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)—May 3, 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:

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 May 3, 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 first quarter 2006 results. We are furnishing the press release, attached as Exhibit 99.1, pursuant to Item 2.02 and Item 7.01 of Form 8-K. Pursuant to Item 7.01 we are providing detail guidance for financial performance for the second quarter of calendar 2006 and modifying certain aspects of our previous guidance for financial performance for the full year of calendar 2006 (which supersedes guidance in our 8-K furnished on February 23, 2006). In accordance with General Instruction B.2. of Form 8-K, the information presented herein under Item 2.02 and Item 7.01 shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, nor shall it be deemed incorporated by reference in any filing under the Securities Act of 1933, as amended, except as expressly set forth by specific reference in such a filing.

Disclosure of Second 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, and 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, revaluations of foreign currency, cumulative effect of a change in accounting principle and, to the extent known, gains and losses related to SFAS 133 (primarily non-cash, mark-to-market adjustments) on EBITDA, Net Income and Net Income per Limited Partner Unit.

The following guidance for the three months ending June 30, 2006 and the six months and 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 May 2, 2006. 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)

	Actual			Guidance(1)
				Three				Six				Twelve
	Three			Months				Months				Months
	Months			Ending				Ending				Ending
	Ended			June 30,				December 31,				December 31,
	March 31,			2006				2006				2006
	2006			Low		High		Low		High		Low		High
Pipeline
Net revenues		$ 96.4		$ 101.0		$ 103.6		$ 209.9		$ 212.7		$ 407.3		$ 412.7
Field operating costs		(45.1	)	(48.2	)	(47.6	)	(93.2	)	(92.0	)	(186.5	)	(184.7	)
General and administrative expenses		(13.3	)	(11.4	)	(11.2	)	(23.4	)	(23.0	)	(48.1	)	(47.5	)
		38.0		41.4		44.8		93.3		97.7		172.7		180.5
Gathering, Marketing, Terminalling & Storage
Net revenues		111.6		97.9		103.4		204.2		217.8		413.7		432.8
Field operating costs		(37.2	)	(39.0	)	(38.4	)	(79.3	)	(78.1	)	(155.5	)	(153.7	)
General and administrative expenses		(18.5	)	(19.2	)	(18.9	)	(38.7	)	(38.1	)	(76.4	)	(75.5	)
		55.9		39.7		46.1		86.2		101.6		181.8		203.6
Segment Profit		93.9		81.1		90.9		179.5		199.3		354.5		384.1
Depreciation and amortization expense		(21.6	)	(23.1	)	(22.7	)	(48.0	)	(47.2	)	(92.7	)	(91.5	)
Interest expense		(15.3	)	(18.6	)	(17.8	)	(37.3	)	(35.7	)	(71.2	)	(68.8	)
Equity earnings (Loss) in PAA / Vulcan Gas Storage, LLC		(0.2	)	0.6		0.8		1.9		2.1		2.3		2.7
Other Income (Expense)		0.3		—		—		—		—		0.3		0.3
Income Before Cumulative Effect of Change in Accounting Principle		57.1		40.0		51.2		96.1		118.5		193.2		226.8
Cumulative Effect of Change in Accounting Principle		6.3		—		—		—		—		6.3		6.3
Net Income		$ 63.4		$ 40.0		$ 51.2		$ 96.1		$ 118.5		$ 199.5		$ 233.1
Net Income to Limited Partners		$ 56.7		$ 32.0		$ 43.0		$ 79.8		$ 101.7		$ 168.5		$ 201.4
Basic Net Income Per Limited Partner Unit
Weighted Average Units Outstanding		74.0		77.0		77.0		77.3		77.3		76.4		76.4
Net Income Per Unit		$ 0.73		$ 0.42		$ 0.56		$ 1.03		$ 1.32		$ 2.20		$ 2.63
Diluted Net Income Per Limited Partner Unit
Weighted Average Units Outstanding		75.7		78.7		78.7		79.0		79.0		78.1		78.1
Net Income Per Unit		$ 0.71		$ 0.41		$ 0.55		$ 1.01		$ 1.29		$ 2.16		$ 2.58
EBIT		$ 78.7		$ 58.6		$ 69.0		$ 133.4		$ 154.2		$ 270.7		$ 301.9
EBITDA		$ 100.3		$ 81.7		$ 91.7		$ 181.4		$ 201.4		$ 363.4		$ 393.4

*Selected Items Impacting Comparability*
LTIP charge		$ (10.6	)	$ (8.3	)	$ (8.3	)	$ (17.4	)	$ (17.4	)	$ (36.3	)	$ (36.3	)
Cumulative Effect of Change in Accounting Principle		6.3		—		—		—		—		6.3		6.3
SFAS 133 Mark-to-Market Adjustment		(0.7	)	—		—		—		—		(0.7	)	(0.7	)
Gain (loss) on Foreign Currency Revaluation		(0.9	)	—		—		—		—		(0.9	)	(0.9	)
		$ (5.9	)	$ (8.3	)	$ (8.3	)	$ (17.4	)	$ (17.4	)	$ (31.6	)	$ (31.6	)


*Excluding Selected Items Impacting Comparability*
Adjusted EBITDA		$ 106.2		$ 90.0		$ 100.0		$ 198.8		$ 218.8		$ 395.0		$ 425.0
Adjusted Net Income		$ 69.3		$ 48.3		$ 59.5		$ 113.5		$ 135.9		$ 231.1		$ 264.7
Adjusted Basic Net Income per Limited Partner Unit		$ 0.84		$ 0.52		$ 0.66		$ 1.25		$ 1.54		$ 2.61		$ 3.04
Adjusted Diluted Net Income per Limited Partner Unit		$ 0.82		$ 0.51		$ 0.65		$ 1.24		$ 1.50		$ 2.55		$ 2.98

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

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 June 30, 2006 projected volumes incorporate assumptions with respect to 1) additional throughput agreements and expected higher seasonal demand volumes on Capline Pipeline, and 2) higher Canadian volumes primarily due to the purchase of the remaining interest in Cactus Lake Pipeline. Volumes for the remainder of the year are impacted by a combination of anticipated seasonal demand, recovery of certain volumes impacted by last year’s hurricanes, and natural field declines.

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

	Calendar 2006
	Actual		Guidance(3)
	Three Months		Three Months			Six Months			Twelve Months
	Ended		Ending			Ending			Ending
	March 31		June 30			December 31			December 31
Average Daily Volumes (000's Bbl/d)
All American		44		50			48			47
Basin		314		225			266			267
Capline		86		175			160			146
Cushing to Broome		70		80			80			77
North Dakota/Trenton		82		92			91			89
West Texas / New Mexico area systems(1)		442		409			388			407
Canada(2)		239		262			264			258
Other		537		547			543			539
		1,814		1,840			1,840			1,830
Average Segment Profit ($/Bbl)
As Reported/Estimated		$ 0.233		$ 0.257	(3)		$ 0.282	(3)		$ 0.264	(3)
Excluding Selected Items Impacting Comparability		$ 0.263		$ 0.280	(3)		$ 0.306	(3)		$ 0.289	(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.

Segment profit is forecast using the volume assumptions in the table above, priced at tariff rates currently received, with adjustments where appropriate for estimated escalation in certain rates as allowed by contractual terms, less estimated field operating costs and G&A expenses. Field operating costs do not include depreciation. 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 net 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	%		$ 3.6
Basin		20,000		7	%		1.4
Capline		10,000		7	%		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 June 30, 2006 reflect an expected continuation of the current contango market and favorable market conditions, although not quite as favorable as market conditions in the first quarter. Operating results for the remaining six 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
	Actual		Guidance(1)
	Three Months		Three Months			Six Months			Twelve Months
	Ended		Ending			Ending			Ending
	March 31		June 30			December 31			December 31
Average Daily Volumes (000’s Bbl/d)
Crude Oil Lease Gathering		615		635			651			637
LPG		84		58			93			82
		699		693			744			719
Segment Profit per Barrel
As Reported/Estimated		$ 0.89		$ 0.68	(1)		$ 0.69	(1)		$ 0.73	(1)
Excluding Selected Items Impacting Comparability		$ 1.01		$ 0.75	(1)		$ 0.75	(1)		$ 0.82	(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 expenses and carrying costs for contango inventory based on current and anticipated market conditions. The forecast also includes the incremental profits from recently completed acquisitions. Field operating costs do not include depreciation. Realized unit margins for any given lease-gathered barrel could vary significantly based on a variety of factors including location, quality and contract structure. Based on our mid-point projection of adjusted segment profit per barrel for calendar 2006, a 15,000 Bbl/d variance in lease gathering volumes would impact segment profit by approximately $4.5 million on an annualized basis. A $0.01 variance in the aggregate average per-barrel margin would impact segment profit by approximately $2.6 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 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 $250 million during calendar 2006 of which $45 million was incurred in the first quarter. 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
· Kerrobert tankage and pumps		45
· Spraberry System expansion		20
· High Prairie truck and rail terminals		18
· East Texas/Louisiana tankage		16
· Wichita Falls tankage		11
· Midale/Regina truck terminal		11
· Truck trailers		11
· Other Projects		58
		250
Maintenance Capital		23
Total Projected Capital Expenditures		$ 273

7. Capital Structure. The guidance is based on our capital structure as of March 31, 2006, adjusted for the sale of 1.2 million common units in April 2006.

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 $68.8 million and $71.2 million, assuming an average long-term debt balance of approximately $1.2 billion and an all-in average rate of approximately 6.0%. 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 March 31, 2006, 100% of our long-term debt balance was fixed at an average interest rate of 6.0%. The amortization of

deferred amounts associated with terminated interest rate hedges results in a non-cash component to interest expense of approximately $400,000 per quarter through September 2006, decreasing to approximately $100,000 per quarter thereafter until fully amortized over the next ten years.

Interest expense does not include interest on borrowings for contango inventory. We treat these costs as carrying costs of crude oil and include it as part of the purchase price of crude oil.

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.

	Guidance (in millions)
	Three Months Ending						Six Months Ending						Twelve Months Ending
	June 30, 2006						December 31, 2006						December 31, 2006
	Low			High			Low			High			Low			High
Numerator for basic and diluted earnings per limited partner unit:
Net Income		$ 40.0			$ 51.2			$ 96.1			$ 118.5			$ 199.5			$ 233.1
Less:
General partner’s incentive distribution		(7.3	)		(7.3	)		(14.7	)		(14.7	)		(27.6	)		(27.6	)
		32.7			43.9			81.4			103.8			171.9			205.5
General partner 2% ownership		(0.7	)		(0.9	)		(1.6	)		(2.1	)		(3.4	)		(4.1	)
Net income available to limited partners		32.0			43.0			79.8			101.7			168.5			201.4
Pro forma additional general partner’s incentive distribution		—			—			—			—			—			—
Net Income available for limited partners under EITF 03-06		$ 32.0			$ 43.0			$ 79.8			$ 101.7			$ 168.5			$201.4
Denominator:
Denominator for basic earnings per limited partner unit- weighted average number of limited partner units		77.0			77.0			77.3			77.3			76.4			76.4
Effect of dilutive securities:
Weighted average LTIP units		1.7			1.7			1.7			1.7			1.7			1.7
Denominator for diluted earnings per limited partner unit-weighted average number of limited partner units		78.7			78.7			79.0			79.0			78.1			78.1
Basic net income per limited partner unit		$ 0.42			$ 0.56			$ 1.03			$ 1.32			$ 2.20			$ 2.63
Diluted net income per limited partner unit		$ 0.41			$ 0.55			$ 1.01			$ 1.29			$ 2.16			$ 2.58

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 $2.83 per unit, our general partner’s distribution is forecast to be approximately $33.9 million annually, of which $29.4 million is attributed to the incentive distribution rights. The relative amount of the incentive distribution varies directionally with the number of units outstanding and the level of the distribution on the units. For distribution rates where EITF 03-06 does not apply, each $0.05 per unit annual increase in the distribution over $2.83 per unit decreases net income available for limited partners by approximately $3.7 million ($0.05 per unit) on an annualized basis.

10. Long-term Incentive Plans. Effective January 1, 2006 we adopted SFAS 123(R) Share-Based Payment, resulting in a cumulative effect of change in accounting principle gain of $6.3 million. The majority of phantom unit grants outstanding under our 1998 and 2005 Long-Term Incentive Plans contain vesting criteria that are based on a combination of performance benchmarks and service period. The 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, $3.00, respectively, and for certain grants, $3.10 per unit. The majority of the phantom units have a final service period vesting in 2011. In addition to exceeding the distribution level of $2.80, it has been deemed probable that the $3.10 distribution level will be achieved. Accordingly, guidance includes, for phantom units tied to performance levels of $3.10 or less, an accrual over the corresponding service period. For 2006, the guidance includes approximately $36.3 million of principally non-cash expense associated with these phantom units. The earliest significant vesting event for outstanding grants will occur in 2007.

The actual amount of LTIP expense amortization in any given year will be directly influenced by our unit price at the end of each reporting period and the amount of amortization in the early years, 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
	Three Months Ending						Six Months Ending						Twelve Months Ending
	June 30, 2006						December 31, 2006						December 31, 2006
	Low			High			Low			High			Low			High
	(in millions)
Reconciliation to Net Income
EBITDA		$ 81.7			$ 91.7			$ 181.4			$ 201.4			$ 363.4			$ 393.4
Depreciation and amortization		(23.1	)		(22.7	)		(48.0	)		(47.2	)		(92.7	)		(91.5	)
EBIT		58.6			69.0			133.4			154.2			270.7			301.9
Interest expense		(18.6	)		(17.8	)		(37.3	)		(35.7	)		(71.2	)		(68.8	)
Net Income		$ 40.0			$ 51.2			$ 96.1			$ 118.5			$ 199.5			$ 233.1

Forward-Looking Statements and Associated Risks

All statements included in this report, other than statements of historical fact, are forward-looking statements, including, but not limited to, statements identified by the words “anticipate,” “believe,” “estimate,” “expect,” “plan,” “intend” and “forecast” and similar expressions and statements regarding our business strategy, plans and objectives of our management for future operations. However, the absence of these words does not mean that the statements are not forward-looking. These statements reflect our current views with respect to future events, based on what we believe are reasonable assumptions. Certain factors could cause actual results to differ materially from results anticipated in the forward-looking statements. These factors include, but are not limited to:

· the success of our risk management activities;

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

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

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

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

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

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

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

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

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

· successful integration and future performance of acquired assets or businesses and the risks associated with operating in lines of business that are distinct and separate from our historical operations;

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

· the effects of competition;

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

· interruptions in service and fluctuations in rates of third party pipelines;

· increased costs or lack of availability of insurance:

· fluctuations in the debt and equity markets, including the price of our units at the time of vesting under our Long-Term Incentive Plans;

· the currency exchange rate of the Canadian dollar;

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

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

· weather interference with business operations or project construction;

· general economic, market or business conditions; and

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

We undertake no obligation to publicly update or revise any forward-looking statements. Further information on risks and uncertainties is available in our filings with the Securities and Exchange Commission, which information is incorporated by reference herein.

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.

PLAINS AAP, L. P., its general partner

PLAINS ALL AMERICAN GP LLC, its general partner

Date: May 3, 2006

/s/ PHIL KRAMER

Phil Kramer

Executive Vice President and Chief Financial Officer