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)— May 5, 2010

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 May 5, 2010.

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 first-quarter 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.  Pursuant to Item 7.01 we are providing detailed guidance for financial performance for the second quarter and second half of calendar 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.

Disclosure of Second Quarter and Second Half 2010 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 9 below, we reconcile net income to EBIT and EBITDA for the 2010 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 a 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, gains and losses from other derivative activities, and PNGS contingent consideration fair value adjustment on Segment Profit, EBITDA, Net Income and Net Income per Basic and Diluted Limited Partner Unit.

We based our guidance for the three-month period ending June 30, 2010 and the six-month and twelve-month periods ending December 31, 2010 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 May 4, 2010. We undertake no obligation to publicly update or revise any forward-looking statements.

2

Plains All American Pipeline, L.P.

Operating and Financial Guidance

(in millions, except per unit data)

(1)             The projected average foreign exchange rate is $1.02 and $1.05 Canadian dollar to $1 U.S. Dollar, respectively for the three months ending June 30, 2010 and six months ending December 31, 2010. The rate as of May 4, 2010 was $1.025 Canadian dollar to $1 U.S. Dollar. A $0.10 change in the FX rate will impact EBITDA for the last nine months of 2010 by approximately $9 million.

3

Notes and Significant Assumptions:

1.                                                                                       Definitions.

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 and Frontier pipeline systems and Settoon Towing, in which we own noncontrolling interests.

Pipeline volume estimates are based on historical trends, anticipated future operating performance and completion of internal growth projects. Actual 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. 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.

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

(2)  Mid-point of guidance.

4

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.

We forecast adjusted segment profit 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.               Supply and Logistics.  Our supply and logistics segment operations generally consist of the following activities:

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 June 30, 2010 reflect the current market structure and seasonal, weather-related variations in LPG sales.  The second half of 2010 reflects our expectation of normal winter weather for our LPG business.  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.

5

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, asset impairments or foreign exchange rates.

4.                      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 2010 to be approximately $360 million for expansion projects with an additional $85 million for maintenance capital projects. During the first three months of 2010, we spent $76 million and $11 million, respectively, for expansion and maintenance projects.  Following are some of the more notable projects and forecasted expenditures for the year ending December 31, 2010:

(1)             Primarily pipeline connections and upgrades, truck stations, new tank construction and refurbishing, and carry-over of projects started in 2009.

6

5.                     Capital Structure.  This guidance is based on our capital structure as of March 31, 2010 as adjusted to give effect of the sale of 23% of our natural gas storage business that closed on May 5, 2010.  The results of the natural gas storage business will continue to be consolidated in our financial statements with respect to our 77% interest, however, all third party equity in the assets will be reported as a non-controlling interest, where appropriate.

6.                     Interest Expense.   Debt balances are projected based on 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.                     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 MLP’s.”

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 $65 million of this reduction was realized as of March 31, 2010.  Incentive distributions will be reduced by $10.75 million for the balance of 2010 and $7.25 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.

7

8.                     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 May 5, 2010, 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 April 13, 2010, we declared an annualized distribution of $3.74 payable on May 14, 2010 to our unitholders of record as of May 4, 2010. 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 $57.00 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 June 30, 2010 would change the second-quarter equity compensation expense by approximately $6 million. Therefore, actual net income could differ materially from our projections.

9.                     Reconciliation of Net Income to EBIT and EBITDA.  The following table reconciles net income to EBIT and EBITDA, for the three-month guidance range ending June 30, 2010 and six-month and twelve-month guidance ranges ending December 31, 2010.

8

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:

9

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.

10

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.

11