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 10, 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 February 10, 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 fourth-quarter and annual 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 detailed guidance for financial performance for the first quarter of calendar 2010 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 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 on Segment Profit, EBITDA, Net Income attributable to Plains and Net Income per Basic and Diluted Limited Partner Unit.

The following guidance for the three-month period ending March 31, 2010 and twelve-month period ending December 31, 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 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 9, 2010. We undertake no obligation to publicly update or revise any forward-looking statements.

On January 25, 2010, PAA announced that its wholly owned subsidiary, PAA Natural Gas Storage, L.P. (“PNGS”), had filed a registration statement on Form S-1 with the SEC relating to its proposed initial public offering of common units representing limited partner interests in PNGS. The registration statement is available on the SEC’s web site at http://www.sec.gov under the registrant’s name, “PAA Natural Gas Storage, L.P.,” but has not yet become effective. Although PAA is an existing issuer, PNGS is not. Under these circumstances, SEC rules restrict the disclosure of certain types of information about a potential issuer.  In respect of these restrictions, we have modified the format and level of detail we typically apply to certain aspects of our presentation as they relate to specific information regarding PNGS activities.  The PNGS securities may not be sold nor may offers to buy be accepted prior to the time the registration statement becomes effective.  This notice shall not constitute an offer to sell or a solicitation of an offer to buy, nor shall there be any sale of these securities in any state or jurisdiction in which such an offer, solicitation or sale would be unlawful prior to registration or qualification under the securities laws of any such state or jurisdiction.

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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 $1.10 Canadian dollar to $1 U.S. Dollar. The rate as of February 9, 2010 was $1.07 Canadian dollar to $1 U.S. Dollar. A $0.10 change in the FX rate will impact annual EBITDA by approximately $13 million.

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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) Supply and Logistics. We previously referred to the Supply and Logistics segment as the Marketing segment.  We revised the segment name to better describe the business activities conducted within that segment.  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. Adjusted 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.

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 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 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, 2010 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 actual 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.                       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.  Following are some of the more notable projects and forecasted expenditures for the year ending December 31, 2010 (in millions):

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

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5.                       Capital Structure.  This guidance is based on our capital structure as of December 31, 2009.

6.                       Interest Expense.  Debt balances are projected based on estimated cash flows, estimated distribution rates, 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, amortization of 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 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 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 $60 million of this reduction was realized as of December 31, 2009.  Incentive distributions will be reduced approximately $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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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 February 10, 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 January 20, 2010, we declared an annualized distribution of $3.71 payable on February 12, 2010 to our unitholders of record as of February 2, 2010. We have made the assessment that a $3.90 distribution level is probable of occurring prior to the expiration dates of the underlying LTIP grants 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 $53.00 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 March 31, 2010 would change the first-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 and twelve-month guidance ranges ending March 31, 2010 and December 31, 2010, 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 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 success 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;

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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 deteriorated 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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