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

Plains All American Pipeline, L.P.

(Exact name of registrant as specified in its charter)

DELAWARE		1-14569		76-0582150
(State or other jurisdiction		(Commission		(IRS Employer
of incorporation)		File Number)		Identification No.)

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 22, 2007

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 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 first quarter of calendar 2007 and the full year of calendar 2007. 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 First Quarter 2007 Guidance; Update of Full Year 2007 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 10 below, we reconcile EBITDA and EBIT to net income for the 2007 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 on Segment Profit, Net Income and Net Income per Basic and Diluted Limited Partner Unit.

     The following guidance for the three-month period ending March 31, 2007 and twelve-month period ending December 31, 2007 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, 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 February 21, 2007. We undertake no obligation to publicly update or revise any forward-looking statements.

Plains All American Pipeline, L.P.
Operating and Financial Guidance
(in millions, except per unit data)

			Guidance 1
			Three Months Ending								Twelve Months Ending
			March 31, 2007								December 31, 2007
			Low				High				Low				High
	Segment Profit
	Net revenues		$	336.6			$	346.0			$	1,310.2			$	1,340.3
	Field operating costs			(134.4	)			(132.4	)			(533.7	)			(526.2	)
	General and administrative expenses			(40.2	)			(39.6	)			(141.8	)			(139.4	)
				162.0				174.0				634.7				674.7
	Depreciation and amortization expense			(41.5	)			(41.0	)			(170.0	)			(168.0	)
	Interest expense, net			(41.5	)			(40.5	)			(168.0	)			(164.0	)
	Income tax expense			(0.6	)			(0.2	)			(1.7	)			(1.3	)
	Other Income (Expense)			-				-				-				-
	Net Income		$	78.4			$	92.3			$	295.0			$	341.4
	Net Income to Limited Partners		$	61.8			$	75.4			$	228.9			$	274.4
	Basic Net Income Per Limited Partner Unit:
	Weighted Average Units Outstanding			109.4				109.4				109.6				109.6
	Net Income Per Unit		$	0.56			$	0.69			$	2.09			$	2.50
	Diluted Net Income Per Limited Partner Unit:
	Weighted Average Units Outstanding			110.7				110.7				110.6				110.6
	Net Income Per Unit		$	0.56			$	0.68			$	2.07			$	2.48
	EBIT		$	120.5			$	133.0			$	464.7			$	506.7
	EBITDA		$	162.0			$	174.0			$	634.7			$	674.7
	Selected Items Impacting Comparability
	LTIP charge		$	(13.0	)		$	(13.0	)		$	(35.3	)		$	(35.3	)
	Excluding Selected Items Impacting Comparability
	Adjusted Segment Profit
	Transportation		$	77.0			$	81.0			$	330.0			$	342.0
	Facilities			23.0				25.0				112.0				120.0
	Marketing			75.0				81.0				228.0				248.0
	Adjusted EBITDA		$	175.0			$	187.0			$	670.0			$	710.0
	Adjusted Net Income		$	91.4			$	105.3			$	330.3			$	376.7
	Adjusted Basic Net Income per Limited Partner Unit		$	0.68			$	0.81			$	2.40			$	2.82
	Adjusted Diluted Net Income per Limited Partner Unit		$	0.67			$	0.80			$	2.38			$	2.79

Notes and Significant Assumptions:

1.

Definitions.

Bcf		Billion cubic feet
EBIT		Earnings before interest and taxes
EBITDA		Earnings before interest, taxes and depreciation and amortization expense
Bbls/d		Barrels per day
Segment Profit		Net revenues less purchases (including equity earnings, as applicable), 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.

Business Segments. Prior to the fourth quarter of 2006, we managed our operations through two segments. Due to our growth, especially in the facilities portion of our business (most notably in conjunction with our acquisition of Pacific Energy Partners, L.P. (“Pacific”)), we have revised the manner in which we internally evaluate our segment performance and decide how to allocate resources to our segments. As a result, we now manage our operations through three operating segments: (i) Transportation, (ii) Facilities, and (iii) Marketing.

	a.		Transportation. Our transportation segment operations generally consist of fee-based activities associated with transporting crude oil and refined products on pipelines and gathering systems. We generate revenue through a combination of tariffs, third-party leases of pipeline capacity, transportation fees, barrel exchanges and buy/sell arrangements. We also include in this segment our equity earnings from our investments in the Butte and Frontier pipeline systems, in which we own minority interests, and Settoon Towing, in which we own a 50% interest.
			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.
			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.

		2007 Guidance
		Three Months				Twelve Months
		Ending				Ending
		March 31				December 31
Average Daily Volumes (MBbls/d)
Crude Oil
All American			50				48
Basin			310				335
BOA / CAM			195				215
Capline			215				190
Line 63 / 2000			150				145
Salt Lake City			130				130
North Dakota / Trenton			95				90
West Texas / New Mexico area systems (1)			385				400
Manito			80				75
Other			870				912
			2,480				2,540
Refined Products			120				120
			2,600				2,660
Average Segment Profit ($/Bbl)
Excluding Selected Items Impacting Comparability		$	0.34	(2)		$	0.35	(2)

(1)		The aggregate of multiple systems in the West Texas / New Mexico area.
(2)		Mid-point of guidance.

Segment profit is forecast using the volume assumptions in the table above, priced at forecasted tariff rates, less estimated field operating costs and G&A expenses. Field operating costs do not include depreciation.

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 and LPG, 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. This segment also includes our equity earnings from our 50% investment in PAA/Vulcan Gas Storage, LLC which owns, and operates approximately 25.7 billion cubic feet of underground natural gas storage capacity and is constructing an additional 24 Bcf of underground storage capacity.

		Calendar 2007 Guidance
		Three Months				Twelve Months
		Ending				Ending
		March 31				December 31
Operating Data:
Crude Oil, Refined Products and LPG Storage (MMBbls/Month)			33.7				35.6
Natural Gas Storage, net (Bcf/Month)			12.9				13.4
LPG Processing (MBbl/d)			17.0				17.0
Facilities Activities Total — Average Capacity (MMBbls/Month)(1)			36.4				38.3
Average Segment Profit per Barrel ($/Bbl)
Excluding Selected Items Impacting Comparability			$0.22	(2)			$0.25	(2)

(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 gas to oil ratio; and iii) LPG processing volumes multiplied by the number of days in the month and divided by 1,000 to convert to monthly volumes in millions.
(2)		Mid-point of guidance.

			Segment profit is forecast using the volume assumptions in the table above, priced at forecasted rates, less estimated field operating costs and G&A expenses. Field operating costs do not include depreciation.
	c.		Marketing. Our marketing segment operations generally consist of the following merchant activities:

		•	the purchase of U.S. and Canadian crude oil at the wellhead and the bulk purchase of crude oil at pipeline and terminal facilities, as well as of foreign cargoes at their load port and various other locations in transit;
		•	storage of inventory during contango market conditions;
		•	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
		•	arranging for 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 marketing 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, 2007 reflect an expected continuation of the current contango market and favorable market conditions (relative to our asset base and business model) generally consistent with the conditions experienced in the fourth quarter of 2006, and a moderately strong market structure for the remaining three quarters of 2007. Unexpected changes in market structure or volatility (or lack thereof) could cause actual results to differ materially from forecasted results.

		Calendar 2007 Guidance
		Three Months				Twelve Months
		Ending				Ending
		March 31				December 31
Average Daily Volumes (MBbls/d)
Crude Oil Lease Gathering			670				670
LPG Sales			125				110
Waterborne foreign crude imported			70				90
			865				870
Average Segment Profit per Barrel ($/Bbl)
Excluding Selected Items Impacting Comparability		$	1.00	(1)		$	0.75	(1)

(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. 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.

3.		Depreciation and Amortization. Depreciation and amortization are forecast based on our existing depreciable assets, forecasted capital expenditures, and projected in-service dates. Depreciation is computed using the straight-line method over estimated useful lives, which range from 3-years (for office furniture and equipment) to 40-years (for certain pipelines, crude oil terminals and facilities).
4.		Statement of Financial Accounting Standards No. 133 “Accounting for Derivative Instruments and Hedging Activities,” as amended (“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.
5.		Capital Expenditures and Acquisitions. 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 acquisition that may be made after the date hereof. Capital expenditures for expansion projects are forecasted to be approximately $500 million during calendar 2007. Following are some of the more notable projects and projected expenditures for the year:

		Calendar 2007
		(in millions)
Expansion Capital
•  St. James, Louisiana storage facility		$	75
•  Salt Lake City Expansion			55
•  Patoka Tankage			40
•  Cheyenne Pipeline			34
•  Martinez Terminal			27
•  Cushing Tankage — Phase VI			27
•  Paulsboro Expansion			20
•  West Hynes Tanks			15
•  Kerrobert Tankage			14
•  Fort Laramie Tank Expansion			12
•  High Prairie Rail Terminal			11
•  Pier 400			10
•  Other Projects			160
			500
Maintenance Capital			45
Total Projected Capital Expenditures (excluding acquisitions)		$	545

6.		Capital Structure. This guidance is based on our capital structure as of December 31, 2006. 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. As a result of our 2006 equity financing activities in combination with our projected 2007 cash flow in excess of distributions, we have substantially pre-funded the required equity financing associated with our 2007 expansion capital program.
7.		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.
		Annual 2007 interest expense is expected to be between $164 million and $168 million, assuming an average long-term debt balance of approximately $2.8 billion during the period. Included in the effective cost of debt are projected interest payments, as well as 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 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.

8.

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.

		Guidance (in millions, except per unit data)
		Three Months Ending								Twelve Months Ending
		March 31, 2007								December 31, 2007
		Low				High				Low				High
Numerator for basic and diluted earnings per limited partner unit:
Net Income		$	78.4			$	92.3			$	295.0			$	341.4
General partner’s incentive distribution			(20.3	)			(20.3	)			(81.5	)			(81.5	)
General partner’s incentive distribution reduction			5.0				5.0				20.0				20.0
			63.1				77.0				233.5				279.9
General partner 2% ownership			(1.3	)			1.5				(4.7	)			(5.6	)
Net Income available for limited partners		$	61.8			$	75.4			$	228.9			$	274.3
Denominator:
Denominator for basic earnings per limited partner unit-weighted average number of limited partner units			109.4				109.4				109.6				109.6
Effect of dilutive securities:
Weighted average LTIP units			1.3				1.3				1.0				1.0
Denominator for diluted earnings per limited partner unit-weighted average number of limited partner units			110.7				110.7				110.6				110.6
Basic net income per limited partner unit		$	0.56			$	0.69			$	2.09			$	2.50
Diluted net income per limited partner unit		$	0.56			$	0.68			$	2.07			$	2.48

		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 $3.20 per unit, our general partner’s distribution is forecast to be approximately $87.1 million annually, of which $81.5 million is attributed to the incentive distribution rights. However, in conjunction with the Pacific acquisition, the general partner agreed to reduce the amounts due it as incentive distributions. The reduction will be effective for five years, as follows: (i) $5 million per quarter for the first four quarters, (ii) $3.75 million per quarter for the next eight quarters, (iii) $2.5 million per quarter for the next four quarters, and (iv) $1.25 million per quarter for the final four quarters. The total reduction in incentive distributions will be $65 million. As such, total incentive distributions to the general partner in 2007 will be reduced by $20.0 million. The relative amount of the incentive distribution varies directionally with the number of units outstanding and the level of the distribution on the units. Each $0.05 per unit annual increase in the distribution over $3.20 per unit decreases net income available for limited partners by approximately $5.4 million ($0.05 per unit) on an annualized basis.
9.		Long-term Incentive Plans. The majority of grants outstanding under our Long-Term Incentive Plans 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, vesting dates range from May 2007 to May 2012 and minimum annualized distribution levels range from $2.60 to $4.00. For some awards, a percentage of any remaining units will vest on a date certain in 2011 or 2012.
		We have reached the annualized distribution level of $3.20 and, accordingly, for grants that vest at annualized distribution levels of $3.20 or less, guidance includes an accrual over the corresponding service period at an assumed market price of $53.80 per unit as well as the fair value associated with awards that will vest on a date certain. For 2007, the guidance includes approximately $35.3 million of expense associated with these grants. The next annualized distribution threshold that would affect the vesting accrual is $3.50 and at this time, it has not been deemed probable. If achievement of the $3.50 performance threshold is deemed probable at any point during 2007, then the total LTIP charge for 2007 would increase by approximately $7.7 million, all other factors remaining constant.
		In May 2007, we anticipate that approximately 0.7 million units will vest totaling $37.8 million using the assumed $53.80 unit price above.
		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.
10.		Reconciliation of EBITDA and EBIT to Net Income. The following table reconciles the 2007 guidance ranges for EBITDA and EBIT to net income.

		Guidance
		Three Months Ending								Twelve Months Ending
		March 31, 2007								December 31, 2007
		Low				High				Low				High
		(in millions)
Reconciliation to Net Income
EBITDA		$	162.0			$	174.0			$	634.7			$	674.7
Depreciation and amortization			41.5				41.0				170.0				168.0
EBIT			120.5				133.0				464.7				506.7
Interest expense			41.5				40.5				168.0				164.0
Income tax expense			0.6				0.2				1.7				1.3
Net Income		$	78.4			$	92.3			$	295.0			$	341.4

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. 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 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:

•		our failure to successfully integrate the business operations of Pacific or our failure to successfully integrate any future acquisitions;
•		the failure to realize the anticipated cost savings, synergies and other benefits of the merger with Pacific;
•		the success of our risk management activities;
•		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 and trade counterparties;
•		abrupt or severe declines or interruptions in outer continental shelf production located offshore California and transported on our pipeline systems;
•		failure to implement or capitalize on planned internal growth projects;
•		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;
•		fluctuations in refinery capacity in areas supplied by our main lines and other factors affecting demand for various grades of crude oil, refined products and natural gas and resulting changes in pricing conditions or transmission throughput requirements;
•		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 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;
•		the currency exchange rate of the Canadian dollar;
•		shortages or cost increases of power supplies, materials or labor;
•		weather interference with business operations or project construction;
•		risks related to the development and operation of natural gas storage facilities;
•		general economic, market or business conditions; 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.

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: February 22, 2007		By:		/s/ PHIL KRAMER
				Name: Phil Kramer
				Title: Executive Vice President and Chief Financial Officer

INDEX TO EXHIBITS

Exhibit No.		Description
99.1		Press release dated February 22, 2007

 

Exhibit 99.1

 

 

 

 

FOR IMMEDIATE RELEASE

 

Plains All American Pipeline, L.P.
Reports Strong 2006 Results

 

(Houston — February 22, 2007) Plains All American Pipeline, L.P. (NYSE: PAA) today reported net income of $46.0 million, or $0.36 per diluted limited partner unit, for the fourth quarter 2006 and net income of $285.1 million, or $2.88 per diluted limited partner unit, for the full year 2006. Net income for the fourth quarter 2005 was $53.7 million, or $0.64 per diluted limited partner unit, and net income for the full year 2005 was $217.8 million or $2.72 per diluted unit. Comparisons with prior year periods were impacted by selected items impacting comparability in each period. (See table entitled “Selected items impacting comparability” below.)

 

The Partnership reported earnings before interest, taxes, depreciation and amortization (“EBITDA”) of $111.5 million for the fourth quarter of 2006, which represents an increase of 18% compared with EBITDA of $94.1 million for the fourth quarter of 2005. EBITDA for the full year 2006 was $470.2 million, an increase of 30% over 2005 reported EBITDA of $360.7 million. All reported results include the effect of the merger with Pacific Energy Partners, L.P., from the closing date of November 15, 2006. (See the section of this release entitled “Non-GAAP Financial Measures” and the attached tables for discussion of EBITDA and other non-GAAP financial measures, and reconciliations of such measures to the comparable GAAP measures.)

 

“2006 was a very active, productive and rewarding year for the Partnership,” said Greg L. Armstrong, Chairman and CEO of Plains All American. “We achieved or exceeded each of our stated goals, executed a record level of internal growth projects and completed the largest acquisition in Partnership history. In addition, we completed the transformation from an entity that in 2001 was primarily dependent on acquisitions for growth, to one that has a high-quality backlog of expansion projects across a diversified and complementary suite of businesses, which we expect to fuel our growth for the next several years, irrespective of future acquisitions.”

 

Armstrong also noted that Plains All American invested nearly $3.4 billion during the year, increased distributions paid to unitholders by 11.5% and, as a result of its disciplined and proactive financing activities, exited 2006 with a strong balance sheet and capital structure and the highest level of liquidity in its history.

 

Reported results include the impact of various items that affect comparability between reporting periods. Adjusted results exclude selected items impacting comparability, as further described in the table below. Accordingly, the Partnership’s fourth quarter 2006 adjusted net income, adjusted net income per diluted limited partner unit and adjusted EBITDA were $80.8 million, $0.72 and $146.3 million, respectively. The Partnership’s fourth quarter 2005 adjusted net income, adjusted net income per diluted limited partner unit and adjusted EBITDA were $62.6 million, $0.75 and $103 million, respectively. On a comparable basis, fourth quarter 2006 adjusted net income and adjusted EBITDA increased 29% and 42%, respectively, over the corresponding metrics for the fourth quarter 2005, while adjusted net income per diluted limited partner unit decreased approximately 4% between the periods.

 

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The Partnership’s adjusted net income, adjusted net income per diluted limited partner unit and adjusted EBITDA for the full year 2006 were $325.9 million, $3.50 and $511 million, respectively. These same metrics for 2005 were $264.9 million, $3.47 and $407.8 million, respectively. On a comparative basis, 2006 adjusted net income, adjusted net income per diluted limited partner unit and adjusted EBITDA increased 23%, 1% and 25%, respectively, over 2005. Armstrong also noted that the Partnership met or exceeded the guidance that it provided via Form 8-K on November 2, 2006 for adjusted net income, adjusted net income per diluted unit and adjusted EBITDA.

 

The following table summarizes selected items that the Partnership believes impact comparability of financial results between reporting periods:

 

 

 

 

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Effective with the fourth quarter of 2006, the Partnership began reporting its segment results in three segments, which include Transportation, Facilities and Marketing. Information for prior annual and quarterly periods has been conformed to the three segment presentation. The following tables present certain selected financial information by segment for the fourth quarter and full year reporting periods:

 

 

 

 

 

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Excluding selected items impacting comparability, segment profit from Transportation operations in the fourth quarter of 2006 was $62.9 million representing a 41% increase over fourth quarter 2005 results of $44.5 million. For the full 2006 year, adjusted segment profit for Transportation operations was $221.0 million which is a 22% increase as compared with full year 2005 results of $181.1. Transportation volumes for the fourth quarter of 2006 were approximately 2.5 million barrels per day versus 1.8 million barrels per day in the 2005 quarter.

 

Fourth quarter and full year 2006 Facilities operations adjusted segment profit of $17.3 million and $40.4 million represent respective increases of 246% and 132% over comparable 2005 metrics.

 

Marketing operations adjusted segment profit of $65.8 million and $248.5 million for the fourth quarter and full year 2006 represent increases of 24% and 19%, respectively, over corresponding metrics for 2005.

 

The Partnership’s basic weighted average units outstanding for the fourth quarter 2006 totaled 93.2 million (94.3 million diluted) as compared to 73.7 million (75.3 million diluted) in last year’s fourth quarter. At December 31, 2006, the Partnership had approximately 109.4 million units outstanding, long-term debt of approximately $2.6 billion and a long-term debt-to-total capitalization ratio of 47%.

 

On February 14, 2007, the Partnership paid a cash distribution of $0.80 per unit ($3.20 per unit on an annualized basis) on its outstanding limited partner units. The distribution represents an increase of approximately 16.4% over the distribution paid in February 2006 and approximately 6.7% over the distribution paid in November 2006. This represents the 11th consecutive increase in quarterly distributions for the Partnership and the 18th increase in the last twenty-four quarters.

 

The Partnership will furnish a current report on Form 8-K, which will include material in this press release and financial and operational guidance for the first quarter and full year 2007. A copy of the Form 8-K will be available on the Partnership’s website at www.paalp.com.

 

Non-GAAP Financial Measures

 

In this release, the Partnership’s EBITDA disclosure is not presented in accordance with generally accepted accounting principles and is not intended to be used in lieu of GAAP presentations of net income or cash flows from operating activities. EBITDA is presented because we believe it provides additional information with respect to both the performance of our fundamental business activities as well as 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 present selected items that impact the comparability of our operating results as additional information that may be helpful to your understanding of our financial results. We consider an understanding of these selected items impacting comparability to be material to our evaluation of our operating results and prospects. Although we present selected items that we consider in evaluating our performance, you should also be aware that the items presented do not represent all items that affect comparability between the periods presented. Variations in our operating results are also caused by changes in volumes, prices, exchange rates, mechanical interruptions, acquisitions and numerous other factors. These types of variations are not separately identified in this release, but will be discussed in management’s discussion and analysis of operating results in our Annual Report on Form 10-K.

 

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A reconciliation of EBITDA to net income and cash flows from operating activities for the periods presented is included in the tables attached to this release. In addition, the Partnership maintains on its website (www.paalp.com) a reconciliation of all non-GAAP financial information, such as EBITDA, that it reconciles to the most comparable GAAP measures. To access the information, investors should click on the “Investor Relations” link on the Partnership’s home page and then the “Non-GAAP Reconciliation” link on the Investor Relations page.

 

Conference Call

 

The Partnership will host a conference call on Friday, February 23, 2007 to discuss the following items:

 

1. The Partnership’s fourth quarter and 2006 performance;

 

2. The status of the Pacific integration, major expansion projects and recent acquisition activity;

 

3. Capitalization and liquidity;

 

4. Financial and operating guidance for the first quarter and full year 2007; and

 

5. The Partnership’s outlook for the future.

 

The call will begin at 10:00 AM (Central). To participate in the call, please dial 877-709-8150, or, for international callers, 201-689-8354, at approximately 9:55 AM (Central). No password or reservation number is required.

 

Webcast Instructions

 

To access the Internet webcast, please go to the Partnership’s website at www.paalp.com, choose “Investor Relations,” and then choose “Conference Calls.” Following the live webcast, the call will be archived for a period of sixty (60) days on the Partnership’s website.

 

Telephonic Replay Instructions

 

To listen to a telephonic replay of the conference call, please dial 877-660-6853, or, for international callers, 201-612-7415, and enter account # 232 and replay # 228179. The replay will be available beginning Friday, February 23, 2007, at approximately 1:00 PM (Central) and continue until 10:59 PM (Central) Wednesday, February 28, 2007.

 

Plains All American Pipeline, L.P. is a publicly traded master limited partnership engaged in the transportation, storage, terminalling and marketing of crude oil, refined products and liquefied petroleum gas and other natural gas related petroleum products. Through its 50% ownership in PAA/Vulcan Gas Storage LLC, the partnership also develops and operates natural gas storage facilities. The Partnership is headquartered in Houston, Texas, and its common units are traded on the New York Stock Exchange under the symbol “PAA.”

 

Forward Looking Statements

 

Except for the historical information contained herein, the matters discussed in this news release are forward-looking statements that involve certain risks and uncertainties that could cause actual results to differ materially from results anticipated in the forward-looking statements. These risks and uncertainties include, among other things: our failure to successfully integrate the business operations of Pacific Energy or our failure to successfully integrate any future acquisitions; the failure to realize the anticipated cost savings, synergies and other benefits of the merger with Pacific Energy; the success of our risk management activities; 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 and trade counterparties; abrupt or severe declines or interruptions in outer continental shelf production located offshore California and transported on our pipeline system; failure to implement or capitalize on planned internal growth projects; the availability of adequate third party production

 

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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; fluctuations in refinery capacity in areas supplied by our main lines and other factors affecting demand for various grades of crude oil, refined products and natural gas and resulting changes in pricing conditions or transmission throughput requirements; 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 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; the currency exchange rate of the Canadian dollar; shortages or cost increases of power supplies, materials or labor; weather interference with business operations or project construction; risks related to the development and operation of natural gas storage facilities; general economic, market or business conditions; 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 discussed in the Partnership’s filings with the Securities and Exchange Commission.

 

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
FINANCIAL SUMMARY (unaudited)

 

CONSOLIDATED STATEMENTS OF OPERATIONS

(In millions, except per unit data)

 

 

 

 

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
FINANCIAL SUMMARY (unaudited)

 

OPERATING DATA⁽¹⁾

(In thousands)

 

 

 

 

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
FINANCIAL SUMMARY (unaudited)

 

CONDENSED CONSOLIDATED BALANCE SHEET DATA

(In millions)

 

 

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

FINANCIAL SUMMARY (unaudited)

 

COMPUTATION OF BASIC AND DILUTED EARNINGS PER LIMITED PARTNER UNIT

(in millions, except per unit data)

 

 

 

 

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

FINANCIAL SUMMARY (unaudited)

 

 

FINANCIAL DATA RECONCILIATIONS
(in millions, except per unit data)