past have owned and 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).

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 TNM pipeline assets from 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 SOP. As of December 31, 2010, we had incurred approximately $19 million of remediation costs associated with these sites, while SOP’s share has been approximately $8 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. See Note 11 for further environmental discussion.

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Note 13—Supplemental Condensed Consolidating Financial Information

Some but not all of our 100% owned subsidiaries have issued full, unconditional and joint and several guarantees of our Senior Notes. Given that certain, but not all, subsidiaries are guarantors of our Senior Notes, we are required to present the following supplemental condensed consolidating financial information. For purposes of the following footnote:

· we are referred to as “Parent;”

· the “Guarantor Subsidiaries” are all subsidiaries other than the Non-Guarantor Subsidiaries defined below; and

· The “Non-Guarantor Subsidiaries” as of December 31, 2010 include two California Public Utilities Commission regulated entities, our natural gas storage subsidiaries and other minor subsidiaries.

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The following supplemental condensed consolidating financial information reflects the Parent’s separate accounts, the combined accounts of the Guarantor Subsidiaries, the combined accounts of the Non-Guarantor Subsidiaries, the combined consolidating adjustments and eliminations and the Parent’s consolidated accounts for the dates and periods indicated. For purposes of the following condensed consolidating information, the Parent’s investments in its subsidiaries and the Guarantor Subsidiaries’ investments in their subsidiaries are accounted for under the equity method of accounting (in millions):

Condensed Consolidating Balance Sheets

	As of December 31, 2010
	Parent			Combined Guarantor Subsidiaries				Combined Non-Guarantor Subsidiaries				Eliminations							Consolidated
ASSETS
Total current assets	$	3,460		$		4,394		$		510		$		(3,983			)		$		4,381
Property and equipment, net	2			4,870				1,819				—							6,691
Investments in unconsolidated entities	6,302			2,173				—				(8,275					)		200
Other assets, net	28			1,976				553				(126					)		2,431
Total assets	$	9,792		$		13,413		$		2,882		$		(12,384			)		$		13,703

LIABILITIES AND PARTNERS’ CAPITAL
Total current liabilities	$	853		$		6,836		$		509		$		(3,983			)		$		4,215
Long-term debt	4,366			5				386				(126					)		4,631
Other long-term liabilities	—			270				14				—							284
Total liabilities	5,219			7,111				909				(4,109					)		9,130

Partners’ capital excluding noncontrolling interests	4,342			6,241				1,973				(8,214					)		4,342
Noncontrolling interests	231			61				—				(61					)		231
Total partners’ capital	4,573			6,302				1,973				(8,275					)		4,573

Total liabilities and partners’ capital	$	9,792		$		13,413		$		2,882		$		(12,384			)		$		13,703

	As of December 31, 2009
	Parent				Combined Guarantor Subsidiaries				Combined Non-Guarantor Subsidiaries				Eliminations					Consolidated
ASSETS
Total current assets	$		3,428		$		3,831		$		209		$		(3,810	)		$		3,658
Property and equipment, net	—				4,606				1,734				—					6,340
Investments in unconsolidated entities	5,295				1,652				—				(6,865			)		82
Other assets, net	29				2,342				367				(460			)		2,278
Total assets	$		8,752		$		12,431		$		2,310		$		(11,135	)		$		12,358

LIABILITIES AND PARTNERS’ CAPITAL
Total current liabilities	$		456		$		6,849		$		287		$		(3,810	)		$		3,782
Long-term debt	4,137				15				450				(460			)		4,142
Other long-term liabilities	—				271				4				—					275
Total liabilities	4,593				7,135				741				(4,270			)		8,199

Partners’ capital excluding noncontrolling interest	4,096				5,233				1,569				(6,802			)		4,096
Noncontrolling interest	63				63				—				(63			)		63
Total partners’ capital	4,159				5,296				1,569				(6,865			)		4,159

Total liabilities and partners’ capital	$		8,752		$		12,431		$		2,310		$		(11,135	)		$		12,358

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Condensed Consolidating Statements of Operations

	Year Ended December 31, 2010
	Parent			Combined Guarantor Subsidiaries			Combined Non-Guarantor Subsidiaries			Eliminations			Consolidated
Net operating revenues (1)	$	—		$	1,749		$	223		$	—		$	1,972
Field operating costs	—			(632		)	(57		)	—			(689		)
General and administrative expenses	—			(230		)	(30		)	—			(260		)
Depreciation and amortization	(4		)	(207		)	(45		)	—			(256		)

Operating income/(loss)	(4		)	680			91			—			767

Equity earnings in unconsolidated entities	778			86			—			(861		)	3
Interest income/(expense)	(254		)	13			(7		)	—			(248		)
Other income/(expense), net	(6		)	(3		)	—			—			(9		)
Income tax benefit	—			1			—			—			1
Net income	514			777			84			(861		)	514
Less: Net income attributable to noncontrolling interests	(9		)	(2		)	—			2			(9		)
Net income attributable to Plains	$	505		$	775		$	84		$	(859	)	$	505

	Year Ended December 31, 2009
	Parent			Combined Guarantor Subsidiaries			Combined Non-Guarantor Subsidiaries			Eliminations			Consolidated
Net operating revenues (1)	$	—		$	1,707		$	157		$	—		$	1,864
Field operating costs	—			(589		)	(49		)	—			(638		)
General and administrative expenses	—			(196		)	(15		)	—			(211		)
Depreciation and amortization	(4		)	(200		)	(32		)	—			(236		)

Operating income/(loss)	(4		)	722			61			—			779

Equity earnings in unconsolidated entities	822			64			—			(871		)	15
Interest income/(expense)	(234		)	14			(4		)	—			(224		)
Other income, net	(4		)	20			—			—			16
Income tax expense	—			(6		)	—			—			(6		)
Net income		580			814			57			(871	)	$	580
Less: Net income attributable to noncontrolling interest	(1		)	(1		)	—			1			(1		)
Net income attributable to Plains	$	579		$	813		$	57		$	(870	)	$	579

	Year Ended December 31, 2008
	Parent			Combined Guarantor Subsidiaries			Combined Non-Guarantor Subsidiaries			Eliminations			Consolidated
Net operating revenues (1)	$	—		$	1,469		$	113		$	—		$	1,582
Field operating costs	—			(575		)	(42		)	—			(617		)
General and administrative expenses	—			(149		)	(11		)	—			(160		)
Depreciation and amortization	(3		)	(187		)	(21		)	—			(211		)

Operating income/(loss)	(3		)	558			39			—			594

Equity earnings in unconsolidated entities	629			45			—			(660		)	14
Interest expense	(195		)	(1		)	—			—			(196		)
Other income, net	6			26			1			—			33
Income tax expense	—			(8		)	—			—			(8		)
Net income	$	437		$	620		$	40		$	(660	)	$	437

(1) Net operating revenues are calculated as “Total revenues” less “Purchases and related costs.”

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Condensed Consolidating Statements of Cash Flows

	Year Ended December 31, 2010
				Combined			Combined
				Guarantor			Non-Guarantor
	Parent			Subsidiaries			Subsidiaries			Eliminations			Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	514		$	777		$	84		$	(861	)	$	514
Reconciliation of net income to net cash provided by/(used in) operating activities:
Depreciation and amortization	4			207			45			—			256
Equity compensation expense	—			95			3			—			98
Gain on sale of linefill	—			(21		)	—			—			(21		)
Equity earnings in unconsolidated entities, net of distributions	(778		)	(77		)	—			861			6
Other	8			3			—			—			11
Changes in assets and liabilities, net of acquisitions	(250		)	(610		)	255			—			(605		)

Net cash provided by/(used in) operating activities	(502		)	374			387			—			259

CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid in connection with acquisitions, net of cash acquired	(20		)	(242		)	(145		)	—			(407		)
Restricted cash in escrow for acquisitions	—			—			(20		)	—			(20		)
Additions to property, equipment and other	—			(323		)	(128		)	—			(451		)
Cash received for sale of noncontrolling interest in a subsidiary	268			—			—			—			268
Net cash received/(paid) for sales and purchases of linefill and base gas	—			35			(10		)	—			25
Proceeds from sales of assets and other investing activities	—			2			—			—			2
Net cash provided by/(used in) investing activities	248			(528		)	(303		)	—			(583		)

CASH FLOWS FROM FINANCING ACTIVITIES
Net borrowings/(repayments) on Plains revolving credit facility	412			(363		)	—			—			49
Net borrowings on PNG revolving credit facility	—			—			260			—			260
Net borrowings on short-term letter of credit and hedged inventory facility	—			200			—			—			200
Net borrowings/(repayments) on intercompany notes	—			332			(332		)	—			—
Proceeds from issuance of senior notes	400			—			—			—			400
Net proceeds from the issuance of common units	296			—			—			—			296
Repayments of senior notes	(175		)	—			—			—			(175		)
Distributions paid to common unitholders and general partner	(682		)	—			—			—			(682		)
Distributions paid to noncontrolling interests	—			—			(10		)	—			(10		)
Other financing activities	(2		)	3			(3		)	—			(2		)
Net cash provided by/(used in) financing activities	249			172			(85		)	—			336

Effect of translation adjustment on cash	—			(1		)	—			—			(1		)
Net increase/(decrease) in cash and cash equivalents	(5		)	17			(1		)	—			11
Cash and cash equivalents, beginning of period	1			19			5			—			25
Cash and cash equivalents, end of period	$	(4	)	$	36		$	4		$	—		$	36

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	Year Ended December 31, 2009
				Combined			Combined
				Guarantor			Non-Guarantor
	Parent			Subsidiaries			Subsidiaries			Eliminations			Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	580		$	814		$	57		$	(871	)	$	580
Reconciliation of net income to net cash provided by/(used in) operating activities:
Depreciation and amortization	4			200			32			—			236
Equity compensation expense	—			67			1			—			68
Equity earnings in unconsolidated entities, net of distributions	(818		)	(61		)	—			871			(8		)
Other	—			(50		)	—			—			(50		)
Changes in assets and liabilities, net of acquisitions	(616		)	155			—			—			(461		)

Net cash provided by/(used in) operating activities	(850		)	1,125			90			—			365

CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid in connection with acquisitions, net of cash acquired	—			(219		)	—			—			(219		)
Additions to property, equipment and other	—			(387		)	(73		)	—			(460		)
Investment in unconsolidated entities	(4		)	—			—			—			(4		)
Cash received for sale of noncontrolling interest in a subsidiary	—			26			—			—			26
Net cash paid for linefill in assets owned	—			(9		)	—			—			(9		)
Proceeds from sales of assets and other	—			6			—			—			6
Net cash used in investing activities	(4		)	(583		)	(73		)	—			(660		)

CASH FLOWS FROM FINANCING ACTIVITIES
Net borrowings/(repayments) on revolving credit facility	95			(114		)	—			—			(19		)
Net borrowings on short-term letter of credit and hedged inventory facility	—			20			—			—			20
Repayment of PNGS debt	—			(446		)	—			—			(446		)
Net borrowings/(repayments) on intercompany notes	—			10			(10		)	—			—
Proceeds from issuance of senior notes	1,346			—			—			—			1,346
Repayments of senior notes	(430		)	—			—			—			(430		)
Net proceeds from the issuance of common units	458			—			—			—			458
Distributions paid to common unitholders and general partner	(605		)	—			—			—			(605		)
Other financing activities	(11		)	1			(2		)	—			(12		)
Net cash provided by/(used in) financing activities	853			(529		)	(12		)	—			312

Effect of translation adjustment on cash	—			(3		)	—			—			(3		)
Net increase/(decrease) in cash and cash equivalents	(1		)	10			5			—			14
Cash and cash equivalents, beginning of period	2			9			—			—			11
Cash and cash equivalents, end of period	$	1		$	19		$	5		$	—		$	25

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	Year Ended December 31, 2008
				Combined			Combined
				Guarantor			Non-Guarantor
	Parent			Subsidiaries			Subsidiaries			Eliminations			Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	437		$	620		$	40		$	(660	)	$	437
Reconciliation of net income to net cash provided by/(used in) operating activities:
Depreciation and amortization	3			187			21			—			211
Inventory valuation adjustment	—			168			—			—			168
Equity compensation expense	—			24			—			—			24
Gain on foreign currency revaluation	—			22			—			—			22
Equity earnings in unconsolidated entities, net of distributions	(622		)	(42		)	—			660			(4		)
Deferred income tax benefit	—			(1		)	—			—			(1		)
Other	17			(15		)	—			—			2
Changes in assets and liabilities, net of acquisitions	(375		)	389			(16		)	—			(2		)

Net cash provided by/(used in) operating activities	(540		)	1,352			45			—			857

CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid in connection with acquisitions, net of cash acquired	—			(709		)	—			—			(709		)
Additions to property, equipment and other	—			(544		)	(45		)	—			(589		)
Investment in unconsolidated entities	(37		)	—			—			—			(37		)
Net cash paid for linefill in assets owned	—			(55		)	—			—			(55		)
Proceeds from sales of assets and other	—			51			—			—			51
Net cash used in investing activities	(37		)	(1,257		)	(45		)	—			(1,339		)

CASH FLOWS FROM FINANCING ACTIVITIES
Net borrowings on revolving credit facility	204			82			—			—			286
Net repayments on short-term letter of credit and hedged inventory facility	—			(196		)	—			—			(196		)
Proceeds from issuance of senior notes	597			—			—			—			597
Net proceeds from the issuance of common units	315			—			—			—			315
Distributions paid to common unitholders and general partner	(532		)	—			—			—			(532		)
Other financing activities	(6		)	—			—			—			(6		)
Net cash provided by/(used in) financing activities	578			(114		)	—			—			464

Effect of translation adjustment on cash	—			5			—			—			5
Net increase/(decrease) in cash and cash equivalents	1			(14		)	—			—			(13		)
Cash and cash equivalents, beginning of period	1			23			—			—			24
Cash and cash equivalents, end of period	$	2		$	9		$	—		$	—		$	11

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Note 14—Quarterly Financial Data (Unaudited)

	First		Second		Third		Fourth
	Quarter		Quarter		Quarter		Quarter		Total (1)
	(in millions, except per unit data)
2010
Revenues	$	6,125	$	6,124	$	6,414	$	7,231	$	25,893
Gross margin (2)	$	273	$	248	$	206	$	300	$	1,027
Operating income	$	211	$	192	$	150	$	213	$	767
Net income	$	151	$	133	$	84	$	146	$	514
Net income attributable to Plains	$	151	$	131	$	81	$	142	$	505
Basic net income per limited partner unit	$	0.80	$	0.65	$	0.28	$	0.68	$	2.41
Diluted net income per limited partner unit	$	0.80	$	0.65	$	0.28	$	0.67	$	2.40
Cash distributions per common unit (3)	$	0.9275	$	0.9350	$	0.9425	$	0.9500	$	3.76

2009
Revenues	$	3,302	$	4,282	$	4,857	$	6,078	$	18,520
Gross margin (2)	$	302	$	237	$	218	$	231	$	990
Operating income	$	256	$	183	$	166	$	173	$	779
Net income	$	211	$	136	$	122	$	110	$	580
Net income attributable to Plains	$	211	$	136	$	122	$	110	$	579
Basic net income per limited partner unit	$	1.42	$	0.79	$	0.65	$	0.53	$	3.34
Diluted net income per limited partner unit	$	1.41	$	0.78	$	0.65	$	0.52	$	3.32
Cash distributions per common unit (3)	$	0.8925	$	0.9050	$	0.9050	$	0.9200	$	3.62

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

(2) Gross margin is calculated as Total revenues less (i) Purchases and related costs, (ii) Field operating costs and (iii) Depreciation and amortization.

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

Note 15—Operating Segments

We manage our operations through three operating segments: (i) Transportation, (ii) Facilities and (iii) Supply and Logistics. See “Revenue Recognition” within Note 2 for a summary of the types of products and services from which each segment derives its revenues.

Our Chief Operating Decision Maker (our Chief Executive Officer) evaluates segment performance based on a variety of measures including segment profit, segment volumes, segment profit per barrel and maintenance capital investment. We define segment profit as revenues and equity earnings in unconsolidated entities less (i) purchases and related costs, (ii) field operating costs and (iii) segment general and administrative (“G&A”) expenses. Each of the items above excludes depreciation and amortization. As an MLP, we make quarterly distributions of our “available cash” (as defined in our partnership agreement) to our unitholders. We look at each period’s earnings before non-cash depreciation and amortization as an important measure of segment performance. The exclusion of depreciation and amortization expense could be viewed as limiting the usefulness of segment profit as a performance measure because it does not account in current periods for the implied reduction in value of our capital assets, such as crude oil pipelines and facilities, caused by aging and wear and tear. We compensate for this limitation by recognizing that depreciation and amortization are largely offset by repair and maintenance investments, which acts to partially offset the wear and tear and age-related decline in the value of our principal fixed assets. These maintenance investments are a component of field operating costs included in segment profit or in maintenance capital, depending on the nature of the cost. Maintenance capital, which is deducted in determining “available cash,” consists of capital expenditures for the replacement of partially or fully depreciated assets in order to maintain the service capability, level of production and/or functionality of our existing assets. Capital expenditures made to expand the existing earnings capacity of our assets are considered expansion capital expenditures, not maintenance capital. Repair and maintenance expenditures incurred in order to maintain the day to day operation of our existing assets are charged to expense as incurred. The following table reflects certain financial data for each segment for the periods indicated (in millions):

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	Transportation		Facilities		Supply & Logistics		Total
Twelve Months Ended December 31, 2010
Revenues:
External Customers	$	565	$	339	$	24,989	$	25,893
Intersegment (1)	480		151		1		632
Total revenues of reportable segments	$	1,045	$	490	$	24,990	$	26,525
Equity earnings in unconsolidated entities	$	3	$	—	$	—	$	3
Segment profit (2) (3)	$	516	$	270	$	240	$	1,026
Capital expenditures	$	329	$	270	$	163	$	762
Total assets	$	4,701	$	3,303	$	5,699	$	13,703
Maintenance capital	$	67	$	17	$	9	$	93

Twelve Months Ended December 31, 2009
Revenues:
External Customers	$	536	$	227	$	17,757	$	18,520
Intersegment (1)	425		135		2		562
Total revenues of reportable segments	$	961	$	362	$	17,759	$	19,082
Equity earnings in unconsolidated entities	$	7	$	8	$	—	$	15
Segment profit (2) (3)	$	477	$	208	$	345	$	1,030
Capital expenditures	$	183	$	564	$	10	$	757
Total assets	$	4,468	$	3,097	$	4,793	$	12,358
Maintenance capital	$	57	$	16	$	8	$	81

Twelve Months Ended December 31, 2008
Revenues:
External Customers	$	556	$	157	$	29,348	$	30,061
Intersegment (1)	371		113		2		486
Total revenues of reportable segments	$	927	$	270	$	29,350	$	30,547
Equity earnings in unconsolidated entities	$	5	$	9	$	—	$	14
Segment profit (2) (3)	$	445	$	153	$	221	$	819
Capital expenditures	$	935	$	265	$	26	$	1,226
Total assets	$	3,930	$	2,048	$	4,054	$	10,032
Maintenance capital	$	54	$	23	$	4	$	81

(1) Segment revenues and purchases and related costs include intersegment amounts. Intersegment sales are conducted at posted tariff rates, rates similar to those charged to third parties or rates that we believe approximate market rates.

(2) Supply and logistics segment profit includes interest expense (related to hedged inventory purchases) of $17 million, $11 million and $21 million for the years ended December 31, 2010, 2009 and 2008, respectively.

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(3) The following table reconciles segment profit to net income attributable to Plains (in millions):

	Year Ended December 31,
	2010			2009			2008
Segment profit	$	1,026		$	1,030		$	819
Depreciation and amortization	(256		)	(236		)	(211		)
Interest expense	(248		)	(224		)	(196		)
Other income/(expense), net	(9		)	16			33
Income tax benefit/(expense)	1			(6		)	(8		)

Net income	514			580			437
Less: Net income attributable to noncontrolling interests	(9		)	(1		)	—
Net income attributable to Plains	$	505		$	579		$	437

Geographic Data

We have operations in the United States and Canada. Set forth below are revenues and long-lived assets attributable to these geographic areas (in millions):

	For the Year Ended December 31,
Revenues (1)	2010		2009		2008
United States	$	21,471	$	15,439	$	25,183
Canada	4,422		3,081		4,878
	$	25,893	$	18,520	$	30,061

(1) Revenues are attributed to each region based on where the customers are located.

	As of December 31,
Long-Lived Assets (1)	2010		2009
United States	$	7,502	$	6,945
Canada	1,800		1,678
	$	9,302	$	8,623

(1) Excludes long-term derivative assets.

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EXHIBIT INDEX

3.1		—	Third Amended and Restated Agreement of Limited Partnership of Plains All American Pipeline, L.P. dated as of June 27, 2001 (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed August 27, 2001).

3.2		—	Amendment No. 1 dated April 15, 2004 to the Third Amended and Restated Agreement of Limited Partnership of Plains All American Pipeline, L.P. (incorporated by reference to Exhibit 3.1 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2004).

3.3		—	Amendment No. 2 dated November 15, 2006 to Third Amended and Restated Agreement of Limited Partnership of Plains All American Pipeline, L.P. (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed November 21, 2006).

3.4		—	Amendment No. 3 dated August 16, 2007 to Third Amended and Restated Agreement of Limited Partnership of Plains All American Pipeline, L.P. (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed August 22, 2007).

3.5		—	Amendment No. 4 effective as of January 1, 2007 to Third Amended and Restated Agreement of Limited Partnership of Plains All American Pipeline, L.P. (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed April 15, 2008).

3.6		—	Amendment No. 5 dated May 28, 2008 to Third Amended and Restated Agreement of Limited Partnership of Plains All American Pipeline, L.P. (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed May 30, 2008).

3.7		—	Amendment No. 6 dated September 3, 2009 to Third Amended and Restated Agreement of Limited Partnership of Plains All American Pipeline, L.P. (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed September 3, 2009).

3.8		—	Third Amended and Restated Agreement of Limited Partnership of Plains Marketing, L.P. dated as of April 1, 2004 (incorporated by reference to Exhibit 3.2 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2004).

3.9	†	—	Amendment No. 1 dated December 31, 2010 to the Third Amended and Restated Agreement of Limited Partnership of Plains Marketing, L.P.

3.10	†	—	Amendment No. 2 dated January 1, 2011 to the Third Amended and Restated Agreement of Limited Partnership of Plains Marketing, L.P.

3.11		—	Third Amended and Restated Agreement of Limited Partnership of Plains Pipeline, L.P. dated as of April 1, 2004 (incorporated by reference to Exhibit 3.3 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2004).

3.12		—	Fifth Amended and Restated Limited Liability Company Agreement of Plains All American GP LLC dated December 23, 2010 (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed December 30, 2010).

3.13		—	Sixth Amended and Restated Limited Partnership Agreement of Plains AAP, L.P. dated December 23, 2010 (incorporated by reference to Exhibit 3.2 to the Current Report on Form 8-K filed December 30, 2010).

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3.14	—	Certificate of Incorporation of PAA Finance Corp (f/k/a Pacific Energy Finance Corporation, successor-by-merger to PAA Finance Corp.) (incorporated by reference to Exhibit 3.10 to the Annual Report on Form 10-K for the year ended December 31, 2006).

3.15	—	Bylaws of PAA Finance Corp (f/k/a Pacific Energy Finance Corporation, successor-by-merger to PAA Finance Corp.) (incorporated by reference to Exhibit 3.11 to the Annual Report on Form 10-K for the year ended December 31, 2006).

3.16	—	Limited Liability Company Agreement of PAA GP LLC dated December 28, 2007 (incorporated by reference to Exhibit 3.3 to the Current Report on Form 8-K filed January 4, 2008).

4.1	—	Indenture dated September 25, 2002 among Plains All American Pipeline, L.P., PAA Finance Corp. and Wachovia Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2002).

4.2	—	First Supplemental Indenture (Series A and Series B 7.75% Senior Notes due 2012) dated as of September 25, 2002 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and Wachovia Bank, National Association, as trustee (incorporated by reference to Exhibit 4.2 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2002).

4.3	—	Second Supplemental Indenture (Series A and Series B 5.625% Senior Notes due 2013) dated as of December 10, 2003 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and Wachovia Bank, National Association, as trustee (incorporated by reference to Exhibit 4.4 to the Annual Report on Form 10-K for the year ended December 31, 2003).

4.4	—	Fourth Supplemental Indenture (Series A and Series B 5.875% Senior Notes due 2016) dated August 12, 2004 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and Wachovia Bank, National Association, as trustee (incorporated by reference to Exhibit 4.5 to the Registration Statement on Form S-4, File No. 333-121168).

4.5	—	Fifth Supplemental Indenture (Series A and Series B 5.25% Senior Notes due 2015) dated May 27, 2005 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and Wachovia Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed May 31, 2005).

4.6	—	Sixth Supplemental Indenture (Series A and Series B 6.70% Senior Notes due 2036) dated May 12, 2006 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and Wachovia Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed May 12, 2006).

4.7	—	Seventh Supplemental Indenture dated May 12, 2006 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and Wachovia Bank, National Association, as trustee (incorporated by reference to Exhibit 4.3 to the Current Report on Form 8-K filed May 12, 2006).

4.8	—	Eighth Supplemental Indenture dated August 25, 2006 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and Wachovia Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed August 25, 2006).

4.9	—	Ninth Supplemental Indenture (Series A and Series B 6.125% Senior Notes due 2017) dated October 30, 2006 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed October 30, 2006).

4.10	—	Tenth Supplemental Indenture (Series A and Series B 6.650% Senior Notes due 2037) dated October 30, 2006 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to

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		Exhibit 4.2 to the Current Report on Form 8-K filed October 30, 2006).

4.11	—	Eleventh Supplemental Indenture dated November 15, 2006 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed November 21, 2006).

4.12	—	Twelfth Supplemental Indenture dated January 1, 2008 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.21 to the Annual Report on Form 10-K for the year ended December 31, 2007).

4.13	—	Thirteenth Supplemental Indenture (Series A and Series B 6.5% Senior Notes due 2018) dated April 23, 2008 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed April 23, 2008).

4.14	—	Fourteenth Supplemental Indenture dated July 1, 2008 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.15 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2008).

4.15	—	Fifteenth Supplemental Indenture (8.75% Senior Notes due 2019) dated April 20, 2009 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed April 20, 2009).

4.16	—	Sixteenth Supplemental Indenture (4.25% Senior Notes due 2012) dated July 23, 2009 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed July 23, 2009).

4.17	—	Seventeenth Supplemental Indenture (5.75% Senior Notes due 2020) dated September 4, 2009 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed September 4, 2009).

4.18	—	Eighteenth Supplemental Indenture (3.95% Senior Notes due 2015) dated July 14, 2010 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed July 13, 2010).

4.19	—	Nineteenth Supplemental Indenture (5.00% Senior Notes due 2021) dated January 14, 2011 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed January 11, 2011).

4.20	—	Registration Rights Agreement dated September 3, 2009 by and between Plains All American Pipeline, L.P. and Vulcan Gas Storage LLC (incorporated by reference to Exhibit 4.1 to the Registration Statement on Form S-3, File No. 333-162477).

10.1	—	Second Amended and Restated Credit Agreement dated as of July 31, 2006 by and among Plains All American Pipeline, L.P., as US Borrower; PMC (Nova Scotia) Company and Plains Marketing Canada, L.P., as Canadian Borrowers; Bank of America, N.A., as Administrative Agent; Bank of America, N.A., acting through its Canada Branch, as Canadian Administrative Agent; Wachovia Bank, National Association and J. P. Morgan Chase Bank, N.A., as Co-Syndication Agents; Fortis Capital Corp., Citibank, N.A., BNP Paribas, UBS Securities LLC, SunTrust Bank, and The Bank of Nova Scotia, as Co-Documentation Agents; the Lenders party thereto; and Banc of America Securities LLC

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			and Wachovia Capital Markets, LLC, as Joint Lead Arrangers and Joint Book Managers (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed August 4, 2006).

10.2		—	Amended and Restated Crude Oil Marketing Agreement dated as of July 23, 2004, among Plains Resources Inc., Calumet Florida Inc. and Plains Marketing, L.P. (incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2004).

10.3		—	Amended and Restated Omnibus Agreement dated as of July 23, 2004, among Plains Resources Inc., Plains All American Pipeline, L.P., Plains Marketing, L.P., Plains Pipeline, L.P. and Plains All American GP LLC (incorporated by reference to Exhibit 10.3 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2004).

10.4		—	Contribution, Assignment and Amendment Agreement dated as of June 27, 2001, among Plains All American Pipeline, L.P., Plains Marketing, L.P., All American Pipeline, L.P., Plains AAP, L.P., Plains All American GP LLC and Plains Marketing GP Inc. (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed June 27, 2001).

10.5		—	Contribution, Assignment and Amendment Agreement dated as of June 8, 2001, among Plains All American Inc., Plains AAP, L.P. and Plains All American GP LLC (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed June 11, 2001).

10.6		—	Separation Agreement dated as of June 8, 2001 among Plains Resources Inc., Plains All American Inc., Plains All American GP LLC, Plains AAP, L.P. and Plains All American Pipeline, L.P. (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed June 11, 2001).

10.7	**	—	Pension and Employee Benefits Assumption and Transition Agreement dated as of June 8, 2001 among Plains Resources Inc., Plains All American Inc. and Plains All American GP LLC (incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K filed June 11, 2001).

10.8	**	—	Plains All American GP LLC 2005 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed January 26, 2005).

10.9	**	—	Plains All American GP LLC 1998 Long-Term Incentive Plan (incorporated by reference to Exhibit 99.1 to Registration Statement on Form S-8, File No. 333-74920) as amended June 27, 2003 (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2003).

10.10	**	—	Plains All American 2001 Performance Option Plan (incorporated by reference to Exhibit 99.2 to the Registration Statement on Form S-8 filed December 11, 2001, File No. 333-74920).

10.11	**	—	Amended and Restated Employment Agreement between Plains All American GP LLC and Greg L. Armstrong dated as of June 30, 2001 (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2001).

10.12	**	—	Amended and Restated Employment Agreement between Plains All American GP LLC and Harry N. Pefanis dated as of June 30, 2001 (incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2001).

10.13		—	Asset Purchase and Sale Agreement dated February 28, 2001 between Murphy Oil Company Ltd. and Plains Marketing Canada, L.P. (incorporated by reference to Exhibit 99.1 to the Current Report on Form 8-K filed May 10, 2001).

10.14		—	Transportation Agreement dated July 30, 1993, between All American Pipeline Company and Exxon Company, U.S.A. (incorporated by reference to Exhibit 10.9 to the Registration Statement on Form S-1 filed September 23, 1998, File No. 333-64107).

10.15		—	Transportation Agreement dated August 2, 1993, among All American Pipeline Company, Texaco Trading and Transportation Inc., Chevron U.S.A. and Sun Operating Limited Partnership (incorporated by reference to Exhibit 10.10 to the Registration Statement on Form S-1 filed September 23, 1998, File

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			No. 333-64107).

10.16		—	First Amendment to Contribution, Conveyance and Assumption Agreement dated as of December 15, 1998 (incorporated by reference to Exhibit 10.13 to the Annual Report on Form 10-K for the year ended December 31, 1998).

10.17		—	Agreement for Purchase and Sale of Membership Interest in Scurlock Permian LLC between Marathon Ashland LLC and Plains Marketing, L.P. dated as of March 17, 1999 (incorporated by reference to Exhibit 10.16 to the Annual Report on Form 10-K for the year ended December 31, 1998).

10.18	**	—	Plains All American Inc. 1998 Management Incentive Plan (incorporated by reference to Exhibit 10.5 to the Annual Report on Form 10-K for the year ended December 31, 1998).

10.19	**	—	PMC (Nova Scotia) Company Bonus Program (incorporated by reference to Exhibit 10.20 to the Annual Report on Form 10-K for the year ended December 31, 2004).

10.20	**	—	Quarterly Bonus Program Summary (incorporated by reference to Exhibit 10.21 to the Annual Report on Form 10-K for the year ended December 31, 2005).

10.21	**†	—	Directors’ Compensation Summary.

10.22		—	Master Railcar Leasing Agreement dated as of May 25, 1998 (effective June 1, 1998), between Pivotal Enterprises Corporation and CANPET Energy Group, Inc., (incorporated by reference to Exhibit 10.16 to the Annual Report on Form 10-K for the year ended December 31, 2001).

10.23	**	—	Form of LTIP Grant Letter (Armstrong/Pefanis) (incorporated by reference to Exhibit 10.24 to the Annual Report on Form 10-K for the year ended December 31, 2005).

10.24	**	—	Form of LTIP Grant Letter (executive officers) (incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K filed April 1, 2005).

10.25	**	—	Form of LTIP Grant Letter (independent directors) (incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K filed February 23, 2005).

10.26	**	—	Form of LTIP Grant Letter (designated directors) (incorporated by reference to Exhibit 10.4 to the Current Report on Form 8-K filed February 23, 2005).

10.27	**	—	Form of LTIP Grant Letter (payment to entity) (incorporated by reference to Exhibit 10.5 to the Current Report on Form 8-K filed February 23, 2005).

10.28	**	—	Form of Performance Option Grant Letter (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed April 1, 2005).

10.29		—	Administrative Services Agreement between Plains All American GP LLC and Vulcan Energy Corporation dated October 14, 2005 (incorporated by reference to Exhibit 1.1 to the Current Report on Form 8-K filed October 19, 2005).

10.30		—	Membership Interest Purchase Agreement by and between Sempra Energy Trading Corp. and PAA/Vulcan Gas Storage, LLC dated August 19, 2005 (incorporated by reference to Exhibit 1.2 to the Current Report on Form 8-K filed September 19, 2005).

10.31	**†	—	Waiver Agreement dated as of December 23, 2010 between Plains All American GP LLC and Greg L. Armstrong.

10.32	**†	—	Waiver Agreement dated as of December 23, 2010 between Plains All American GP LLC and Harry N. Pefanis.

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10.33		—	Excess Voting Rights Agreement dated as of August 12, 2005 between Vulcan Energy GP Holdings Inc. and Plains All American GP LLC (incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K filed August 16, 2005).

10.34		—	Excess Voting Rights Agreement dated as of August 12, 2005 between Lynx Holdings I, LLC and Plains All American GP LLC (incorporated by reference to Exhibit 10.4 to the Current Report on Form 8-K filed August 16, 2005).

10.35	**	—	Form of LTIP Grant Letter (executive officers) (incorporated by reference to Exhibit 10.39 to the Annual Report on Form 10-K for the year ended December 31, 2005).

10.36	**	—	Employment Agreement between Plains All American GP LLC and John P. vonBerg dated December 18, 2001 (incorporated by reference to Exhibit 10.40 to the Annual Report on Form 10-K for the year ended December 31, 2005).

10.37	**	—	Form of LTIP Grant Letter (audit committee members) (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed August 23, 2006).

10.38	**	—	Plains All American PPX Successor Long-Term Incentive Plan (incorporated by reference to Exhibit 10.45 to the Annual Report on Form 10-K for the year ended December 31, 2006).

10.39	**	—	Forms of LTIP Grant Letters dated February 22, 2007 (Named Executive Officers) (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2007).

10.40		—	First Amendment dated July 31, 2007 to the Second Amended and Restated Credit Agreement [US/Canada Facilities] by and between Plains All American Pipeline, L.P., PMC (Nova Scotia) Company, Plains Marketing Canada, L.P., Rangeland Pipeline Company, Bank of America, N.A., as Administrative Agent, and the Lenders party thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed August 6, 2007).

10.41	**	—	Separation and Release Agreement dated August 21, 2007 between Plains All American GP LLC and George R. Coiner (incorporated by reference to Exhibit 10.3 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2007).

10.42	**	—	Form of Plains AAP, L.P. Class B Restricted Units Agreement (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed January 4, 2008).

10.43		—	Second Restated Credit Agreement dated as of November 6, 2008 by among Plains Marketing, L.P., Bank of America, N.A., as Administrative Agent, and the Lenders party there to (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed November 7, 2008).

10.44		—	Second Amendment to Second Restated Credit Agreement dated as of October 25, 2010, by and among Plains Marketing, L.P., Bank of America, N.A., as Administrative Agent, and the Lenders party thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed October 28, 2010).

10.45		—	Restated Guaranty Agreement dated November 6, 2008 by Plains All American Pipeline, L.P. in favor of Bank of America, N.A., as Administrative Agent (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed November 7, 2008).

10.46		—	Contribution and Assumption Agreement dated December 28, 2007, by and between Plains AAP, L.P. and PAA GP LLC (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed January 4, 2008).

10.47		—	Assumption, Ratification and Confirmation Agreement dated January 1, 2008 by Plains Midstream Canada ULC in favor of the Lenders party to the Second Amended and Restated Credit Agreement [US/Canada Facilities], as amended (incorporated by reference to Exhibit 10.54 to the Annual Report on Form 10-K for the year ended December 31, 2007).

10.48	†	—	Assumption, Ratification and Confirmation Agreement dated January 1, 2011 by Plains Midstream

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			Canada ULC in favor of the Lenders party to the Second Amended and Restated Credit Agreement [US/Canada Facilities], as amended.

10.49	**	—	First Amendment to Amended and Restated Employment Agreement dated December 4, 2008 between Plains All American GP LLC and Greg L. Armstrong (incorporated by reference to Exhibit 10.49 to the Annual Report on Form 10-K for the year ended December 31, 2008).

10.50	**	—	First Amendment to Amended and Restated Employment Agreement dated December 4, 2008 between Plains All American GP LLC and Harry N. Pefanis (incorporated by reference to Exhibit 10.50 to the Annual Report on Form 10-K for the year ended December 31, 2008).

10.51	**	—	First Amendment to Plains All American GP LLC 2005 Long-Term Incentive Plan dated December 4, 2008 (incorporated by reference to Exhibit 10.51 to the Annual Report on Form 10-K for the year ended December 31, 2008).

10.52	**	—	Second Amendment to Plains All American GP LLC 1998 Long-Term Incentive Plan dated December 4, 2008 (incorporated by reference to Exhibit 10.52 to the Annual Report on Form 10-K for the year ended December 31, 2008).

10.53	**	—	Form of Amendment to LTIP grant letters (executive officers) (incorporated by reference to Exhibit 10.53 to the Annual Report on Form 10-K for the year ended December 31, 2008).

10.54	**	—	Form of Amendment to LTIP grant letters (directors) (incorporated by reference to Exhibit 10.54 to the Annual Report on Form 10-K for the year ended December 31, 2008).

10.55		—	Contribution Agreement dated as of April 29, 2010 by and among PAA Natural Gas Storage, L.P., PNGS GP LLC, Plains All American Pipeline, L.P., PAA Natural Gas Storage, LLC, PAA/Vulcan Gas Storage, LLC, Plains Marketing, L.P. and Plains Marketing GP Inc. (incorporated by reference to Exhibit 10.1 to PNG’s Current Report on Form 8-K filed May 4, 2010).

10.56		—	Omnibus Agreement dated May 5, 2010 by and among Plains All American GP LLC, Plains All American Pipeline, L.P., PNGS GP LLC and PAA Natural Gas Storage, L.P. (incorporated by reference to Exhibit 10.1 to PNG’s Current Report on Form 8-K filed May 11, 2010).

10.57	**	—	Form of Transaction Grant Agreement (incorporated by reference to Exhibit 10.3 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2010).

10.58	**†	—	Form of 2010 LTIP Grant Letters.

10.59	**†	—	Employment Agreement between Plains All American GP LLC and John R. Rutherford dated September 27, 2010.

10.60		—	364-Day Credit Agreement dated January 3, 2011 among Plains All American Pipeline, L.P., as Borrower; Bank of America, N.A., as Administrative Agent; DnB NOR Bank ASA and JPMorgan Chase Bank NA, as Co-Syndication Agents; SunTrust Bank and Wells Fargo Bank, National Association, as Co-Documentation Agents; the Lenders party thereto; and Merrill Lynch, Pierce, Fenner & Smith Incorporated, DnB NOR Markets, Inc. and J.P. Morgan Securities LLC, as Joint Lead Arrangers and Joint Book Managers (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed January 7, 2011).

12.1	†	—	Computation of Ratio of Earnings to Fixed Charges

21.1	†	—	List of Subsidiaries of Plains All American Pipeline, L.P.

23.1	†	—	Consent of PricewaterhouseCoopers LLP.

31.1	†	—	Certification of Principal Executive Officer pursuant to Exchange Act Rules 13a-14(a) and 15d-14(a).

31.2	†	—	Certification of Principal Financial Officer pursuant to Exchange Act Rules 13a-14(a) and 15d-14(a).

32.1	†	—	Certification of Principal Executive Officer pursuant to 18 U.S.C. 1350

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32.2	†	—	Certification of Principal Financial Officer pursuant to 18 U.S.C. 1350

101	†	—	The following financial information from the annual report on Form 10-K of Plains All American Pipeline, L.P. for the year ended December 31, 2010, formatted in XBRL (extensible Business Reporting Language): (i) Consolidated Statements of Operations, (ii) Consolidated Balance Sheets, (iii) Consolidated Statements of Cash Flows, (iv) Consolidated Statements of Changes in Partners’ Capital, (v) Consolidated Statements of Comprehensive Income, (vi) Consolidated Statements of Changes in Accumulated Other Comprehensive Income and (vii) Notes to the Consolidated Financial Statements.

† Filed herewith

** Management compensatory plan or arrangement