PAA Plains All American Pipeline

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

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))

(a)                                          The assumed average foreign exchange rate is $1.30 Canadian dollar (CAD) to $1.00 U.S. dollar (USD) for the three-month period ending June 30, 2016 and the six-month period ending December 31, 2016.  The rate as of May 3, 2016 was $1.27 CAD to $1.00 USD. We do not anticipate that fluctuations in the foreign exchange rate will have significant impact on aggregate reported financial results, but such fluctuations will result in variations between segments.

(b)                                         We allocate Net Income Attributable to PAA among our Series A Preferred Unitholders, Common Unitholders and General Partner interest using the two-class method in accordance with applicable authoritative accounting guidance.  Under the two-class method, we allocate Net Income Attributable to PAA based on the distributions pertaining to the current period’s net income.  After adjusting for the appropriate period’s distributions, the remaining undistributed earnings or excess distributions over earnings, if any, are allocated to the general partner, common unitholders and participating securities in accordance with the contractual terms of the partnership agreement and as further prescribed under the two-class method.

(c)                                          Diluted net income per common unit is computed based on the weighted average number of common units outstanding plus the effect of dilutive potential units outstanding during the period using the two-class method, unless the effects of such units are anti-dilutive.

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2.               Operating Segments . We manage our operations through three operating segments:  Transportation, Facilities and 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 NGL on pipelines, gathering systems, trucks and barges. The Transportation segment generates revenue through a combination of tariffs, third-party pipeline capacity agreements and other transportation fees. Our transportation segment also includes equity earnings from our investments in the entities that own BridgeTex, Eagle Ford, Frontier, Saddlehorn, White Cliffs, and Butte pipeline systems as well as Settoon Towing, in which we own interests ranging from 22% to 50%.  We account for these investments under the equity method of accounting.

Pipeline volume estimates are based on historical trends, anticipated future operating performance and assumed completion of capital projects. Actual volumes will be influenced by maintenance schedules at refineries, drilling and completion activity levels, production trends, weather and other natural occurrences including hurricanes, changes in the quantity of inventory held in tanks, variations due to market structure and other external factors beyond our control. We forecast adjusted segment profit using the volume assumptions in the following table, priced at forecasted tariff rates, less estimated field operating costs and G&A expenses. Field operating costs do not include depreciation. Actual adjusted segment profit could vary materially depending on the level and mix of volumes transported or expenses incurred during the period, as well as any differences between forecasted and actual recognition of minimum ship or pay commitments. The following table summarizes our total transportation volumes and is broken down by crude oil geographic area as well as total NGL and trucking volumes.

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(1)                 Region includes volumes (attributable to our interest) from pipelines owned by unconsolidated entities.

(2)                 Represents the midpoint 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 and natural gas and condensate processing services. The Facilities segment generates revenue through a combination of month-to-month and multi-year agreements and processing arrangements.

Revenues generated in this segment primarily include (i) fees that are generated from storage capacity agreements, (ii) terminal throughput fees that are generated when we receive crude oil, refined products or NGL from one connecting source and deliver the applicable product to another connecting carrier, (iii) loading and unloading fees at our rail terminals, (iv) fees from NGL fractionation and isomerization services, (v) fees from natural gas and condensate processing services and (vi) fees associated with natural gas park and loan activities, interruptible storage services and wheeling and balancing services.  Adjusted segment profit is forecasted using the volume assumptions in the following table, 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 NGL terminalling and storage capacity; (ii) rail load and unload volumes multiplied by the number of days in the period and divided by the number of months in the period; (iii) natural gas storage working capacity divided by 6 to account for the 6:1 mcf of natural gas to crude Btu equivalent ratio and further divided by 1,000 to convert to monthly volumes in millions; and (iv) NGL fractionation volumes multiplied by the number of days in the period and divided by the number of months in the period.

(2)                 Represents the midpoint of guidance.

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c.                            Supply and Logistics . Our Supply and Logistics segment operations generally consist of the following merchant-related activities:

·                   the purchase of U.S. and Canadian crude oil at the wellhead, the bulk purchase of crude oil at pipeline, terminal and rail 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 and natural gas;

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

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

·                   the transportation of crude oil and NGL on trucks, barges, railcars, pipelines and ocean-going vessels from various delivery points, market hub locations or directly to end users such as refineries, processors and fractionation facilities; and

·                   the purchase and sale of natural gas.

We characterize a substantial portion of our baseline 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 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 and carrying costs for hedged inventory as well as any operating and G&A 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 market volatility as well as variable operating expenses. Forecasted operating results for the three-month period ending June 30, 2016 and for the six-month period ending December 31, 2016 reflect current market structure as well as seasonal, weather-related and other anticipated variations in crude oil, NGL and natural gas 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 hedged inventory, based on current and anticipated market conditions. Actual volumes are influenced by temporary market-driven storage and withdrawal of crude oil, maintenance schedules at refineries, actual production levels, 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 and quality differentials as well as contract structure. Accordingly, the projected adjusted segment profit per barrel can vary significantly even if aggregate volumes are in line with the forecasted levels.

(1)              Represents the midpoint 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 also vary due to gains and losses on intermittent sales of assets, asset retirement obligations, asset impairments, and acceleration of depreciation 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 (the forecast does include the announced Empress acquisition that is expected to close during the second quarter of 2016). We forecast capital expenditures during calendar year 2016 to be approximately $1.5 billion for expansion projects with an additional $190 million to $210 million for maintenance capital projects. During the first three months of 2016, we invested $370 million and $47 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, 2016:

(1)              Potential variation to current capital costs estimates may result from (i) changes to project design, (ii) final cost of materials and labor and (iii) timing of incurrence of costs due to uncontrollable factors such as receipt of permits, or regulatory approvals and weather.

5.               Asset Sales. This guidance takes into account the sale of non-core assets for aggregate total proceeds of $500 million to $600 million for the full year 2016.  We do not expect that in the aggregate any net gain or loss from these asset sales will be material and thus, we have not included any such estimate in our guidance.

6.               Capital Structure. This guidance is based on our capital structure as of March 31, 2016.

7.               Interest Expense. Debt balances are projected based on estimated cash flows, estimated distribution rates, estimated capital expenditures for maintenance and expansion projects, anticipated equity proceeds from the continuous offering program, 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 LIBOR curve as of late April 2016.

Interest expense is net of amounts capitalized for expansion capital projects and does not include interest on borrowings for hedged inventory. We treat interest on hedged inventory borrowings as carrying costs of crude oil, NGL, and natural gas and include it in purchases and related costs.

8.              Income Taxes . We expect our Canadian income tax expense to be approximately $9 million and $84 million for the three-month period ending June 30, 2016 and twelve-month period ending December 31, 2016, respectively, of which approximately $4 million and $74 million, respectively, is classified as a current income tax expense.  For the twelve-month period ending December 31, 2016 we expect to have a deferred tax expense of $10 million.  All or part of the annual income tax expense of $84 million may result in a tax credit to our equity holders.

9.               Equity-Indexed Compensation Plans. The majority of grants outstanding under our various equity-indexed 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.

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Guidance assumes a market price of $21 per unit as well as an accrual associated with awards that will vest on a certain date.  A $2 change in the unit price would change the second-quarter and full year equity-indexed compensation expense by approximately $4 million. Therefore, actual net income could differ from our projections.

10.        Reconciliation of Net Income to EBITDA and Adjusted EBITDA. The following table reconciles net income to EBITDA and Adjusted EBITDA for the indicated periods.

11.        Implied DCF. The following table reconciles adjusted EBITDA to implied DCF for the indicated periods.

(1)              Excludes certain non-cash items impacting interest expense such as amortization of debt issuance costs and terminated interest rate swaps.

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Forward-Looking Statements

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 such words, expressions or statements, however, does not mean that the statements are not forward-looking. Any such forward-looking 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 or outcomes to differ materially from the results or outcomes anticipated in the forward-looking statements. The most important of these factors include, but are not limited to:

·                   declines in the volume of crude oil, refined product and NGL shipped, processed, purchased, stored, fractionated and/or gathered at or through the use of our assets, whether due to declines in production from existing oil and gas reserves, failure to develop or slowdown in the development of additional oil and gas reserves, whether from reduced cash flow to fund drilling or the inability to access capital, or other factors;

·                   the effects of competition;

·                   failure to implement or capitalize, or delays in implementing or capitalizing, on expansion projects;

·                   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;

·                   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 occurrence of a natural disaster, catastrophe, terrorist attack or other event, including attacks on our electronic and computer systems;

·                   maintenance of our credit rating and ability to receive open credit from our suppliers and trade counterparties;

·                   tightened capital markets or other factors that increase our cost of capital or limit 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 currency exchange rate of the Canadian dollar;

·                   continued creditworthiness of, and performance by, our counterparties, including financial institutions and trading companies with which we do business;

·                   inability to recognize current revenue attributable to deficiency payments received from customers who fail to ship or move more than minimum contracted volumes until the related credits expire or are used;

·                   non-utilization of our assets and facilities;

·                   increased costs, or lack of availability, of insurance;

·                   weather interference with business operations or project construction, including the impact of extreme weather events or conditions;

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

·                   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 effectiveness of our risk management activities;

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

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

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

·                   risks related to the development and operation of our assets, including our ability to satisfy our contractual obligations to our customers;

·                   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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