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)—April 28, 2005

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

(c)          Exhibit 99.1—Press Release dated April 28, 2005

Item 2.02 and 7.01.   Regulation FD Disclosure; Results of Operations and Financial Condition

Plains All American Pipeline, L.P. (the “Partnership”) today issued a press release reporting its first quarter 2005 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. We are also furnishing pursuant to Item 7.01 its projections of certain operating and financial results for the second quarter of 2005 and modifying certain aspects of our previous guidance for financial performance for the full year of calendar 2005. In accordance with General Instruction B.2. of Form 8-K, the information presented herein under Item 7.01 shall not be deemed “filed” for purposes of Section 18 of the Securities 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 Second Quarter 2005 Estimates; Update of Full Year 2005 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 periods presented. We also 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 on EBITDA, Net Income and Net Income per limited partner unit of our long-term incentive program, potential future revaluations of foreign currency and, to the extent known, gains and losses related to SFAS 133 (primarily non-cash, mark-to-market adjustments).

The following guidance for the three months ending June 30, 2005 and the six months and twelve months ending December 31, 2005 is 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 and also include projections for several recent acquisitions, 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 April 27, 2005. 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)

		Actual					Guidance(1)
		Three Months					Three Months Ended										Six Months Ended										Twelve Months Ended
		Ended					June 30, 2005										December 31, 2005										December 31, 2005
		March 31, 2005					Low					High					Low					High					Low					High
Pipeline Operations
Net revenues			$	95.5				$	91.0				$	93.5				$	189.4				$	190.4				$	375.9				$	379.4
Field operating costs			(34.1		)			(35.6		)			(34.4		)			(73.1		)			(71.7		)			(142.8		)			(140.2		)
General and administrative expenses			(11.3		)			(12.8		)			(12.1		)			(26.3		)			(25.3		)			(50.4		)			(48.7		)
			50.1					42.6					47.0					90.0					93.4					182.7					190.5
Gathering, Marketing, Terminalling & Storage Operations
Net revenues			56.8					74.0					76.5					126.4					128.7					257.2					262.0
Field operating costs			(29.7		)			(29.0		)			(28.4		)			(60.5		)			(59.6		)			(119.2		)			(117.7		)
General and administrative expenses			(10.8		)			(11.2		)			(10.7		)			(21.6		)			(21.2		)			(43.6		)			(42.7		)
			16.3					33.8					37.4					44.3					47.9					94.4					101.6
Segment Profit			66.4					76.4					84.4					134.3					141.3					277.1					292.1
Depreciation and amortization expense			(19.1		)			(19.1		)			(18.8		)			(39.5		)			(38.8		)			(77.7		)			(76.7		)
Interest expense			(14.6		)			(14.9		)			(14.5		)			(32.8		)			(32.2		)			(62.3		)			(61.3		)
Other Income (Expense)			0.1					—					—					—					—					0.1					0.1
Net Income			$	32.8				$	42.4				$	51.1				$	62.0				$	70.3				$	137.2				$	154.2
Net Income to Limited Partners			$	29.3				$	38.1				$	46.6				$	53.9				$	62.0				$	121.4				$	138.0
Basic:
Weighted Average Units Outstanding			67.5					67.9					67.9					67.9					67.9					67.9					67.9
Net Income Per Limited Partner Unit			$	0.43				$	0.56				$	0.69				$	0.79				$	0.91				$	1.79				$	2.03
Diluted:
Weighted Average Units Outstanding			68.2					69.3					69.3					69.3					69.3					69.1					69.1
Net Income Per Limited Partner Unit			$	0.43				$	0.55				$	0.67				$	0.78				$	0.90				$	1.76				$	2.00
EBIT			$	47.4				$	57.3				$	65.6				$	94.8				$	102.5				$	199.5				$	215.5
EBITDA			$	66.5				$	76.4				$	84.4				$	134.3				$	141.3				$	277.2				$	292.2
Selected Items Impacting Comparability
LTIP charge			$	(2.2	)			$	(5.6	)			$	(5.6	)			$	(10.8	)			$	(10.8	)			$	(18.6	)			$	(18.6	)
FAS 133 non-cash mark-to-market adjustment			(13.4		)			—					—					—					—					(13.4		)			(13.4		)
FX gain (loss)			(0.8		)			—					—					—					—					(0.8		)			(0.8		)
			$	(16.5	)			$	(5.6	)			$	(5.6	)			$	(10.8	)			$	(10.8	)			$	(32.8	)			$	(32.8	)
Excluding Selected Items Impacting Comparability
Adjusted EBITDA			$	82.9				$	82.0				$	90.0				$	145.1				$	152.1				$	310.0				$	325.0
Adjusted Net Income			$	49.3				$	48.0				$	56.7				$	72.8				$	81.1				$	170.0				$	187.0
Adjusted Basic Net Income per Limited Partner Unit			$	0.67				$	0.64				$	0.77				$	0.95				$	1.07				$	2.26				$	2.51
Adjusted Diluted Net Income per Limited Partner Unit			$	0.67				$	0.63				$	0.75				$	0.93				$	1.05				$	2.22				$	2.46

(1)    The projected average foreign exchange rate is $1.25 CAD to $1 USD

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Notes and Significant Assumptions:

1.                 Definitions.

EBIT		Earnings before interest and taxes
EBITDA		Earnings before interest, taxes and depreciation and amortization expense
Bbl/d		Barrels per day
Segment Profit		Net revenues less purchases, field operating costs, and segment general and administrative expenses
LTIP		Long-Term Incentive Plan
LPG		Liquefied petroleum gas and other petroleum products
FX		Foreign currency exchange

 

2.                 Pipeline Operations.   Pipeline volume estimates are based on historical and anticipated future operating performance. Actual segment profit could vary materially depending on the level of volumes transported. The following table summarizes our pipeline volumes and breaks out the major systems that are significant either in total volumes transported or in contribution to total net revenue.

		Calendar 2005
		Actual				Guidance
		Three Months				Three Months				Six Months				Twelve Months
		Ended				Ended				Ended				Ended
		March 31				June 30				December 31				December 31
Average Daily Volumes (000’s Bbl/d)
All American			54				54				54				54
Basin			277				292				280				282
Capline			160				157				132				145
Cushing to Broome			23				76				80				66
West Texas / New Mexico area systems(1)			401				384				381				387
Other			546				561				555				551
			1,461				1,524				1,482				1,487
Canada(2)			268				266				268				268
			1,729				1,790				1,750				1,755

(1)    The aggregate of 10 systems in the West Texas / New Mexico area.

(2)    The aggregate of 7 systems.

Average volumes for the second quarter are expected to be in the range of 1,790,000 Bbl/d, compared to an average 1,729,000 Bbl/d for the three months ended March 31. The volume growth for the second quarter and the year is driven primarily by the start-up of the Cushing to Broome pipeline system late in the first quarter, which is expected to exit the year at 80,000 Bbl/d.

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Net revenues were forecasted 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. To illustrate the impact volume changes may have on segment profit, the following table provides a volume sensitivity analysis of three systems representing approximately 30% of total pipeline net revenues.

Volume Sensitivity Analysis
												Increase /
				Increase /				% of				(Decrease)
				(Decrease)				System				in Annualized
System				in Volume				Total				Segment Profit
				(Bbls/d)								(in millions)
All American					5,000				9	%			$	3.2
Basin					20,000				7	%			1.7
Capline					10,000				6	%			1.4

 

3.                 Gathering, Marketing, Terminalling and Storage Operations.   The degree of price volatility in the crude oil market influences the level of profit in the GMT&S segment. As a result of the higher volatility experienced during the first four months of 2005, segment profit in the first six months of 2005 is currently expected to be higher than the last half of 2005 based on the expectation of volatility returning to historical levels. Volumes from crude oil lease gathering are projected to average 630,000 Bbl/d in the second quarter and increase to an average of 640,000 Bbl/d for the last half of the year. LPG volumes are influenced by seasonal demands with volumes decreasing during the summer months. As such, second quarter volumes are expected to average 24,000 Bbl/d versus the annual average of 54,000 Bbl/d.

		Calendar 2005
		Actual				Guidance
		Three Months				Three Months				Six Months				Twelve Months
		Ended				Ended				Ended				Ended
		March 31				June 30				December 31				December 31
Average Daily Volumes (000’s Bbl/d)
Crude Oil Lease Gathering			622				630				640				633
LPG			84				24				54				54
			706				654				694				687

 

Segment profit is forecast using the volume assumptions stated above and estimates of unit margins, operating expenses and G&A based on current and anticipated market conditions. 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 projected segment profit per barrel for the second quarter of 2005, a 15,000 Bbl/d variance in lease gathering volumes would impact segment profit by an approximate $4.3 million on an annualized basis. A $0.01 variance in the aggregate average per-barrel margin would impact segment profit by an approximate $2.4 million on an annualized basis.

4.                 Depreciation & Amortization.   Depreciation and amortization is forecast based on our existing depreciable assets and forecast 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 50 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 forecast presented above does not include assumptions or projections with respect to potential gains or losses related to SFAS 133, as there is no accurate way to forecast these potential gains or losses. The potential gains or losses related to SFAS 133 (primarily

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non-cash, mark-to-market adjustments) could cause actual net income to differ materially from our projections.

6.                 Acquisitions and Capital Expenditures.   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 material acquisition that may be made after the date hereof. Capital expenditures for expansion projects are forecast to be approximately $120 million during calendar 2005, a $20 million increase over the original guidance. This increase is primarily due to additional expenditures on the Trenton system which will expand the system by 70 miles and add 18,000 barrels per day of capacity and 14,000 barrels per day of gathering volumes. Following are some of the more notable projects and estimated expenditures for 2005.

·        Trenton pipeline expansion—$34 million,

·        Capital projects associated with the Link acquisition—$18 million,

·        NW Alberta fractionator—$16 million.

·        Cushing Phase V expansion—$13 million, and

·        Shell South Louisiana Asset Acquisition—$8 million.

For the three months ended March 31, 2005, approximately $45 million of the forecasted $120 million of expansion capital was incurred in accordance with the project commitments.

Capital expenditures for maintenance projects are forecast to be approximately $19 million during 2005, of which approximately $4 million was incurred in the first quarter.

7.      Capital Structure.   The guidance is based on our capital structure as of March 31, 2005, except for the projected issuance of approximately 50,000 units to satisfy equity grants issued under the 1998 LTIP plan, and does not include any debt or equity issuances associated with acquisitions or significant capital expenditures not included in our guidance for the remainder of 2005. The crude oil market has been and is expected to continue to be volatile. In preparation for potentially higher crude oil prices and to maintain significant liquidity in such an environment, we are currently considering various transactions to increase our liquidity and financial flexibility to insure that we are well positioned to capitalize on associated opportunities in such higher priced environment. Accordingly, the foregoing financial results and per unit estimates may be impacted by future capital markets activities, depending on the timing and the terms of any debt or equity that we might issue.

8.                 Interest Expense.   Debt balances are projected based on estimated cash flows, current distribution rates, capital expenditures for maintenance and expansion projects, planned sales of surplus equipment, expected timing of collections and payments, and forecast levels of inventory and other working capital sources and uses.

Calendar 2005 interest expense is expected to be between $61.3 million and $62.3 million assuming an average long-term debt balance of approximately $990 million and an all-in average rate of approximately 6.2%. While interest on floating rate debt is based on a forward one-year LIBOR index curve of 3.5%, approximately 80% of our projected average debt balance has an average fixed interest rate of 6.0%. Included in the effective cost of debt are not only current cash payments, but also commitment fees, amortization of long-term debt discounts, and deferred amounts associated with terminated interest rate hedges. The amortization of deferred amounts associated with terminated interest rate hedges results in a non-cash component to interest expense of approximately $1.6 million per year (approximately $400,000 per quarter). Approximately 73% of these deferred amounts will be

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completely amortized by the fourth quarter of 2006. The remainder will be amortized over the next nine years.

Long-term debt at December 31, 2005 is projected to be approximately $1.03 billion.

9.                 Net Income per Unit.   Basic net income per limited partner unit is calculated by dividing the net income allocated to limited partners by the basic weighted average units outstanding during the period. Basic weighted average units outstanding are projected to average approximately 67.9 million units for 2005.

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. Accordingly, for each $0.05 per unit annual increase in the distribution rate up to $2.70 per unit, net income available for limited partners decreases approximately $1.0 million ($0.02 per unit) on an annualized basis. 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 $2.55 per unit, our general partner’s distribution is forecast to be approximately $17.5 million annually, of which $14.0 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 on the units.

10.          Long-term Incentive Plans.   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 phantom units under the 2005 plan generally vest on the later of 2 years, 4 years or 5 years, or achievement of annualized distribution levels of $2.60, $2.80 and $3.00 per unit, respectively, and the majority of the phantom units have a final service period vesting in 2011. Accordingly, guidance includes 1) for phantom units tied to the $2.60 performance level, an accrual over the corresponding service period, generally 2 years, as it has been deemed probable that the $2.60 performance level will be reached, and 2) for the phantom units that are not tied to the $2.60 performance threshold but have a final service period vesting in 2011, a pro rata accrual associated with a six-year service period.  For 2005, the guidance includes approximately $18.4 million of principally non-cash expense associated with these phantom units. The actual amount of LTIP expense amortization in any given year will be directly influenced by fluctuations in our unit price and the amount of amortization in the early years and will also be increased if a determination is made that achievement of any of the remaining performance thresholds is probable.

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

		Guidance
		Three Months Ended										Twelve Months Ended
		June 30, 2005										December 31, 2005
		Low					High					Low					High
		(in millions)
Reconciliation to Net Income
EBITDA			$	76.4				$	84.4				$	277.2				$	292.2
Depreciation and amortization			19.1					18.8					77.7					76.7
EBIT			57.3					65.6					199.5					215.5
Interest expense			14.9					14.5					62.3					61.3
Net Income			$	42.4				$	51.1				$	137.2				$	154.2

 

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Forward-Looking Statements and Associated Risks

All statements, other than statements of historical fact, included in this report 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. 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:

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

·       the success of our risk management activities;

·       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;

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

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

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

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

·       successful third-party drilling efforts in areas in which we operate pipelines or gather crude oil;

·       demand for 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 effects of competition;

·       continued creditworthiness of, and performance by, counterparties;

·       the impact of crude oil price fluctuations;

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

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

·       weather interference with business operations or project construction;

·       the currency exchange rate of the Canadian dollar;

·       fluctuations in the debt and equity markets, including the price of our units at the time of vesting under our LTIP plan; and

·       general economic, market or business conditions.

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.

	PLAINS ALL AMERICAN PIPELINE, L.P.
	By:	PLAINS AAP, L. P., its general partner
	By:	PLAINS ALL AMERICAN GP LLC,  its general partner
Date: April 28, 2005	By:	/s/ PHIL KRAMER
		Name:	Phil Kramer
		Title:	Executive Vice President and Chief Financial Officer

 

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