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)—November 4, 2009

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:

Item 9.01. Financial Statements and Exhibits

(d)              Exhibit 99.1 — Press Release dated November 4, 2009.

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

Plains All American Pipeline, L.P. (the “Partnership or Plains”) today issued a press release reporting its third-quarter 2009 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.  Pursuant to Item 7.01 we are providing updated detailed guidance for financial performance for the fourth quarter of calendar year 2009 with resulting performance for the full calendar year of 2009 (which supersedes guidance pertaining to 2009 contained in our Form 8-K furnished on August 5, 2009) and we are providing preliminary guidance for calendar year 2010.  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.

Update of Fourth Quarter 2009 Guidance; Disclosure of Full Year 2010 Preliminary Guidance

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 10 below, we reconcile net income to EBIT and EBITDA for the 2009 guidance periods presented. It is, however, impractical to reconcile EBIT and EBITDA to cash flows from operating activities for a forecasted period. We encourage you to visit our website at www.paalp.com (in particular the section entitled “Non-GAAP Reconciliation”), which presents an historical reconciliation of certain commonly used non-GAAP financial measures, including EBIT and EBITDA. We present EBIT and EBITDA because we believe they provide additional information with respect to both the performance of our fundamental business activities and 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 have highlighted the impact of our equity compensation plans, inventory valuation adjustments net of gains and losses from related derivative activities, gains and losses from other derivative activities, foreign currency revaluations and loss on senior notes on Segment Profit, EBITDA, Net Income and Net Income per Basic and Diluted Limited Partner Unit.

The following guidance for the three months and twelve months ending December 31, 2009, as well as the preliminary guidance for calendar year 2010, is based 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 we can provide no assurance 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 November 3, 2009. We undertake no obligation to publicly update or revise any forward-looking statements.

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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 was based on actual rates for October 2009 and $1.08 CAD to $1 USD for the remainder of 2009. The rate as of November 3, 2009 was $1.07 CAD to $1 USD.

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Notes and Significant Assumptions:

1.                                 Definitions.

2.                                  Business Segments.  We manage our operations through three operating segments: (i) Transportation, (ii) Facilities and (iii) Marketing. 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. We also include in this segment our equity earnings from our investment in the Butte and Frontier 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 completion of internal growth projects. Volumes are influenced by maintenance schedules at refineries, production declines, weather and other natural disasters including hurricanes, changes in the quantity of inventory held in tanks, and other external factors beyond our control. Segment profit is forecast 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.

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

(2)   Mid-point of guidance.

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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.  On September 3, 2009, we acquired the remaining 50% indirect interest in PAA Natural Gas Storage, LLC. (“PNGS”).  As a result of the transaction, PAA now owns 100% of PNGS’s natural gas storage business and related operating entities, which is now accounted for on a consolidated basis beginning in September 2009.  PAA historically accounted for its 50% indirect interest in PNGS under the equity method.

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 6 to account for the 6:1 mcf of gas to barrel of crude oil ratio; 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.

c.               Marketing.  Our marketing segment operations generally consist of the following merchant activities:

The level of profit in the marketing 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 remainder of 2009 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 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.  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.

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(1)                                     Mid-point of guidance.

3.                                       Depreciation and Amortization.   We forecast depreciation and amortization based on our existing depreciable assets, 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, or asset impairments.

4.                                       Selected Items Impacting Comparability.   Our operating results are impacted by items that affect comparability between reporting periods, such as the equity compensation benefit or charge associated with our long-term incentive programs.  In addition, our actual results will reflect certain mark-to-market items such as gains and losses related to derivative activities, gains and losses from unrealized foreign currency transactions, and inventory valuation adjustments.  Our adjusted results exclude these selected items impacting comparability until such time as the underlying and offsetting physical transaction settles.  Although the economics of these transactions as a whole are embedded in our guidance presented here, our selected items impacting comparability for future periods do not reflect these items as there is no accurate way to forecast the timing and magnitude of their ultimate effect.  The magnitude of these items depends on market prices and exchange rates at a point in time.  Accordingly, our actual results could differ materially from our projections.

5.                                       Acquisitions and Other Capital Expenditures.   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 2009 to be approximately $380 million for expansion projects with an additional $85 to $95 million for maintenance capital projects. During the first nine months of 2009, we invested $261 million and $56 million, respectively, for expansion and maintenance capital projects.  Following are some of the more notable projects and forecasted expenditures for the year:

(1)                                     Includes a dock and condensate tanks.

(2)                                     Primarily pipeline connections, upgrades and truck stations, new tank construction and refurbishing, and carry-over of projects started in 2008.

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6.                                       Capital Structure.  This guidance is based on our capital structure as of September 30, 2009 as adjusted for the retirement on October 5, 2009 of the 7.125% Senior Notes due June 2014.

7.                                       Interest Expense.   Debt balances are projected based on estimated cash flows, estimated distribution rates, forecasted acquisitions and 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.

8.                                       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 allocate 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).  Guidance issued by the FASB 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. We reflect the impact of this difference as the “Adjustment in accordance with application of the two-class method for MLPs.”

In conjunction with the Pacific, Rainbow and PNGS acquisitions, our general partner reduced the amounts due it as incentive distributions by an aggregate amount of $83 million. Approximately $54 million of this reduction was realized as of September 30, 2009.  Incentive distributions will be reduced by $6 million for the balance of 2009, $16 million in 2010 and $7 million 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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9.                                       Equity Compensation Plans.  The majority of grants outstanding under our equity compensation plans (LTIP and Class B units) 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 earliest vesting dates and the dates on which minimum distribution levels are reached. Among the various grants outstanding as of November 4, 2009, estimated vesting dates range from May 2010 to May 2019 and annualized distribution levels range from $3.00 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 are forfeited.

On October 19, 2009, we declared an annualized distribution of $3.68 payable on November 13, 2009 to our unitholders of record as of November 3, 2009. We have made the assessment that a $3.90 distribution level is probable of occurring and accordingly, for grants that vest at annualized distribution levels of $3.90 or less, guidance includes an accrual over the applicable service period at an assumed market price of approximately $50.00 per unit as well as the fair value 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 date of actual vesting, (iii) the amount of the amortization in the early years, (iv) the probability assessment of achieving future distribution rates, and (v) new equity compensation award grants. For example, a $3.00 change in the unit price assumption at September 30, 2009 would change the fourth-quarter equity compensation expense by approximately $5 million. Therefore, actual net income could differ materially from our projections.

10.                                 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 ranges ending December 31, 2009.

Preliminary Calendar 2010 Guidance

The following range for preliminary adjusted EBITDA guidance for 2010 is based on the following:

The low end of the range assumes —

The high end of the range assumes —

Preliminary Calendar 2010 Guidance (in millions)

Our preliminary guidance for interest expense is based on our capital structure as of September 30, 2009 (adjusted for the retirement of the $250 million Senior Notes on October 5, 2009), the current market outlook for floating interest rates, approved capital projects for 2009 and the assumption that 2010 capital projects including base gas will range between $300 million to $400 million.  Our preliminary guidance for depreciation and amortization is based on projected depreciation from our present asset base, and continued development of our portfolio of projects.  Our preliminary guidance for maintenance capital expenditures is based on our

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estimate of the range of recurring expenditures that are expected to average approximately $85 million in any given year.  All amounts assume a foreign exchange rate of $1.10 CAD to $1.00 USD.  The adjusted net income and adjusted EBITDA shown above exclude selected items impacting comparability such as equity compensation and gains and losses related to derivative activities  (see note 4 above) as it is impractical to forecast such items.

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 identified by the words “anticipate,” “believe,” “estimate,” “expect,” “plan,” “intend” and “forecast,” as well as similar expressions and statements regarding our business strategy, plans and objectives of our management 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 are 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:

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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

 Solid Third-Quarter 2009 Results

(Houston — November 5, 2009) Plains All American Pipeline, L.P. (NYSE: PAA) today reported net income of $122 million, or $0.65 per diluted limited partner unit, for the third quarter of 2009 as compared to net income for the third quarter of 2008 of $206 million, or $1.41 per diluted limited partner unit.  The Partnership reported earnings before interest, taxes, depreciation and amortization (“EBITDA”) of $242 million for the third quarter of 2009, compared with EBITDA of $310 million for the third quarter of 2008.

The Partnership’s reported results include the impact of items that affect comparability between reporting periods. These items are excluded from adjusted results, as further described in the table below.  Accordingly, the Partnership’s third-quarter 2009 adjusted net income, adjusted net income per diluted limited partner unit and adjusted EBITDA were $114 million, $0.59 and $234 million, respectively, as compared to third-quarter 2008 adjusted net income, adjusted net income per diluted limited partner unit and adjusted EBITDA of $119 million, $0.71 and $223 million, respectively. (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.)

“Plains All American has been very active and productive in the four months since the end of the second quarter” said Greg L. Armstrong, Chairman & CEO of Plains All American.  “We delivered operating and financial results at the high end of guidance, acquired the remaining 50% interest in PAA Natural Gas Storage (PNGS), raised over $1.2 billion in the capital markets at very attractive rates and increased our annualized distribution by 6 cents or 1.7% to $3.68 per unit.  We also ended the third quarter with a solid balance sheet and over $1.6 billion of available committed liquidity, of which approximately $260 million was used in early October to prepay our 7.125% senior notes.”

For the first nine months of 2009, the Partnership reported net income of $469 million, or $2.82 per diluted limited partner unit, as compared to net income for the first nine months of 2008 of $339 million, or $2.08 per diluted limited partner unit. The Partnership reported EBITDA of $808 million for the first nine months of 2009, compared with EBITDA of $639 million for the first nine months of 2008. Adjusted net income, adjusted net income per diluted limited partner unit and adjusted

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EBITDA for the first nine months of 2009 were $406 million, $2.33 and $745 million, respectively. Adjusted net income, adjusted net income per diluted limited partner unit and adjusted EBITDA for the first nine months of 2008 were $352 million, $2.19 and $652 million, respectively.

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 charge for the three and nine months ended September 30, 2009 and 2008 excludes the portion of the equity compensation expense represented by grants under the LTIP Plans 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 LTIP Plans is approximately $4 million and $1 million for the three months ended September 30, 2009 and 2008, respectively, and approximately $11 million and $3 million for the nine months ended September 30, 2009 and 2008, respectively.

(2)                           Gains and losses from derivative activities related to revalued inventory are included in the line item “Inventory valuation adjustments net of gains and (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 nine months ended September 30, 2009 includes losses of approximately $1 million related to interest rate derivatives, which are included in other income/(expense), net, but do not impact segment profit.

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The following tables present certain selected financial information by segment for the third-quarter and first nine months reporting periods (amounts in millions):