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 7, 2012

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 7, 2012

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 2012 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 2012.  In accordance with General Instruction B.2. of Form 8-K, the information presented herein under Item 2.02 and 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 2012 Guidance

To supplement our financial information presented in accordance with GAAP, management uses additional measures 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 represents one of the two most directly comparable GAAP measures to EBIT and EBITDA. In Note 10 below, we reconcile net income to EBIT and EBITDA for the 2012 guidance periods presented. Cash flow from operating activities is the other most comparable GAAP measure. 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 (i) losses from derivative activities, (ii) equity compensation expense, (iii) acquisition related expenses and (iv) other selected items.  Due to the nature of the selected items, certain of the selected items impacting comparability may impact certain non-GAAP financial measures but not impact other non-GAAP financial measures.

We based our guidance for the three-month period ending June 30, 2012 and the six-month and twelve-month periods ending December 31, 2012 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 NGL 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 6, 2012. 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)

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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, Frontier and White Cliffs pipeline systems and Settoon Towing, in which we own noncontrolling 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 trends, 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 transportation 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)                     Includes BP NGL acquisition effective April 1, 2012.

(3)                     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, NGL and natural gas, as well as NGL 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 forecasted 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)                     Includes BP NGL acquisition effective April 1, 2012.

(2)                    Calculated as the sum of: (i) crude oil, refined products and NGL storage capacity; (ii) natural gas storage capacity divided by 6 to account for the 6:1 mcf of gas to crude Btu equivalent ratio and further divided by 1,000 to convert monthly volumes in millions; and (iii) NGL fractionation volumes (based on estimated utilized capacity), multiplied by the number of days in the period and divided by the number of months in the period.

(3)                    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, the bulk purchase of crude oil at pipeline and terminal facilities, and the purchase of cargos at their load port and various other locations in transit;

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

·                  the purchase of NGL from producers, refiners and other marketers;

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

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

We characterize a substantial portion of the profit generated by our supply and logistics segment as fee equivalent. This portion of the segment profit is generated by the purchase and resale of crude oil production at the wellhead on an index-related basis, which results in us generating a gross margin for such activities.  This gross margin is reduced by the transportation, facilities and other logistical costs associated with delivering the crude oil to market as well as any operating and general and administrative expenses.  The level of profit associated with a portion of the other activities we conduct 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, 2012 reflect the current market structure and for the last nine months of 2012, reflect the seasonal, weather-related variations in NGL 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)                     Includes BP NGL acquisition effective April 1, 2012.

(2)                     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, asset impairments or foreign exchange rates.

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4.               Capital Expenditures and Acquisitions.  Although acquisitions constitute a key element of our growth strategy, the forecasted results and associated estimates do not include any forecasts for acquisitions that we may commit to after the date hereof. We forecast capital expenditures during calendar 2012 to be approximately $1.0 billion for expansion projects with an additional $140 to $160 million for maintenance capital projects. During the first three months of 2012, we spent $236 million and $35 million for expansion and maintenance projects, respectively.  The following are some of the more notable projects and forecasted expenditures for the year ending December 31, 2012:

5.               Capital Structure. This guidance is based on our capital structure as of March 31, 2012.

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.              Income Taxes. We expect Canadian income tax expense to be approximately $16 million and $66 million for the three-month and twelve-month periods ending June 30, 2012 and December 31, 2012, respectively, of which approximately $15 million and $60 million, respectively, is classified as current.  For the twelve-month period ending December 31, 2012 we expect to have a deferred tax expense of $6 million.  All or part of the income tax expense of $66 million may result in a tax credit to our equity holders.

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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 period ending June 30, 2012 and the six-month and twelve-month periods ending December 31, 2012.

9.               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 periods. 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 May 6, 2012, estimated vesting dates range from May 2012 to May 2019 and annualized distribution levels range from $3.75 to $4.80. For some awards, a percentage of any units remaining unvested as of a certain date will vest on such date and all others will be forfeited.

On April 10, 2012, we declared an annualized distribution of $4.18 payable on May 15, 2012 to our unitholders of record as of May 4, 2012. We have made the assessment that a $4.50 distribution level is probable of occurring, and accordingly, for grants that vest at annualized distribution levels of $4.50 or less, guidance includes an accrual over the applicable service period at an assumed market price of $78.00 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 probability assessment regarding distributions, and (iv) new equity compensation award grants. For example, a $3.00 change in the unit price during the quarter would change the second-quarter equity compensation expense by approximately $5 million and the second-half equity compensation expense by approximately $1 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 period ending June 30, 2012 and six-month and twelve-month periods ending December 31, 2012.

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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. The most important of these factors include, but are not limited to:

·                  failure to integrate the BP NGL acquisition;

·                  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;

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

·                  environmental liabilities or events that are not covered by an indemnity, insurance or existing reserves;

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

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

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

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

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

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

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

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

·                  the effects of competition;

·                  interruptions in service on third-party pipelines;

·                  increased costs or lack of availability of insurance;

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

·                  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;

·                  factors affecting demand for natural gas and natural gas storage services and rates;

·                  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 and refined products, as well as in the storage of natural gas and the processing, transportation, fractionation, storage and marketing of natural gas liquids.

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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