UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT
Pursuant to Section 13 or 15(d) of The Securities Exchange Act of 1934

Date of Report (Date of earliest event reported) — February 9, 2011

Plains All American Pipeline, L.P.

(Exact name of registrant as specified in its charter)

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

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

(Former name or former address, if changed since last report.)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

o            Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

o            Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

o            Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

o            Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Item 9.01.          Financial Statements and Exhibits

(d)    Exhibit 99.1 — Press Release dated February 9, 2011.

Item 2.02         and Item 7.01. Results of Operations and Financial Condition; Regulation FD Disclosure

Plains All American Pipeline, L.P. (the “Partnership”) today issued a press release reporting its fourth-quarter and annual 2010 results. We are furnishing the press release, attached as Exhibit 99.1, pursuant to Item 2.02 and Item 7.01 of Form 8-K.  We are providing detailed guidance for financial performance for the first quarter of calendar 2011 and for the full year.  In accordance with General Instruction B.2. of Form 8-K, the information presented herein under this Item 7.01 shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), nor shall it be deemed incorporated by reference in any filing under the Exchange Act or Securities Act of 1933, as amended, except as expressly set forth by specific reference in such a filing.

Disclosure of First Quarter and Full Year 2011 Guidance

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.  Management believes that the presentation of such additional financial measures provides useful information to investors regarding our financial condition and results of operations because these measures, when used in conjunction with related GAAP financial measures, (i) provide additional information about our core operations 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.  EBIT and EBITDA (each as defined below in Note 1 to the “Operating and Financial Guidance” table) are non-GAAP financial measures. Net income and cash flows from operating activities are the most directly comparable GAAP measures to EBIT and EBITDA. In Note 11 below, we reconcile net income to EBIT and EBITDA for the 2011 guidance periods presented. We do not, however, reconcile cash flows from operating activities to EBIT and EBITDA, because such reconciliations are impractical for a forecasted period. We encourage you to visit our website at www.paalp.com (in particular the section entitled “Non-GAAP Reconciliations”), which presents a historical reconciliation of EBIT and EBITDA as well as certain other commonly used non-GAAP financial measures. In addition, we have highlighted the impact of our (i) equity compensation expense, (ii) net loss on early repayment of senior notes, and (iii) PAA Natural Gas Storage (“PNG”) insurance deductib le for the Bluewater incident as well as SG Resources acquisition related costs, as such items affect Segment Profit, EBITDA, Net Income attributable to Plains and Net Income per Basic and Diluted Limited Partner Unit.

We based our guidance for the three-month period ending March 31, 2011 and twelve-month period ending December 31, 2011 on assumptions and estimates that we believe are reasonable given our assessment of historical trends (modified for changes in market conditions), business cycles and other reasonably available information. Projections covering multi-quarter periods contemplate inter-period changes in future performance resulting from new expansion projects, seasonal operational changes (such as LPG sales) and acquisition synergies. Our assumptions and future performance, however, are both subject to a wide range of business risks and uncertainties, so no assurance can be provided that actual performance will fall within the guidance ranges. Please refer to information under the caption “Forward-Looking Statements and Associated Risks” below. These risks and uncertainties, as well as other unforeseeable risks and uncertainties, could cause our actual results to differ materially from those in the following table. The operating and financial guidance provided below is given as of the date hereof, based on information known to us as of February 8, 2011. We undertake no obligation to publicly update or revise any forward-looking statements.

On December 29, 2010 PAA announced that PAA Natural Gas Storage, L.P. (in which PAA has a general partner interest and majority equity ownership position) entered into a definitive agreement to acquire SG Resources Mississippi, LLC, (“SG Resources”).  The primary asset of SG Resources is the Southern Pines Energy Center (“Southern Pines”) which is a FERC-regulated, high-performance, salt-cavern natural gas storage facility. These projections include the effect of the Southern Pines acquisition which closed on February 9, 2011 for total consideration of approximately $750 million.

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Plains All American Pipeline, L.P.

Operating and Financial Guidance

(in millions, except per unit data)

(1)     The projected average foreign exchange rate is $1.05 Canadian dollar to $1 U.S. Dollar. The rate as of February 8, 2011 was $0.99 Canadian dollar to $1 U.S. Dollar.  A $0.05 change in the FX rate will impact annual EBITDA by approximately $10 million.

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Notes and Significant Assumptions:

2.              Operating Segments. We manage our operations through three operating segments: (i) Transportation, (ii) Facilities and (iii) Supply and Logistics. The following is a brief explanation of the operating activities for each segment as well as key metrics.

a.              Transportation. 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 the Butte, Frontier and White Cliffs pipeline systems and Settoon Towing, in which we own non-controlling interests.

Pipeline volume estimates are based on historical trends, anticipated future operating performance and assumed completion of internal growth projects. Actual volumes will be influenced by maintenance schedules at refineries, production declines, weather and other natural occurrences including hurricanes, changes in the quantity of inventory held in tanks, and other external factors beyond our control. We forecast adjusted segment profit using the volume assumptions in the table below, priced at forecasted tariff rates, less estimated field operating costs and G&A expenses. Field operating costs do not include depreciation. Actual segment profit could vary materially depending on the level and mix of volumes transported or expenses incurred during the period.

The following table summarizes our total pipeline volumes and highlights major systems that are significant either in total volumes transported or in contribution to total transportation segment profit.

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(1)   The aggregate of multiple systems in their respective areas.

(2)   Mid-point of guidance.

b.              Facilities. 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.

Adjusted segment profit is forecast using the volume assumptions in the table below, priced at forecasted rates, less estimated field operating costs and G&A expenses. Field operating costs do not include depreciation.

(1)             Calculated as the sum of: (i) crude oil, refined products and LPG storage capacity; (ii) natural gas storage capacity divided by the gas to crude Btu equivalent ratio of 6 mcf of gas to 1 barrel of crude oil; and (iii) LPG processing volumes multiplied by the number of days in the period and divided by the number of months in the period.

(2)             Mid-point of guidance.

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c.               Supply and Logistics. Our supply and logistics segment operations generally consist of the following activities:

·                  the purchase of 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;

·                  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 level of profit in the supply and logistics segment is influenced by overall market structure and the degree of volatility in the crude oil market, as well as variable operating expenses. Forecasted operating results for the three-month period ending March 31, 2011 reflect the current market structure and seasonal, weather-related variations in LPG sales.  Variations in weather, market structure or volatility could cause actual results to differ materially from forecasted results.

We forecast adjusted segment profit using the volume assumptions stated below, as well as estimates of unit margins, field operating costs, G&A expenses and carrying costs for contango inventory, based on current and anticipated market conditions. Actual volumes are influenced by temporary market-driven storage and withdrawal of oil, maintenance schedules at refineries, production declines, weather, and other external factors beyond our control. Field operating costs do not include depreciation. Realized unit margins for any given lease-gathered barrel could vary significantly based on a variety of factors including location, quality and contract structure. Accordingly, the projected segment profit per barrel can vary significantly even if aggregate volumes are in line with the forecasted levels.

(1)             Mid-point of guidance

3.              Depreciation and Amortization. We forecast depreciation and amortization based on our existing depreciable assets, the Southern Pines acquisition, forecasted capital expenditures and projected in-service dates. Depreciation may vary during any one period due to gains and losses on intermittent sales of assets, asset retirement obligations, asset impairments or foreign exchange rates. This guidance reflects the full year benefit of a reduction in depreciation expense from the internal review initiated in 2010 that reassessed the depreciable lives of several of our large storage facilities and pipeline systems.

4.              Acquisitions and Other Capital Expenditures. As stated above, this guidance includes the effect of the purchase of Southern Pines that closed on February 9, 2011.  Although acquisitions constitute a key element of our growth strategy, the forecasted results and associated estimates do not include any forecasts for acquisitions to which we may commit after the date hereof. We forecast capital expenditures during calendar 2011 to be approximately $550 million for expansion projects with an additional $85 million for maintenance capital projects. Following are some of the more notable projects and forecasted expenditures for the year ending December 31, 2011:

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

5.              Capital Structure. This guidance is based on our capital structure as of December 31, 2011 adjusted for PNG’s issuance of $370 million of equity prior to closing of the Southern Pines acquisition and PAA’s issuance of $600 million of 5% 10-year senior notes on January 14, 2011.  A portion of the new senior notes was used to fund the remainder of the Southern Pines purchase price and repurchase $200 million of 7.75% senior notes on February 7, 2011 (a $23 million loss associated with repurchasing these notes is reflected in Other Expenses and is considered a Selected Item Impacting Comparability).  Also, in e arly January 2011, a $500 million, 364-day revolving credit facility was established.

6.              Interest Expense. Debt balances are projected based on the change in capital structure discussed in Note 5, estimated cash flows, estimated distribution rates, estimated capital expenditures for maintenance and expansion projects, expected timing of collections and payments, and forecasted levels of inventory and other working capital sources and uses. Interest rate assumptions for variable-rate debt are based on the current forward LIBOR curve.

Included in interest expense are commitment fees, amortization of long-term debt discounts or premiums, deferred amounts associated with terminated interest-rate hedges and interest on short-term debt for non-contango inventory (primarily hedged LPG inventory and New York Mercantile Exchange and IntercontinentalExchange margin deposits). Interest expense is net of amounts capitalized for major expansion capital projects and does not include interest on borrowings for inventory stored in a contango market. We treat interest on contango-related borrowings as carrying costs of crude oil and include it in purchases and related costs.

7.              Income Taxes. Effective January 1, 2011, our Canadian entities that were previously pass-through entities for Canadian tax purposes will become taxpaying entities.  For U.S. tax purposes, these entities will continue to be treated as pass-through entities.  As a result of this and other organizational modifications related to this event, we expect our Canadian income tax expense to increase to approximately $20 million, of which approximately $17 million is classified as current taxes.  In addition, withholding tax payments of approximately $12 million are estimated to be payable in 2011. Such withholding payments will red uce distributable cash flow, but will result in a tax credit to our equity holders and will be reflected as a distribution in partners’ capital.

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8.              Reconciliation of Adjusted EBITDA to Implied DCF. The following table reconciles the mid-point of adjusted EBITDA to implied distributable cash flow for the three-month and twelve-month mid-point guidance periods ending March 31, 2011 and December 31, 2011, respectively.

9.              Net Income per Unit. Basic net income per limited partner unit is calculated by dividing net income allocated to limited partners by the basic weighted average units outstanding during the period.

(1)             We calculate net income to our general partner 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 within the earnings per unit calculation. After adjusting for this distribution, the remaining undistributed earnings or excess distribution 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.”

In conjunction with certain acquisitions, our general partner reduced the amounts due it as incentive distributions by an aggregate amount of $83 million. Approximately $76 million of this reduction was realized as of December 31, 2010. The remaining $7 million of incentive distribution reductions will be realized in 2011.

The relative amount of the incentive distribution varies directionally with the number of units outstanding and the level of the distribution on the units. Based on the current number of units outstanding, each $0.05 per unit annual increase or decrease in the distribution relative to forecasted amounts decreases or increases net income available for limited partners by approximately $7 million ($0.05 per unit) on an annualized basis.

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10.       Equity Compensation Plans. The majority of grants outstanding under our various equity compensation plans contain vesting criteria that are based on a combination of performance benchmarks and service period. The grants will vest in various percentages, typically on the later to occur of specified vesting dates and the dates on which minimum distribution levels are reached. Among the various grants outstanding as of February 9, 2011, estimated vesting dates range from May 2011 to May 2019 and annualized distribution levels range from $3.50 to $4.50. For some awards, a percentage of any units remaining unvested as of a date certain will vest on such date and all others will be forfeited.

On January 12, 2011, we declared an annualized distribution of $3.83 payable on February 14, 2011 to our unitholders of record as of February 4, 2011. We have made the assessment that a $4.00 distribution level is probable of occurring and accordingly, for grants that vest at annualized distribution levels of $4.00 or less, guidance includes an accrual over the applicable service period at an assumed market price of $63.00 per unit as well as an accrual associated with awards that will vest on a date certain. The actual amount of equity compensation expense amortization in any given period will be directly influenced by (i) our unit price at the end of each reporting period, (ii) our unit price on the vesting date, (iii) the amount of the amortization in the early years, (iv) the probability assessment regarding distributions, and (v) new equity compensation award g rants. For example, a $3.00 change in the unit price assumption at March 31, 2011 would change the first-quarter equity compensation expense by approximately $6 million. Therefore, actual net income could differ materially from our projections. Similarly, if an assessment was made that a $4.10 distribution level was probable, first-quarter equity compensation expense would increase by approximately $8 million (approximately $6 million for the cumulative effect of prior service periods and approximately $2 million for the current service period amortization). Compensation expense for the remaining nine months ending December 31, 2011 would increase approximately $6 million.

11.       Reconciliation of Net Income to EBIT and EBITDA. The following table reconciles net income to EBIT and EBITDA, for the three-month and twelve-month guidance periods ending March 31, 2011 and December 31, 2011, respectively.

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Forward-Looking Statements and Associated Risks

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 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 power 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 and fluctuations in tariffs or volumes 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;

·       the currency exchange rate of the Canadian dollar;

·       weather interference with business operations or project construction;

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·       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.

We undertake no obligation to publicly update or revise any forward-looking statements. Further information on risks and uncertainties is available in our filings with the Securities and Exchange Commission, which information is incorporated by reference herein.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

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Exhibit 99.1

FOR IMMEDIATE RELEASE

Plains All American Pipeline, L.P. Reports

Fourth-Quarter and Full-Year 2010 Results

(Houston — February 9, 2011) Plains All American Pipeline, L.P. (NYSE: PAA) today reported net income attributable to Plains of $142 million, or $0.67 per diluted limited partner unit, for the fourth quarter 2010 and net income attributable to Plains of $505 million, or $2.40 per diluted limited partner unit, for the full year 2010.  Net income attributable to Plains for the fourth quarter 2009 was $110 million, or $0.52 per diluted limited partner unit, and net income attributable to Plains for the full year 2009 was $579 million, or $3.32 per diluted limited partner unit.  The Partnership reported earnings before interest, taxes, depreciation and amortization (“EBITDA”) of $277 million and $1.02 billion for the respective fourth-quarter and full-year 2010 periods, compared to reported EBITDA for the comparable 2009 periods of $236 million and $1.05 billion. (See the section of this release entitled “Non-GAAP Financial Measures” and the attached tables for discussion of EBITDA and other non-GAAP financial measures, and reconciliations of such measures to the comparable GAAP measures.)

“We are very pleased with PAA’s fourth quarter performance as we delivered fourth quarter results well above the high end of our guidance range,” said Greg L. Armstrong, Chairman and CEO of Plains All American. “These results were driven by solid performance in our fee-based transportation and facilities segments and over performance in our supply and logistics segment.”

“In addition to delivering solid financial results throughout 2010, we increased distributions paid by 3.7% while generating a healthy distribution coverage ratio of 111%, invested approximately $760 million in organic growth projects and acquisitions and completed the initial public offering of PAA Natural Gas Storage. Looking forward, our current 2011 organic capital program totals $550 million, a 55% increase over 2010. Additionally, we are well positioned to continue to pursue strategic and accretive acquisitions as we ended the year with a strong balance sheet and approximately $1.4 billion of pro forma committed liquidity.”

The Partnership’s reported results include the impact of items that affect comparability between reporting periods.  These items are excluded from adjusted results, and are described in the table below.  Accordingly, the Partnership’s fourth-quarter 2010 adjusted net income attributable to Plains, adjusted net income per diluted limited partner unit and adjusted EBITDA were $187 million, $0.99 and $322 million, respectively, as compared to fourth-quarter 2009 adjusted net income attributable to Plains, adjusted net income per diluted limited partner unit and adjusted EBITDA of $149 million, $0.80 and $275 million, respectively.

The Partnership’s adjusted net income attributable to Plains, adjusted net income per diluted limited partner unit and adjusted EBITDA for the full year 2010 were $594 million, $3.03 and $1.11 billion, respectively, as compared to adjusted net income attributable to Plains, adjusted net income per diluted limited partner unit and adjusted EBITDA of $555 million, $3.14 and $1.02 billion, respectively.

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The following table summarizes selected items that the Partnership believes impact comparability of financial results between reporting periods (amounts in millions, except per unit amounts):

(1)                         The equity compensation expenses for the three and twelve months ended December 31, 2010 and 2009 exclude the portion of the equity compensation expense represented by grants under our Long-Term Incentive Plans (“LTIPs”) that, pursuant to the terms of the grant, will be settled in cash only and have no impact on diluted units.  The portion of the equity compensation expense attributable to the cash portion of the LTIPs is approximately $15 million and $6 million for the three months ended December 31, 2010 and 2009, respectively, and approximately $31 million and $18 million for the twelve mont hs ended December 31, 2010 and 2009, respectively.

(2)                         Gains and losses from derivative activities related to revalued inventory are included in the line item “Inventory valuation adjustments net of gains/(losses) from related derivative activities;” gains and losses from derivative activities not related to revalued inventory are included in the line item “Gains/(losses) from other derivative activities.”

(3)                         Gains and losses from other derivative activities for the three-month periods ended December 31, 2010 and 2009 include gains of less than $1 million and losses of approximately $2 million, respectively, and for the twelve-month periods ended December 31, 2010 and 2009 include gains of approximately $3 million and losses of approximately $4 million, respectively, related to interest rate derivatives, which are included in other income, net and interest expense, but do not impact segment profit.

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The following tables present certain selected financial information by segment for the fourth-quarter and full-year 2010 reporting periods (amounts in millions):

(1)                         Includes intersegment amounts.

(2)                         Segment general and administrative expenses (G&A) reflect direct costs attributable to each segment and an allocation of other expenses to the segments based on the business activities that existed at that time.  The proportional allocations by segment require judgment by management and will continue to be based on the business activities that exist during each period.

(3)                         The equity compensation expenses for the three and twelve months ended December 31, 2010 and 2009 exclude the portion of the equity compensation expense represented by grants under our Long-Term Incentive Plans (“LTIPs”) that, pursuant to the terms of the grant, will be settled in cash only and have no impact on diluted units.  The portion of the equity compensation expense attributable to the cash portion of the LTIPs is approximately $15 million and $6 million for the three months ended December 31, 2010 and 2009, respectively, and approximately $31 million and $18 million for the twelve mont hs ended December 31, 2010 and 2009, respectively.

(4)                         Gains and losses from derivative activities related to revalued inventory are included in the line item “Inventory valuation adjustments net of (gains)/losses from related derivative activities;” gains and losses from derivative activities not related to revalued inventory are included in the line item “(Gains)/losses from other derivative activities.”

(5)                         Gains and losses from other derivative activities for the three-month periods ended December 31, 2010 and 2009 include gains of less than $1 million and losses of approximately $2 million, respectively, and for the twelve-month periods ended December 31, 2010 and 2009 include gains of approximately $3 million and losses of approximately $4 million, respectively, related to interest rate derivatives, which are included in other income, net and interest expense, but do not impact segment profit.

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Adjusted segment profit for the Transportation segment for the fourth quarter and full year of 2010 increased by approximately 6% and 9%, respectively, over comparable 2009 results.  The fourth-quarter increase was primarily driven by higher pipeline volumes, partially offset by higher operating expenses.  The full-year increase was driven primarily by higher tariffs and volumes, favorable foreign exchange rates and increased pipeline loss allowance revenue, partially offset by higher operating and general and administrative expenses.

Adjusted segment profit for the Facilities segment for the fourth quarter and full year of 2010 increased by approximately 34% and 31%, respectively, over comparable 2009 results primarily due to capacity additions related to acquisitions and organic capital projects.

Adjusted segment profit for the Supply and Logistics segment for the fourth quarter and full year of 2010 increased by approximately 30% and decreased by approximately 3%, respectively, as compared to prior year fourth-quarter and full-year 2009 results.  The fourth-quarter increase reflects the benefit of higher lease gathering volumes and margins, more favorable crude oil quality differentials, market structure and volatility, partially offset by lower LPG profitability and higher operating expenses.  The full-year decrease primarily reflects lower LPG profitability, less favorable crude oil quality differentials and higher operating and general and administrative expenses, partially offset by higher gathering margins and volumes.

The Partnership’s basic weighted average units outstanding for the fourth quarter of 2010 totaled 138 million (139 million diluted) as compared to 136 million (137 million diluted) in last year’s fourth quarter. On December 31, 2010, the Partnership had approximately 141.2 million units outstanding, long-term debt of approximately $4.6 billion ($466 million of which supports hedged inventory) and an adjusted long-term debt-to-total capitalization ratio of 48%.

The Partnership has declared a quarterly distribution of $0.9575 per unit ($3.83 per unit on an annualized basis) payable February 14, 2011 on its outstanding limited partner units. This distribution represents an increase of approximately 3.2% over the quarterly distribution paid in February 2010 and an increase of approximately 0.8% from the November 2010 distribution level.

The Partnership will hold a conference call at 10:00 AM (Central) on February 10, 2011.  Prior to this conference call, the Partnership will furnish a current report on Form 8-K, which will include material in this press release and financial and operational guidance for the first quarter and full year 2011.  A copy of the Form 8-K will be available on the Partnership’s website at www.paalp.com.

Non-GAAP Financial Measures

In this release, the Partnership’s EBITDA disclosure is not presented in accordance with generally accepted accounting principles and is not intended to be used in lieu of GAAP presentations of net income or cash flows from operating activities. EBITDA is presented because we believe it provides additional information with respect to both the performance of our fundamental business activities as well as our ability to meet our future debt service, capital expenditures and working capital requirements. We also believe that debt holders commonly use EBITDA to analyze Partnership performance. In addition, we present selected items that impact the comparability of our operating results as additional information that may be helpful to your understanding of our financial results. We consider an understanding of these selected items impacting comparability to be material to our evaluation of our operating results and prospects.  Although we present selected items that we consider in evaluating our performance, you should also be aware that the items presented do not represent all items that affect comparability between the periods presented. Variations in our operating results are also caused by changes in volumes, prices, exchange rates, mechanical interruptions, acquisitions and numerous other factors. These types of variations are not separately identified in this release, but will be discussed, as applicable, in management’s discussion and analysis of operating results in our Annual Report on Form 10-K.

A reconciliation of net income to EBITDA and EBITDA to cash flows from operating activities for the periods presented is included in the tables attached to this release. In addition, the Partnership maintains on its website (www.paalp.com) a reconciliation of all non-GAAP financial information, such as EBITDA, to the most comparable GAAP measures. To access the information, investors should click on the “Investor Relations” link on the Partnership’s home page and then the “Non-GAAP Reconciliations” link on the Investor Relations page.

Forward Looking Statements

Except for the historical information contained herein, the matters discussed in this release are forward-looking statements that involve certain risks and uncertainties that could cause actual results to differ materially from results anticipated in the forward-looking statements. These risks and uncertainties include, among other things, 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 shel f production located offshore California and transported on our pipeline systems; shortages or cost increases of power 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

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333 Clay Street, Suite 1500          Houston, Texas 77002          713-646-4100 / 800-564-3036

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