8-K

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)—February 23, 2006

Plains All American Pipeline, L.P.

(Exact name of registrant as specified in its charter)

DELAWARE	1-14569	76-0582150
(State or other jurisdiction of incorporation)	(Commission File Number)	(IRS Employer 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:

oWritten communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

oSoliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

oPre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

oPre-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 23, 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 fourth quarter and annual 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. Pursuant to Item 7.01 we are providing detail guidance for financial performance for the first quarter of calendar 2006 and the full year of calendar 2006 (which supersedes preliminary guidance in our 8-K furnished on October 27, 2005). 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 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 guidance periods presented. However, it is impractical to reconcile EBIT and EBITDA to cash flows from operating activities for forecasted periods. 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 of our long-term incentive program on EBITDA, Net Income and Net Income per Limited Partner Unit.

The following guidance for the three months ending March 31, 2006 and the twelve months 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 February 22, 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)

	Guidance(1)
	Three Months Ending						Twelve Months Ending
	March 31, 2006						December 31, 2006
	Low			High			Low			High
Pipeline
Net revenues	$	92.0		$	95.5		$	390.4		$	398.7
Field operating costs	(46.0		)	(45.1		)	(182.8		)	(180.7		)
General and administrative expenses	(12.4		)	(12.2		)	(46.4		)	(45.6		)
	33.6			38.2			161.2			172.4
Gathering, Marketing, Terminalling & Storage
Net revenues	103.7			108.1			356.1			371.4
Field operating costs	(33.3		)	(32.6		)	(131.1		)	(129.2		)
General and administrative expenses	(19.4		)	(19.1		)	(73.1		)	(71.9		)
	51.0			56.4			151.9			170.3
Total Segment Profit	84.6			94.6			313.1			342.7
Depreciation and amortization expense	(21.4		)	(21.0		)	(89.2		)	(87.7		)
Interest expense	(15.5		)	(14.8		)	(64.7		)	(61.7		)
Equity Earnings (Loss) in PAA/Vulcan Gas Storage, LLC	—			—			2.3			2.7
Income Before Cumulative Effect of Change in Accounting Principle	47.7			58.8			161.5			196.0
Cumulative Effect of Change in Accounting Principle	6.4			6.4			6.4			6.4
Net Income	$	54.1		$	65.2		$	167.9		$	202.4
Net Income to Limited Partners	$	47.6		$	58.4		$	142.7		$	176.5
Basic Net Income Per Limited Partner Unit
Weighted Average Units Outstanding	73.8			73.8			73.8			73.8
Net Income per Unit	$	0.64		$	0.74		$	1.93		$	2.39
Diluted Net Income Per Limited Partner Unit
Weighted Average Units Outstanding	75.4			75.4			75.5			75.5
Net Income per Unit	$	0.63		$	0.72		$	1.89		$	2.34
EBIT	$	69.6		$	80.0		$	232.6		$	264.1
EBITDA	$	91.0		$	101.0		$	321.8		$	351.8
Selected Items Impacting Comparability
LTIP charge	$	(10.4	)	$	(10.4	)	$	(34.6	)	$	(34.6	)
Cumulative Effect of Change in Accounting Principle	6.4			6.4			6.4			6.4
	$	(4.0	)	$	(4.0	)	$	(28.2	)	$	(28.2	)
Excluding Selected Items Impacting Comparability
Adjusted EBITDA	$	95.0		$	105.0		$	350.0		$	380.0
Adjusted Net Income	$	58.1		$	69.2		$	196.1		$	230.6
Adjusted Basic Net Income per Limited Partner Unit	$	0.70		$	0.85		$	2.31		$	2.77
Adjusted Diluted Net Income per Limited Partner Unit	$	0.68		$	0.83		$	2.26		$	2.70

(1)The projected average foreign exchange rate is $1.20 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	Barrel 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
GMT&S	Gathering, Marketing, Terminalling & Storage

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 end-user refineries, field declines and other external factors beyond our control. Actual segment profit could vary materially depending on the level of volumes transported.

For the three months ending March 31, 2006 projected volumes incorporate assumptions with respect to 1) scheduled maintenance on a certain producer’s asset that feeds All American Pipeline, 2) expected lower cyclical demand volumes on Capline Pipeline, and 3) lingering effects of 2005 Hurricanes Katrina and Rita. Volumes for the remainder of the year are projected to increase from a combination of cyclical demand and recovery of certain volumes impacted by last year’s hurricanes.

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 pipeline segment profit.

	2006 Guidance
	Three Months				Twelve Months
	Ending				Ending
	March 31				December 31
Average Daily Volumes (000’s Bbl/d)
All American		43				47
Basin		279				273
Capline		96				122
West Texas / New Mexico area systems(1)		424				415
Canada(2)		265				265
Other		693				723
		1,800				1,845
Average Segment Profit ($/Bbl)
As Estimated		$	0.222	(3)		$	0.248	(3)
Excluding Selected Items Impacting Comparability		$	0.251	(3)		$	0.271	(3)

(1)The aggregate of 11 systems in the West Texas / New Mexico area.

(2)The aggregate of 8 systems.

(3)Mid-point of estimate.

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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. Field operating costs do not include depreciation. To illustrate the impact volume changes may have on segment profit, the following table provides a volume sensitivity analysis of three systems representing approximately 25% of total pipeline revenues.

Volume Sensitivity Analysis
			% of			Incr (Decr)
	Incr (Decr)		System			in Annualized
System	in Volume		Total			Segment Profit
	(Bbls/d)					(in millions)
All American		5,000		11	%		$	3.5
Basin		20,000		7	%		1.4
Capline		10,000		8	%		1.3

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 months ending March 31, 2006 reflect an expected continuation of the favorable market structure experienced in the fourth quarter of 2005. Operating results for the remaining nine months of 2006 reflect the expectation that the market structure will be more favorable than market conditions for 2003 and 2004, but not as favorable as those experienced throughout 2005, which were considered very favorable relative to our asset base and business model.

	Calendar 2006
	Three Months Ending March 31				Twelve Months Ending December 31
Average Daily Volumes (000’s Bbl/d)
Crude Oil Lease Gathering		600				605
LPG		90				75
		690				680
Segment Profit per Barrel
As Estimated		$	0.865	(1)		$	0.649	(1)
Excluding Selected Items Impacting Comparability		$	0.955	(1)		$	0.725	(1)

(1)Mid-point of estimate.

Segment profit is forecast using the volume assumptions stated above and estimates of unit margins, field operating costs, G&A 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. Based on our mid-point projected segment profit per barrel for calendar 2006, a 15,000 Bbl/d variance in lease gathering volumes would impact segment profit by approximately $4.0 million on an annualized basis. A $0.01 variance in the aggregate average per-barrel margin would impact segment profit by approximately $2.5 million on an annualized basis.

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.Foreign Currency Revaluations and Statement of Financial Accounting Standards No. 133 “Accounting for Derivative Instruments and Hedging Activities” (SFAS 133).   The guidance presented above does

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not include assumptions or projections with respect to potential gains or losses related to foreign currency revaluations and 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 foreign currency revaluations and derivatives (primarily 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 $230 million during calendar 2006. Following are some of the more notable projects to be undertaken in 2006 and the estimated expenditures for the year.

	Calendar 2006
	(in millions)
Expansion Capital
·  St. James, Louisiana storage facility		$	60
·  Spraberry System expansion		20
·  High Prairie truck and rail terminals		31
·  Kerrobert tankage and pumps		35
·  Midale truck terminal		11
·  Truck trailers		11
·  Wichita Falls tankage		9
·  Other Projects		53
		230
Maintenance Capital		23
Total Projected Capital Expenditures		$	253

7.Capital Structure.   The guidance is based on our capital structure as of December 31, 2005.

8.Interest Expense.   Debt balances are projected based on estimated cash flows, current distribution rates, 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.

Calendar 2006 interest expense is expected to be between $61.7 million and $64.7 million, assuming an average long-term debt balance of approximately $1,110 million 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 margin deposits). At December 31, 2005, 100% of our long-term debt balance was fixed at an average interest rate of 6.0%. Interest on floating rate debt is based on a forward graduated LIBOR index curve of approximately 5.1%. 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

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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 these costs as carrying costs of the crude and include it as part of the purchase price of the crude.

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.

	2006 Guidance (in millions, except per unit amounts)
	Three Months Ending								Twelve Months Ending
	March 31, 2006								December 31, 2006
	Low				High				Low				High
Numerator for basic and diluted earnings per limited partner unit:
Net Income		$	54.1			$	65.2			$	167.9			$	202.4
Less:
General partners incentive distribution paid		(5.6		)		(5.6		)		(22.3		)		(22.3		)
		48.5				59.6				145.6				180.1
General partner 2% ownership		(0.9		)		(1.2		)		(2.9		)		(3.6		)
Net income available to limited partners		47.6				58.4				142.7				176.5
Pro forma additional general partner's incentive distribution		—				(3.8		)		—				—
Net Income available for limited partners under EITF 03-06		$	47.6			$	54.6			$	142.7			$	176.5
Denominator:
Denominator for basic earnings per limited partner unit- weighted average number of limited partner units		73.8				73.8				73.8				73.8
Effect of dilutive securities:
Weighted average LTIP units		1.6				1.6				1.7				1.7
Denominator for diluted earnings per limited partner unit-weighted average number of limited partner units		75.4				75.4				75.5				75.5
Basic net income per limited partner unit		$	0.64			$	0.74			$	1.93			$	2.39
Diluted net income per limited partner unit		$	0.63			$	0.72			$	1.89			$	2.34

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 $2.75 per unit, our general partner’s distribution is forecast to be approximately $26.4 million annually, of which $22.3 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. For distribution rates where EITF 03-06 does not apply, each $0.05 per unit annual increase in the distribution over $2.75 per unit decreases net income available for limited partners by approximately $3.6 million ($0.05 per unit) on an annualized basis.

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10.Long-term Incentive Plans.   Effective January 1, 2006 we will adopt SFAS 123(R) Share-Based Payment, resulting in a cumulative effect of change in accounting principle of approximately $6.4 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 phantom units under the 2005 plan primarily 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 and $3.00 per unit, respectively, and the majority of the phantom units have a final service period vesting in 2011. In addition to exceeding the distribution level of $2.60, it has been deemed probable that the $3.00 distribution level will be reached. Accordingly, guidance includes, for phantom units tied to performance levels of $3.00 or less, an accrual over the corresponding service period. For 2006, the guidance includes approximately $34.6 million of principally non-cash expense associated with these phantom units. The earliest 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 and will also be increased if a determination is made that achievement of any of the remaining performance thresholds is probable. Therefore, market variables could cause actual net income to differ materially from our projections.

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

	Guidance (in millions)
	Three Months Ending								Twelve Months Ending
	March 31, 2006								December 31, 2006
	Low				High				Low				High
Reconciliation to Net Income
EBITDA		$	91.0			$	101.0			$	321.8			$	351.8
Depreciation and amortization		(21.4		)		(21.0		)		(89.2		)		(87.7		)
EBIT		69.6				80.0				232.6				264.1
Interest expense		(15.5		)		(14.8		)		(64.7		)		(61.7		)
Net Income		$	54.1			$	65.2			$	167.9			$	202.4

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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. 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;

·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;

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

·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;

·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;

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·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.

	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 23, 2006	By:	/s/ PHIL KRAMER
		Name:	Phil Kramer
		Title:	Executive Vice President and Chief Financial Officer

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EX-99.1

Exhibit 99.1

Contacts:	Phillip D. Kramer	Brad A. Thielemann
	Executive VP and CFO	Manager, Special Projects
	713/646-4560—800/564-3036	713/646-4222—800/564-3036

FOR IMMEDIATE RELEASE

Plains All American Pipeline, L.P. Reports
Record Results for 2005

(Houston—February 23, 2006) Plains All American Pipeline, L.P. (NYSE: PAA) today reported net income of $53.7 million, or $0.64 per diluted limited partner unit, for the fourth quarter of 2005. These financial results represent an increase of 117% and 100%, respectively, over net income of $24.7 million, or $0.32 per diluted limited partner unit, for the fourth quarter of 2004. For the full year 2005, the Partnership reported net income of $217.8 million, or $2.72 per diluted limited partner unit, an increase of 68% and 44%, respectively, over net income of $130.0 million, or $1.89 per diluted limited partner unit, for the full year 2004.

As reported, earnings before interest, taxes, depreciation and amortization (“EBITDA”) for the fourth quarter of 2005 was $94.1 million, an increase of 50% as compared with EBITDA of $62.6 million for the fourth quarter of 2004. EBITDA for the full year 2005 was $360.7 million, an increase of 47% as compared with EBITDA of $245.4 million for the full year 2004. (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.)

“The strong operating and financial results for the fourth quarter provided an appropriate conclusion to a record setting year for the Partnership,” said Greg L. Armstrong, Chairman and CEO of Plains All American.  “The performance of the Partnership this past year once again highlights the complementary strengths of our strategically located assets and our business model.”

“In addition to delivering outstanding performance throughout the year, we also met or exceeded each of our stated goals, significantly expanded our portfolio of organic growth projects, made substantial  progress in our foreign crude initiative and established a platform for future growth in the natural gas storage business,” added Armstrong. “The combination of these activities allowed us to increase distributions to unitholders by approximately 12% and positioned the Partnership for continued growth.”

Armstrong also noted that despite the significant growth experienced during the year, the Partnership was able to improve its capital structure and increase its financial flexibility. The Partnership ended the year with a long-term debt-to-total capitalization ratio of 42%, strong credit metrics and approximately $800 million of available capacity on its senior unsecured credit facility.

Reported results include the impact of various items that affect comparability between reporting periods. Adjusting for selected items impacting comparability, the Partnership’s fourth quarter 2005 adjusted net income, adjusted net income per limited partner unit and adjusted EBITDA were $62.6 million, $0.75 per diluted unit, and $103.0 million, respectively. Similarly, the Partnership’s fourth quarter 2004 adjusted net income, adjusted net income per limited partner unit and adjusted EBITDA were $29.3 million, $0.39 per diluted unit, and $67.2 million, respectively. On a comparable basis, fourth quarter 2005 adjusted net income, adjusted net income per diluted limited partner unit and adjusted EBITDA increased 114%, 92% and 53%, respectively, over fourth quarter 2004.

The Partnership’s adjusted net income, adjusted net income per diluted limited partner unit and adjusted EBITDA for the full year of 2005 were $264.9 million, $3.47 per unit, and $407.8 million, respectively. For 2004, these same financial measures were $137.0 million, $2.00 per diluted unit, and $252.4 million, respectively. Using this same basis for comparison, 2005 adjusted net income, adjusted net income per diluted limited partner unit and adjusted EBITDA increased 93%, 74% and 62%, respectively, over 2004.

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

	For the Three Months Ended December 31,				For the Twelve Months Ended December 31,
	2005		2004(1)		2005		2004(1)
	(Dollars in millions, except per unit data)
Long-Term Incentive Plan (“LTIP”) charge	$ (9.3	)	$ (3.7	)	$ (26.1	)	$ (7.9	)
Cumulative effect of change in accounting principle	—		—		—		(3.1	)
Gain/(Loss) on foreign currency revaluation	(0.7	)	1.5		(2.1	)	5.0
Inventory valuation adjustment	—		(2.0	)	—		(2.0	)
SFAS 133 mark-to-market adjustment	1.1		(0.4	)	(18.9	)	1.0
Total(1)	$ (8.9	)	$ (4.6	)	$ (47.1	)	$ (7.0	)
Per Basic Limited Partner Unit(2)	$ (0.12	)	$ (0.07	)	$ (0.76	)	$ (0.11	)
Per Diluted Limited Partner Unit(2)	$ (0.11	)	$ (0.07	)	$ (0.75	)	$ (0.11	)

Note:Figures may not sum due to rounding.

(1)Selected items impacting comparability for the 2004 period does not include several items that were previously included. The impact is a reduction of selected items impacting comparability that are used to calculate adjusted net income of $2.0 million and $0.03 per basic and diluted limited partner unit for the 3 months ended December 31, 2004 (previously, these items totaled $(6.6) million and $(0.10) per basic and diluted unit for the quarter) and $2.2 million and $0.03 per basic and diluted limited partner unit for the year ended December 31, 2004 (previously, these items totaled $(9.2) million and $(0.14) per basic and diluted unit for the year). Because the majority of these items were reclassified into depreciation and amortization, the net impact of these items on adjusted EBITDA was negligible.

(2)For the full year ended December 31, 2005, the Partnership’s net income exceeded the cash distribution paid during such periods, which required the application of Emerging Issues Task Force Issue No. 03-06: “Participating Securities and the Two-Class Method under FASB Statement No. 128” (“EITF 03-06”). This theoretical calculation does not impact the Partnership’s aggregate net income or EBITDA, but does reduce the Partnership’s net income per limited partner unit. The application of EITF 03-06 negatively impacted basic and diluted earnings per limited partner unit by $0.10 for the full year 2005.

The Partnership’s net income and EBITDA for the fourth quarter and full year of 2005 include $1.0 million of earnings associated with the Partnership’s 50% ownership interest in PAA/Vulcan Gas Storage, LLC.

2

The following table presents certain selected financial information by segment for the fourth quarter and full year reporting periods:

	For the Three Months													For the Twelve Months
							Gathering,													Gathering,
							Marketing,													Marketing,
							Terminalling &													Terminalling &
	Pipeline						Storage							Pipeline						Storage
	Operations						Operations(4)							Operations						Operations(4)
	(in millions)													(in millions)
Ended December 31, 2005
Revenues(1)		$			319.2			$				8,433.6			$			1,130.3			$					30,186.6
Purchases and related costs(1)		(225.3				)		(8,333.8					)		(751.5				)		(29,830.6						)
Field operating costs (excluding LTIP charge)		(43.6				)		(27.9					)		(152.4				)		(117.0						)
LTIP charge—operations		(0.3				)		(0.7					)		(1.0				)		(2.1						)
Segment G&A expenses (excluding LTIP charge)(2)		(10.0				)		(10.1					)		(39.6				)		(40.6						)
LTIP charge—general and administrative		(1.9				)		(6.4					)		(10.6				)		(12.4						)
Segment profit		$			38.1			$				54.7			$			175.2			$					183.9
SFAS 133 mark-to-market impact(3)		$			—			$				1.1			$			—			$					(18.9	)
Maintenance capital		$			0.2			$				1.6			$			8.4			$					5.6
Ended December 31, 2004
Revenues(1)		$			235.4			$				5,975.9			$			874.9			$				20,223.5
Purchases and related costs(1)		(146.2				)		(5,917.0					)		(554.6				)		(19,992.8						)
Field operating costs (excluding LTIP charge)		(36.3				)		(24.2					)		(121.1				)		(97.5						)
LTIP charge—operations		—						(0.4					)		(0.1				)		(0.8						)
Segment G&A expenses (excluding LTIP charge)(2)		(10.8				)		(10.5					)		(38.1				)		(37.7						)
LTIP charge—general and administrative		(2.1				)		(1.2					)		(3.8				)		(3.2						)
Segment profit		$			40.0			$			22.6				$		157.2				$			91.5
SFAS 133 mark-to-market impact(3)		$		—				$		(0.4			)		$		—				$		1.0
Maintenance capital		$	4.2					$	1.0						$	8.3					$	3.0

(1)Includes inter-segment amounts.

(2)Segment general and administrative expenses (G&A) reflect direct costs attributable to each segment and an allocation of other expenses to the segments based on the business activities that existed at that time. The proportional allocations by segment require judgment by management and will continue to be based on the business activities that exist during each period.

(3)Amounts related to SFAS 133 are included in revenues and impact segment profit. The SFAS 133 mark-to-market adjustment is primarily based upon crude oil prices at the end of the period and is related to the non-effective portion of our cash flow hedges, as well as certain derivative contracts that do not qualify under SFAS 133 as cash flow hedges. The net gain or loss related to these derivative instruments is principally offset by physical positions in future periods.

(4)Gains/losses on foreign currency revaluation are included in the Gathering, Marketing, Terminalling & Storage segment.

3

Excluding selected items impacting comparability in both periods, segment profit from pipeline operations in the fourth quarter of 2005 was $40.3 million, a $1.8 million decrease as compared to segment profit of $42.1 million for the fourth quarter of 2004. Results for the fourth quarter of 2005 reflect approximately $3.0 million of higher utility and power costs as well as two isolated adjustments totaling $4.5 million. These adjustments consist of a hurricane related expense accrual of $1.9 million (which includes a $1.0 million reallocation from our GMTS segment) and a $2.6 million reserve for a third party tariff claim relating to prior years’ activities on one of our Canadian pipelines. Average daily pipeline volumes totaled 1.8 million barrels per day in the fourth quarter of 2005 versus 1.6 million barrels per day in the prior year period. Excluding selected items impacting comparability in both periods, segment profit from gathering, marketing, terminalling and storage operations in the fourth quarter of 2005 was up approximately 145% over the corresponding period in 2004 as a result of favorable market conditions.

Adjusted segment profit from pipeline operations in 2005 was $186.8 million versus $161.1 million in 2004. Adjusted segment profit from gathering, marketing, terminalling and storage operations was $219.4 million in 2005 versus $91.5 million in 2004. These strong year-over-year results are related to a number of factors, including a fundamental increase in our sustainable performance level and very favorable market conditions that complemented our asset base and business model.

The Partnership’s basic weighted average units outstanding for the fourth quarter of 2005 totaled 73.7 million (75.3 million diluted) as compared to 67.3 million (67.3 million diluted) in last year’s fourth quarter. At December 31, 2005, the Partnership had approximately 73.8 million units outstanding, long-term debt of $951.7 million and a long-term debt-to-total capitalization ratio of approximately 42%.

On February 14, 2006, the Partnership paid a cash distribution of $0.6875 per unit ($2.75 per unit on an annualized basis) on its outstanding limited partner units. The distribution represents an increase of 12.2% over the February 2005 distribution and approximately 1.85% over the November 2005 distribution. This represents the 7th consecutive quarterly distribution increase and the 14th distribution increase for the Partnership in the last 20 quarters.

The Partnership today furnished a current report on Form 8-K, which includes material in this press release and financial and operational guidance for the first quarter and full year 2006. A copy of the Form 8-K is 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 results of operations or cash provided by 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.

4

A reconciliation of EBITDA to net income and cash flow 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 to discuss the results and other forward-looking items on Thursday, February 23, 2006. Specific items to be addressed in this call include:

1.A brief review of the Partnership’s fourth quarter and full year performance;

2.An assessment of the Partnership’s 2005 performance versus goals;

3.A status report on major capital projects and recent acquisition activity;

4.A discussion of capitalization and liquidity;

5.A review of financial and operating guidance for the first quarter and full year 2006; and

6.Comments regarding the Partnership’s outlook and 2006 goals.

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. To access the slides used in connection with the call, please go to the Partnership’s website at www.paalp.com, choose “Investor Relations,” and then choose “Partnership Presentations.”

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, dial 877-660-6853, or for international callers, 201-612-7415, and enter acct # 232 and replay # 190857. The replay will be available beginning Thursday, February 23, 2006, at approximately 1:00 PM (Central) and continue until 11:59PM (Central) Monday, February 27, 2006.

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:  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; declines in volumes shipped on the Basin Pipeline, Capline Pipeline and our other

5

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; successful third party drilling efforts in areas in which we operate pipelines or gather crude oil; 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; the impact of current and future laws, rulings and governmental regulations; the effects of competition; continued creditworthiness of, and performance by, counter parties; 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 discussed in the Partnership’s filings with the Securities and Exchange Commission.

Plains All American Pipeline, L.P. is engaged in interstate and intrastate crude oil transportation and crude oil gathering, marketing, terminalling and storage, as well as the marketing and storage of liquefied petroleum gas and other petroleum products, in the United States and Canada. Through its 50% ownership in PAA/Vulcan Gas Storage LLC, the Partnership is engaged in the development and operation of natural gas storage facilities. The Partnership’s common units are traded on the New York Stock Exchange under the symbol “PAA.” The Partnership is headquartered in Houston, Texas.

# # #

6

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

CONSOLIDATED STATEMENTS OF OPERATIONS(1)
(in millions, except per unit data)

	Three Months Ended						Twelve Months Ended
	December 31,						December 31,
	2005			2004			2005			2004
REVENUES	$	8,713.7		$	6,172.1		$	31,177.3		$	20,975.5
COSTS AND EXPENSES
Purchases and related costs	8,520.0			6,024.2			30,442.5			20,424.6
Field operating costs (excluding LTIP charge)	71.5			60.5			269.4			218.6
LTIP charge—operations	1.0			0.4			3.1			0.9
General and administrative expenses (excluding LTIP charge)	20.1			21.2			80.2			75.7
LTIP charge—general & administrative	8.3			3.3			23.0			7.0
Depreciation and amortization	25.4			23.4			83.5			68.7
Total costs and expenses	8,646.3			6,133.0			30,901.7			20,795.5
OPERATING INCOME	67.4			39.1			275.6			180.0
OTHER INCOME/(EXPENSE)
Equity earnings in PAA/Vulcan Gas Storage, LLC	1.0			—			1.0			—
Interest expense	(15.0		)	(14.5		)	(59.4		)	(46.7		)
Interest and other income (expense), net	0.3			0.1			0.6			(0.2		)
Income before cumulative effect of change in accounting principle	53.7			24.7			217.8			133.1
Cumulative effect of change in accounting principle	—			—			—			(3.1		)
NET INCOME	$	53.7		$	24.7		$	217.8		$	130.0
NET INCOME—LIMITED PARTNERS	$	48.0		$	21.6		$	191.6		$	119.3
NET INCOME—GENERAL PARTNER	$	5.7		$	3.1		$	26.2		$	10.7
BASIC NET INCOME PER LIMITED PARTNER UNIT
Income before cumulative effect of change in accounting principle	$	0.65		$	0.32		$	2.77		$	1.94
Cumulative effect of change in accounting principle	—			—			—			(0.05		)
Basic net income per limited partner unit	$	0.65		$	0.32		$	2.77		$	1.89
DILUTED NET INCOME PER LIMITED PARTNER UNIT
Income before cumulative effect of change in accounting principle	$	0.64		$	0.32		$	2.72		$	1.94
Cumulative effect of change in accounting principle	—			—			—			(0.05		)
Diluted net income per limited partner unit	$	0.64		$	0.32		$	2.72		$	1.89
BASIC WEIGHTED AVERAGE UNITS OUTSTANDING	73.7			67.3			69.3			63.3
DILUTED WEIGHTED AVERAGE UNITS OUTSTANDING	75.3			67.3			70.5			63.3
OPERATING DATA (in thousands) (2)
Average Daily Volumes (barrels)
Pipeline activities:
Tariff activities
All American	50			51			51			54
Basin	309			234			290			265
Capline	97			145			132			123
Cushing to Broome	78			N/A			66			N/A
North Dakota/Trenton	87			59			77			39
West Texas/New Mexico Area Systems(3)	446			377			428			338
Canada	256			278			255			263
Other	435			397			426			330
Pipeline margin activities	90			78			74			74
Total	1,848			1,619			1,799			1,486
Crude oil lease gathering	591			629			610			589
LPG sales	73			73			56			48

(1)Certain reclassifications have been made to prior periods to conform to 2005 presentation.

(2)Volumes associated with acquisitions represent total volumes transported for the number of days we actually owned the assets divided by the number of days in the period.

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

7

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
FINANCIAL SUMMARY (unaudited) (in millions, except per unit data) (Continued)

CONDENSED CONSOLIDATED BALANCE SHEET DATA

	December 31,			December 31,
	2005			2004
ASSETS
Current assets		$	1,805.2		$	1,101.2
Property and equipment, net		1,857.2			1,727.6
Pipeline linefill in owned assets		180.2			168.4
Inventory in third party assets		71.5			59.3
Investment in PAA/Vulcan Gas Storage, LLC		113.5			—
Other long-term assets, net		92.7			103.9
Total Assets		$	4,120.3		$	3,160.4
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities		$	1,793.3		$	1,113.7
Long-term debt under credit facilities and other		4.7			151.7
Senior notes, net of unamortized discount		947.0			797.3
Other long-term liabilities and deferred credits		44.6			27.5
Total Liabilities		2,789.6			2,090.2
Partners’ capital		1,330.7			1,070.2
Total Liabilities and Partners’ Capital		$	4,120.3		$	3,160.4

COMPUTATION OF BASIC AND DILUTED EARNINGS PER LIMITED PARTNER UNIT

	Three months ended December 31,						Twelve months ended December 31,
	2005			2004			2005			2004
Numerator for basic and diluted earnings per limited partner unit:
Net income	$	53.7		$	24.7		$	217.8		$	130.0
Less:
General partner’s incentive distribution paid	(4.7		)	(2.7		)	(14.9		)	(8.3		)
Subtotal	49.0			22.0			202.9			121.7
General partner 2% ownership	(1.0		)	(0.4		)	(4.1		)	(2.4		)
Net income available to limited partners	48.0			21.6			198.8			119.3
Pro forma additional general partner’s incentive distribution(1)	—			—			(7.2		)	—
Net Income available for limited partners under EITF 03-06	$	48.0		$	21.6		$	191.6		$	119.3
Denominator:
Denominator for basic earnings per limited partner unit—weighted average number of limited partner units	73.7			67.3			69.3			63.3
Effect of dilutive securities:
Weighted average LTIP units	1.6			—			1.2			—
Denominator for diluted earnings per limited partner unit—weighted average number of limited partner units	75.3			67.3			70.5			63.3
Basic net income per limited partner unit (1)	$	0.65		$	0.32		$	2.77		$	1.89
Diluted net income per limited partner unit (1)	$	0.64		$	0.32		$	2.72		$	1.89

(1)Reflects pro forma full distribution of earnings under EITF 03-06. The application of EITF 03-06 negatively impacted  basic and diluted earnings per limited partner unit by approximately $0.10  for the year ended 2005.

8

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
FINANCIAL SUMMARY (unaudited) (in millions, except per unit data) (continued)

FINANCIAL DATA RECONCILIATIONS(1)

	Three Months Ended December 31,						Twelve Months Ended December 31,
	2005			2004			2005			2004
Earnings before interest, taxes, depreciation and amortization (“EBITDA”)
Net income reconciliation
EBITDA	$	94.1		$	62.6		$	360.7		$	245.4
Depreciation and amortization	(25.4		)	(23.4		)	(83.5		)	(68.7		)
Earnings before interest and taxes (“EBIT”)	68.7			39.2			277.2			176.7
Interest expense	(15.0		)	(14.5		)	(59.4		)	(46.7		)
Net Income	$	53.7		$	24.7		$	217.8		$	130.0
Cash flow from operating activities reconciliation
EBITDA	$	94.1		$	62.6		$	360.7		$	245.4
Interest expense	(15.0		)	(14.5		)	(59.4		)	(46.7		)
Net change in assets and liabilities, net of acquisitions	386.2			(62.2		)	(324.0		)	(101.7		)
Other items to reconcile to cash flows from operating activities:
Equity earnings in PAA/Vulcan Gas Storage, LLC	(1.0		)	—			(1.0		)	—
Inventory valuation adjustment	—			2.0			—			2.0
Cumulative effect of change in accounting principle	—			—			—			3.1
(Gain)/loss on foreign currency revaluation	0.7			(1.5		)	2.1			(5.0		)
Net cash paid for terminated interest rate hedging instruments	—			—			(0.9		)	(1.5		)
SFAS 133 mark-to-market adjustment	(1.1		)	0.4			18.9			(1.0		)
LTIP charge	9.3			3.7			26.1			7.9
Non-cash amortization of terminated interest rate hedging instruments	0.4			0.4			1.6			1.5
Net cash provided by (used in) operating activities	$	473.6		$	(9.1	)	$	24.1		$	104.0

	Three Months Ended December 31,						Twelve Months Ended December 31,
	2005			2004			2005			2004
Funds flow from operations (“FFO”)
Net Income	$	53.7		$	24.7   24.7		$	217.8		$	130.0   130.0
Equity earnings in PAA/Vulcan Gas Storage, LLC	(1.0		)	—			(1.0		)	—
Depreciation and amortization	25.4			23.4			83.5			68.7
Non-cash amortization of terminated interest rate hedging instruments	0.4			0.4			1.6			1.5
FFO	78.5			48.5			301.9			200.2
Maintenance capital expenditures(2)	(1.8		)	(5.2		)	(14.0		)	(11.3		)
FFO after maintenance capital expenditures	$	76.7		$	43.3   43.3		$	287.9		$	188.9

	Three Months Ended December 31,						Twelve Months Ended December 31,
	2005			2004			2005			2004
Selected items impacting comparability
LTIP charge	$	(9.3	)	$	(3.7	)	$	(26.1	)	$	(7.9	)
Cumulative effect of change in accounting principle	—			—			—			(3.1		)
Gain/(Loss) on foreign currency revaluation	(0.7		)	1.5			(2.1		)	5.0
Inventory valuation adjustment	—			(2.0		)	—			(2.0		)
SFAS 133 mark-to-market adjustment	1.1			(0.4		)	(18.9		)	1.0
Pro forma additional GP distribution under EITF 03-06(3)	—			—			—			—
Selected items impacting comparability(4)	(8.9		)	(4.6		)	(47.1		)	(7.0		)
GP 2% portion of selected items impacting comparability	0.2			0.1			1.0			0.1
LP 98% portion of selected items impacting comparability	$	(8.7	)	$	(4.5	)	$	(46.1	)	$	(6.9	)
Impact to basic net income per limited partner unit(3)	$	(0.12	)	$	(0.07	)	$	(0.76	)	$	(0.11	)
Impact to diluted net income per limited partner unit(3)	$	(0.11	)	$	(0.07	)	$	(0.75	)	$	(0.11	)

(1)          Certain reclassifications have been made to prior periods to conform to 2005 presentation.

(2)Current quarter includes $2.7 million reduction in maintenance capital resulting from a reclassification of prior period costs from maintenance capital to expansion capital.

(3)The application of EITF 03-06 negatively impacted  basic and diluted earnings per limited partner unit by approximately $0.10 for the year ended 2005.

(4)Selected items impacting comparability for the 2004 period does not include several items that were previously included. The impact is a reduction of selected items impacting comparability that are used to calculate adjusted net income of $2.0 million and $0.03 per basic and diluted limited partner unit for the 3 months ended December 31, 2004 (previously, these items totaled $(6.6) million and $(0.10) per basic and diluted unit for the quarter) and $2.2 million and $0.03 per basic and diluted limited partner unit for the year ended December 31, 2004 (previously, these items totaled $(9.2) million and $(0.14) per basic and diluted unit for the year).  Because the majority of these items were reclassified into depreciation and amortization, the net impact of these items on adjusted EBITDA was negligible.

9

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
FINANCIAL SUMMARY (unaudited) (in millions, except per unit data) (continued)

FINANCIAL DATA RECONCILIATIONS(1) (continued)

	Three Months Ended December 31,				Twelve Months Ended December 31,
	2005		2004		2005		2004
Net income and earnings per limited partner unit excluding
selected items impacting comparability
Net Income	$	53.7	$	24.7	$	217.8	$	130.0
Selected items impacting comparability	8.9		4.6		47.1		7.0
Adjusted Net Income	$	62.6	$	29.3	$	264.9	$	137.0
Net Income available for limited partners under EITF 03-06	$	48.0	$	21.6	$	191.6	$	119.3
Limited partners 98% of selected items impacting comparability	8.7		4.5		46.1		6.9
Pro forma additional general partner distribution under EITF 03-06	—		—		7.2		—
Adjusted limited partners Net Income	$	56.7	$	26.1	$	244.9	$	126.2
Adjusted Basic Net Income per limited partner unit	$	0.77	$	0.39	$	3.53	$	2.00
Adjusted Diluted Net Income per limited partner unit	$	0.75	$	0.39	$	3.47	$	2.00
Basic weighted average units outstanding	73.7		67.3		69.3		63.3
Diluted weighted average units outstanding	75.3		67.3		70.5		63.3
EBITDA excluding selected items impacting comparability
EBITDA	$	94.1	$	62.6	$	360.7	$	245.4
Selected items impacting comparability	8.9		4.6		47.1		7.0
Adjusted EBITDA	$	103.0	$	67.2	$	407.8	$	252.4

	Three Months Ended December 31, 2005							Twelve Months Ended December 31, 2005
	Pipeline			GMT&S				Pipeline			GMT&S
2005 Segment profit excluding selected items impacting comparability
Reported segment profit		$	38.1		$	54.7			$	175.2		$	183.9
Selected items impacting comparability of segment profit:
LTIP charge		2.2			7.1				11.6			14.5
(Gain)/Loss on foreign currency revaluation		—			0.7				—			2.1
SFAS 133 mark-to-market adjustment		—			(1.1		)		—			18.9
Segment profit excluding selected items impacting comparability		$	40.3		$	61.4			$	186.8		$	219.4

	Three Months Ended December 31, 2004							Twelve Months Ended December 31, 2004
	Pipeline			GMT&S				Pipeline			GMT&S
2004 Segment profit excluding selected items impacting comparability
Reported segment profit		$	40.0		$	22.6			$	157.2		$	91.5
Selected items impacting comparability of segment profit:
LTIP charge		2.1			1.6				3.9			4.0
Inventory valuation adjustment					2.0							2.0
(Gain)/Loss on foreign currency revaluation		—			(1.5		)		—			(5.0		)
SFAS 133 mark-to-market adjustment		—			0.4				—			(1.0		)
Segment profit excluding selected items impacting comparability		$	42.1		$	25.1			$	161.1		$	91.5

(1)Certain reclassifications have been made to prior periods to conform to 2005 presentation.

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