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)—August 1, 2006

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 August 1, 2006

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 second quarter 2006 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 third and fourth quarter of calendar 2006 and modifying certain aspects of our previous guidance for financial performance for the full year of calendar 2006 (which supersedes guidance in our 8-K furnished on June 12, 2006).  This guidance excludes any contribution from the proposed merger with Pacific Energy Partners, L.P. announced June 12, 2006. 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, nor shall it be deemed incorporated by reference in any filing under the Securities Act of 1933, as amended, except as expressly set forth by specific reference in such a filing.

Disclosure of Third and Fourth Quarter 2006 Estimates; Update of Full Year 2006 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 11 below, we reconcile EBITDA and EBIT to net income for the 2006 guidance periods presented. However, it is impractical to reconcile EBIT and EBITDA to cash flows from operating activities for forecasted periods. 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 long-term incentive plan, the cumulative effect of a change in accounting principle and, to the extent known, gains and losses related to SFAS 133 (primarily non-cash, mark-to-market adjustments) on EBITDA, Net Income and Net Income per Basic and Diluted Limited Partner Unit.

The following guidance for the three month periods ending September 30 and December 31 and twelve month period ending December 31, 2006 are based on assumptions and estimates that we believe are reasonable given our assessment of historical trends, business cycles and other information reasonably available. However, our assumptions and future performance 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 the 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 July 31, 2006. 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)

*       The projected average foreign exchange rate is $1.15 CAD to $1 USD.

**     See Note 9. The application of EITF 03-06 may result in interim period amounts not totaling to the annual amount.

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Notes and Significant Assumptions:

1.                 Definitions.

 

2.                 Pipeline Operations.   Pipeline volume estimates are based on historical trends, anticipated future operating performance and completion of internal growth projects. Volumes are influenced by temporary market-driven storage and withdrawal of oil, maintenance schedules at refineries, production declines and other external factors beyond our control. Actual segment profit could vary materially depending on the level of volumes transported.

For the three month periods ending September 30 and December 31, 2006 projected volumes incorporate assumptions with respect to 1) additional throughput agreements on the Basin and Capline Pipeline Systems, 2) acquisitions of certain assets from BP and Chevron, and 3) higher Canadian volumes primarily due to the purchase of the remaining interest in Cactus Lake Pipeline. Volumes are impacted by a combination of anticipated seasonal demand, acquisitions, recovery of certain volumes impacted by last year’s hurricanes, and natural production declines.

The following table summarizes our total pipeline volumes as well as major systems that are significant either in total volumes transported or in contribution to total pipeline segment profit.

(1)    The aggregate of multiple systems in the West Texas / New Mexico area.

(2)    Mid-point of guidance.

(3)            Includes approximately 150,000 Bbl/d and 35,000 Bbl/d related to assets purchased from BP effective July 1, 2006 and July 31, 2006, respectively.

(4)    Includes approximately 40,000 Bbl/d related to assets we have agreed to purchase from Chevron Pipe Line Company with an estimated effective date of August 31, 2006.

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Segment profit is forecast using the volume assumptions in the table above, priced at tariff rates currently received, with adjustments where appropriate for estimated escalation in certain rates as allowed by contractual terms, less estimated field operating costs and G&A expenses. Field operating costs do not include depreciation. Effective July 1, 2006, common carrier tariffs are permitted to escalate approximately 6.15% in accordance with FERC regulated guidelines. However, in certain instances, contractual arrangements or market forces may not allow us to realize the benefit of these permitted increases.

To illustrate the impact volume changes may have on segment profit, the following table provides a volume sensitivity analysis of three systems representing approximately 27% of total pipeline net revenues.

 

3.                 Gathering, Marketing, Terminalling and Storage Operations.   The level of profit in the GMT&S segment is influenced by overall market structure and the degree of volatility in the crude oil market as well as variable operating expenses. Operating results for the three month periods ending September 30 and December 31, 2006 reflect an expected continuation of the current contango market and favorable market conditions generally consistent with the conditions experienced over most of 2005 and 2006 to date, although not quite as favorable as market conditions in the first six months of 2006. These market conditions are considered favorable relative to our asset base and business model. Unexpected changes in market structure or volatility (or lack thereof) could cause actual results to differ materially from forecasted results.

(1)            Mid-point of guidance.

Segment profit is forecast using the volume assumptions stated above and estimates of unit margins, field operating costs, G&A expenses and carrying costs for contango inventory based on current and anticipated market conditions. The forecast also includes the incremental profits from recently completed acquisitions. 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. Based on our mid-point projection of adjusted segment profit per barrel for calendar 2006, a 15,000 Bbl/d variance in lease gathering volumes would impact segment profit by approximately $5.1 million on an annualized basis. A $0.01 variance in the aggregate average per-barrel margin would impact segment profit by approximately $2.8 million on an annualized basis.

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4.                 Depreciation and Amortization.   Depreciation and amortization are forecast based on our existing depreciable assets and forecasted capital expenditures. Depreciation is computed using the straight-line method over estimated useful lives, which range from 3 years (for office property and equipment) to 40 years (for certain pipelines, crude oil terminals and facilities).

5.                 Statement of Financial Accounting Standards No. 133 “Accounting for Derivative Instruments and Hedging Activities” (SFAS 133).   The guidance presented above does not include assumptions or projections with respect to potential gains or losses related to derivatives accounted for under SFAS 133, as there is no accurate way to forecast these potential gains or losses. The potential gains or losses related to these derivatives (primarily mark-to-market adjustments) could cause actual net income to differ materially from our projections.

6.                 Acquisitions and Capital Expenditures.   As indicated in Note 2 (Pipeline Operations), this guidance includes assets we have agreed to purchase pursuant to definitive agreements with Chevron Pipe Line Company based on an estimated closing date of August 2006. Although acquisitions constitute a key element of our growth strategy, the forecasted results and associated estimates do not include any assumptions or forecasts for any other acquisition that may be made after the date hereof except for the pending acquisition. Capital expenditures for expansion projects are forecast to be approximately $275 million during calendar 2006 of which $104 million was incurred in the first six months of 2006. Following are some of the more notable projects to be undertaken in 2006 and the estimated expenditures for the year.

 

7.                 Capital Structure.   This guidance is based on our capital structure as of June 30, 2006 as adjusted to give effect to the sale in the third quarter of 3.7 million common units and the use of the proceeds of such sale to fund acquisitions, repay indebtedness under credit facilities and for general partnership

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purposes. The Partnership’s policy is to finance acquisitions and major growth capital projects with at least 50% equity or cash flow in excess of distributions.

8.                 Interest Expense.   Debt balances are projected based on estimated cash flows, current distribution rates, forecasted 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 expense for the six months ending December 31, 2006 is expected to be between $39.2 million and $40.8 million, assuming an average long-term debt balance of approximately $1.3 billion during the period and an all-in average rate of approximately 6.2%. Included in the effective cost of debt are projected interest payments, as well as commitment fees, amortization of long-term debt discounts, 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 International Petroleum Exchange margin deposits). At June 30, 2006, 96% of our long-term debt balance was fixed at an average interest rate of 6.1%. The amortization of deferred amounts associated with terminated interest rate hedges results in a non-cash component to interest expense of approximately $400,000 per quarter through September 2006, decreasing to approximately $100,000 per quarter thereafter until fully amortized over the next ten years. Interest expense does not include interest on borrowings for contango inventory. We treat those costs as carrying costs of crude oil and include it as part of the purchase price of crude oil.

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9.                 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. Under Emerging Issues Task Force Issue 03-06: Participating Securities and the Two-Class Method under FASB Statement No. 128 (“EITF 03-06”), when the Partnership’s aggregate net income exceeds the aggregate distribution made during such period, earnings per limited partner unit are calculated as if all of the earnings for the period were distributed, regardless of the pro forma nature of the allocation and whether those earnings would actually be distributed during a particular period from an economic or practical perspective. Although EITF 03-06 does not impact overall net income or other financial results of the Partnership, for periods in which aggregate net income exceeds the aggregate distributions for such period, earnings per limited partner unit will be reduced. The following table sets forth the computation of basic and diluted earnings per limited partner unit.

 

Net income allocated to limited partners is impacted by the income allocated to the general partner and the amount of the incentive distribution paid to the general partner. The amount of income allocated to our limited partnership interests is 98% of the total partnership income after deducting the amount of the general partner’s incentive distribution. Based on our current annualized distribution rate of $2.90 per unit and including 3.7 million units issued in the third quarter, our general partner’s distribution is forecast to be approximately $41.2 million annually, of which $36.4 million is attributed to the incentive distribution rights. The relative amount of the incentive distribution varies directionally with the number of units outstanding and the level of the distribution

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on the units. For distribution rates where EITF 03-06 does not apply, each $0.05 per unit annual increase in the distribution over $2.90 per unit decreases net income available for limited partners by approximately $4.0 million ($0.05 per unit) on an annualized basis.

10.          Long-term Incentive Plans.   Effective January 1, 2006 we adopted SFAS 123(R) Share-Based Payment, resulting in a cumulative effect of change in accounting principle gain of $6.3 million. The majority of phantom unit grants outstanding under our 1998 and 2005 Long-Term Incentive Plans contain vesting criteria that are based on a combination of performance benchmarks and service period. The majority of the phantom units awarded under the 2005 plan vest in various percentages on the later of 1) May 2007, May 2009, and May 2010, or 2) achievement of annualized distribution levels of $2.60, $2.80, $3.00, respectively, and for certain grants, $3.10 per unit. The majority of the phantom units have a final service period vesting in 2011. In addition to achieving the distribution level of $2.90, it has been deemed probable that the $3.10 distribution level will be achieved. Accordingly, guidance includes, for phantom units tied to performance levels of $3.10 or less, an accrual over the corresponding service period at an assumed market price of $45.00 per unit. For 2006, the guidance includes approximately $34.4 million of principally non-cash expense associated with these phantom units. The earliest significant vesting event for outstanding grants will occur in 2007.

The actual amount of LTIP expense amortization in any given year will be directly influenced by our unit price at the end of each reporting period and the amount of amortization in the early years as well as new unit grants. Therefore, actual net income could differ materially from our projections.

11.          Reconciliation of EBITDA and EBIT to Net Income.   The following table reconciles the 2006 guidance ranges for EBITDA and EBIT to net income.

		Guidance
		Three Months Ending								Three Months Ending								Twelve Months Ending
		September 30, 2006								December 31, 2006								December 31, 2006
		Low				High				Low				High				Low				High
		(in millions)
Reconciliation to Net Income
EBITDA			$106.0				$116.0				$106.4				$116.4				$432.3				$452.3
Depreciation and amortization			(24.8	)			(24.4	)			(25.8	)			(25.4	)			(93.5	)			(92.7	)
EBIT			81.2				91.6				80.6				91.0				338.8				359.6
Interest expense			(20.4	)			(19.6	)			(20.4	)			(19.6	)			(74.1	)			(72.5	)
Net Income			$60.8				$72.0				$60.2				$71.4				$264.7				$287.1

 

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” and similar expressions and statements regarding our business strategy, plans and objectives of our management for future operations. However, the absence of these words 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:

·       the success of our risk management activities;

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

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

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

·       declines in volumes shipped on the Basin Pipeline, Capline Pipeline and our other pipelines by us and third party shippers;

·       the availability of adequate third party production volumes for transportation and marketing in the areas in which we operate;

·       demand for natural gas or various grades of crude oil and resulting changes in pricing conditions or transmission throughput requirements;

·       fluctuations in refinery capacity in areas supplied by our transmission lines;

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

·       our access to capital to fund additional acquisitions and our ability to obtain debt or equity financing on satisfactory terms;

·       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 and volatility (or lack thereof);

·       the impact of current and future laws, rulings and governmental regulations;

·       the effects of competition;

·       continued creditworthiness of, and performance by, our counterparties;

·       interruptions in service and fluctuations in rates of 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;

·       the impact of crude oil and natural gas price fluctuations;

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

·       weather interference with business operations or project construction;

·       general economic, market or business conditions; and

·       other factors and uncertainties inherent in the marketing, transportation, terminalling, gathering and storage of crude oil and liquefied petroleum gas.

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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