May 26, 2006

VIA EDGAR AND FACSIMILE

Ms. Jill S. Davis

Branch Chief

Securities and Exchange Commission

Division of Corporation Finance

100 F Street, N.E., Stop 7010

Washington, D.C. 20549

Dear Ms. Davis:

On May 9, 2006, the comments of the staff of the Division of Corporation Finance (the “Staff”) of the Securities and Exchange Commission (the “Commission”) to Form 10-K for the fiscal year ended December 31, 2005 (the “2005 Form 10-K”) were faxed to Plains All American Pipeline, L.P. (the “Partnership”). Due to an internal delay in the delivery of the letter, the Partnership did not become aware of its receipt of those comments until May 18, 2006. We contacted Mr. Jonathan Duersch by phone on May 18, 2006 to advise him of our receipt of the comments and our anticipated timing for responding to these comments.

In response to the Staff’s comments, to the extent appropriate, we have included in this letter proposed revisions to our 2005 Form 10-K disclosures. However, the Partnership believes that the revised and supplemental disclosures contained in this letter would not be material to investors who reviewed our 2005 Form 10-K. Accordingly, the Partnership respectfully requests that the Staff permit the Partnership to include any of these revised or supplemental disclosures in its future filings, rather than amending or supplementing the disclosures in the 2005 Form 10-K.

The following responses are for the Staff’s review. For your convenience, we have repeated in bold type each comment of the Staff exactly as given in the Staff’s comment letter.

PLAINS ALL AMERICAN PIPELINE, L.P.

Corporate Headquarters  |  333 Clay Street, Suite 1600, Houston TX  77002  |  713.646.4100

www.paalp.com

Form 10-K for the Fiscal Year Ended December 31, 2005

Management’s Discussion and Analysis of Financial Condition and Results of Operations

Liquidity and Capital Resources

Cash generated from operations, page 74

1.                                      We note that your operating cash flows have decreased significantly in 2005. It appears the primary change from 2004 to your net operating cash flows is related to an increase in accounts receivable at year end 2005. Please expand your disclosures to discuss the primary drivers and trends associated with your cash flows, particularly relating to accounts receivable for all years presented. Your disclosures should provide information about the quality and variability of your earnings and cash flow so that investors may ascertain the indicative value of your reported financial information. Please refer to Financial Reporting Codification (FRC) Section 501.13.b.1 for further guidance on this subject.

Response:  Although disclosures on our primary drivers and trends on earnings are available to the reader in the Executive Summary and the Results of Operations in the report, we will expand our future operating cash flows disclosures using the following or similar language:

Revised Disclosure:

Cash generated from operations

The crude oil market was in contango for much of 2004 and 2005. Because we own crude oil storage capacity, during a contango market we can buy crude oil in the current month and simultaneously hedge the crude by selling it forward for delivery in a subsequent month. This activity can cause significant fluctuations in our cash flow from operating activities as described below.

The primary drivers of cash generated from our operations are (i) the collection of amounts related to the sale of crude oil and LPG and the transportation of crude oil for a fee and (ii) the payment of amounts related to the purchase of crude oil and LPG and other expenses, principally field operating costs and general and administrative expenses. The cash settlement from the purchase and sale of crude oil during any particular month typically occurs within thirty days from the end of the month, except (i) in the months that we store the purchased crude oil and hedge it by selling it forward for delivery in a subsequent month because of contango market conditions or (ii) in months in which we increase our share of linefill in third party pipelines. The storage of crude oil in periods of a contango market can have a material negative impact on our cash flows from operating

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activities for the period in which we pay for and store the crude oil and a material positive impact in the subsequent period in which we receive proceeds from the sale of the crude oil. In the month we pay for the stored crude oil, we borrow under our credit facilities (or pay from cash on hand) to pay for the crude oil, which negatively impacts our operating cash flow. Conversely, cash flow from operating activities increases during the period in which we collect the cash from the sale of the stored crude oil. Similarly, but to a lesser extent, the level of LPG inventory stored and held for resale at period end affects our cash flow from operating activities.

In periods when the market is not in contango, we typically sell our crude oil during the same month in which we purchase it. Our accounts payable and accounts receivable generally vary proportionately because we make payments and receive payments for the purchase and sale of crude oil in the same month, which is the month following such activity. However, when the market is in contango, our accounts receivable, accounts payable, inventory and short-term debt balances are all impacted, depending on the point of the cycle at any particular period end. As a result, we can have significant fluctuations in those working capital accounts, as we buy, store and sell crude oil.

Our cash flow from operating activities was $24.1 million in 2005 and reflects cash generated by our recurring operations (as indicated above in describing the primary drivers of cash generated from operations), offset by changes in components of working capital. The negative impact to cash flows from operations due to changes in components in working capital primarily results from the increase in inventory during 2005. A significant portion of the increased inventory has been purchased and stored due to contango market conditions and was paid for during the period via borrowings under our credit facilities or from cash on hand. As mentioned above, this activity has a negative impact in the period that we pay for and store the inventory. In addition, there was a change in working capital resulting from higher NYMEX margin deposits paid during 2005 that had a negative impact on our cash flows from operations. The fluctuations in accounts receivable and other and accounts payable and other current liabilities are primarily related to purchases and sales of crude oil that generally vary proportionately.

Cash flow from operating activities was $104.0 million in 2004 and reflects cash generated by our recurring operations that was offset negatively by several factors totaling approximately $100 million. The primary factor was a net increase in hedged crude oil and LPG inventory and linefill in third party assets that was financed with borrowings under our credit facilities (approximately $75 million net). Cash flow from operations was also negatively impacted by a decrease of approximately $20 million in prepayments received from counterparties to mitigate credit risk. Our positive cash flow from operating activities for 2003 resulted from cash generated by our recurring operations. In addition, cash flow from operating activities was positively impacted by approximately $74 million related to proceeds received in 2003 from the sale of 2002 hedged crude oil

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inventory and negatively impacted by approximately $100 million related to inventory stored at the end of 2003. The proceeds from the sale of the 2003 stored crude oil were received in the first quarter of 2004. In 2003, we also received approximately $23 million of additional prepayments over the 2002 balance from counterparties to mitigate our credit risk, and paid approximately $6.2 million to terminate an interest rate hedge in conjunction with a change in our capital structure.

Consolidated Statement of Operations, page F-6

2.                                      We note that you present your long-term incentive plan cost, which appear to be similar to a stock-based compensation plan, as a separate component of operating and General and administrative expense. Please modify your presentation to include the expense related to unit-based payment arrangements in the same line item or lines as cash compensation paid to the same employees. Refer to SAB Topic 14:F or SAB 107 for further guidance.

Response:  SAB 107 added SAB Topic 14:F, which provides guidance regarding the application of Statement of Financial Accounting Standards No. 123 (revised 2004), Share-Based Payment, including interpretive guidance related to the classification of compensation expense associated with these payments. We understood that the provisions of SAB 107 generally corresponded to the effective date of SFAS 123 (R), which was effective on January 1, 2006.   Accordingly, in our Quarterly Report on Form 10-Q for the three months ended March 31, 2006, our LTIP expenses are reported on the same line as cash-based payments in the Statement of Operations and prior periods are reclassified to conform to the current period presentation. We will continue to report unit-based payments and to reclassify prior period presentations in this manner in future filings, including our Annual Report on Form 10-K for the year ending December 31, 2006.

Note 1 Organization and Basis of Presentation, page F-10

Basis of Consolidation and Presentation, page F-10

3.                                      We note your disclosure stating, “The accompanying consolidated financial statements of PAA include PAA and all of its wholly-owned subsidiaries.” Please confirm whether all of your direct or indirect consolidated subsidiaries are wholly owned. In the event you consolidate subsidiaries that are less than wholly owned, please expand your disclosure to indicate whether you proportionately consolidate such entities and identify the criteria used in evaluating whether consolidation is appropriate.

Response:  We confirm that all of our direct or indirect consolidated subsidiaries are wholly owned.

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4.                                      Please expand your disclosure to indicate how you evaluate your equity investment for impairment. Refer to paragraph 19.h of APB 18.

Response:  Prior to 2005, our investments in unconsolidated affiliates totaled $8.2 million, which was less than 0.5% of total assets. As disclosed in Note 8, beginning in the third quarter of 2005, we invested in PAA/Vulcan Gas Storage, LLC (“PAA/Vulcan”). As of December 31, 2005, our investment in PAA/Vulcan was $113.5 million, primarily associated with a capital contribution in September 2005. As of December 31, 2005, the aggregate balance of equity investments approximated less than 3% of total assets. We disclosed in Note 8 that we account for the investment in PAA/Vulcan under the equity method in accordance with APB 18. Pursuant to paragraph 20 of APB 18, we considered the significance of our equity investments and also that the PAA/Vulcan investment was made at the end of 2005. For purposes of providing clarity, we propose to expand our disclosure in Note 1 to our Financial Statements using the following or similar language:

Revised Disclosure:

Investments in 50% or less owned affiliates, over which we have significant influence, are accounted for by the equity method. We evaluate our equity investments for impairment in accordance with APB 18: The Equity Method of Accounting for Investments in Common Stock. An impairment of an equity investment results when factors indicate that the investment’s fair value is less than its carrying value and the reduction in value is other than temporary in nature.

Asset Retirement Obligation, page F-15

5.                                      We note your disclosure indicating that you have obligations to retire certain of your assets for which settlement dates are indeterminate. Please tell us if you maintain and replace component parts on regular intervals. Also, please expand your disclosure to indicate why you are unable to reasonably estimate your settlement dates. Additionally, expand your disclosures to specifically describe the legal retirement obligations associated with your long-lived assets. Refer to paragraph 6 of FIN 47.

Response:  In the ordinary course of business, we do maintain and replace component parts on regular intervals. These parts include pumps, valves, motors, mixers, etc. There are no legal requirements concerning disposal of these parts thus there are no asset retirement obligations associated with this activity. We will expand our disclosure as follows to indicate why we are unable to reasonably

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estimate our settlement dates and to specifically describe the legal retirement obligations.

Revised Disclosure:

Some of our assets, primarily related to our pipeline operations segment, do have contractual or regulatory obligations to perform remediation and, in some instances, dismantlement and removal activities when the assets are abandoned. These obligations include varying levels of activity including disconnecting inactive assets from active assets, cleaning and purging assets and, in some cases, completely removing the assets and returning the land to its original state.  The timing of the obligations is determined relative to the date on which the asset is abandoned. Many of our pipelines are trunk and interstate systems that transport crude oil. The pipelines with indeterminate settlement dates have been in existence for many years and with regular maintenance will continue to be in service for many years to come. Also, it is not possible to predict when demand for this transportation will cease and we do not believe that such demand will cease for the foreseeable future. Accordingly, we believe the date when these assets will be abandoned is indeterminate. With no reasonably determinable abandonment date, we cannot reasonably estimate the fair value of the associated asset retirement obligations. We will record asset retirement obligations for these assets in the period in which sufficient information becomes available for us to reasonably determine the settlement dates.   A small portion of our contractual or regulatory obligations are related to assets that are inactive or that we plan to take out of service and although the ultimate timing and cost to settle these obligations are not known with certainty, we can reasonably estimate the obligation. We have estimated that the fair value of these obligations is approximately $4.6 million and $2.5 million at December 31, 2005 and 2004, respectively.

Other, net, F-16

6.                                      Disclose separately your goodwill on the face of your balance sheet. Refer to paragraph 43 of SFAS 142. Additionally, please expand your accounting policy regarding goodwill impairment to describe how you define a reporting unit.

Response:  At December 31, 2005, goodwill was approximately $47 million or 1% of our total assets. We view this amount to be immaterial. SFAS 142 states that the provisions of this Statement need not be applied to immaterial items. We will expand our accounting policy disclosure regarding goodwill impairment to describe how we define a reporting unit using the following or similar language:

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Revised Disclosure:

In accordance with SFAS No. 142, “Goodwill and Other Intangible Assets,” we test goodwill and other indefinite-lived intangible assets at least annually to determine whether impairment has occurred. Goodwill is tested for impairment at a level of reporting referred to as a reporting unit. Pursuant to SFAS 142, a reporting unit is an operating segment or one level below an operating segment for which discrete financial information is available and regularly reviewed by segment management. Our reporting units are one level below our operating segments. If the fair value of a reporting unit exceeds its carrying amount, goodwill of the reporting unit is considered not impaired. An impairment loss is recognized for intangibles if the carrying amount of an intangible asset is not recoverable and its carrying amount exceeds its fair value.

Environmental Matters, page F-16

7.                                      We note your disclosure indicating that you capitalize environmental liabilities assumed in business combinations. Please modify your disclosure to clarify what you mean by “capitalize” and whether you are referring to recording the liability assumed or an asset associated with the liability, which qualifies for capitalization treatment. Refer to EITF 90-8.

Response:  We were referring to recording the liability assumed. See revised disclosure below.

Revised Disclosure:

We expense expenditures that relate to an existing condition caused by past operations, which do not contribute to current or future revenue generation. We record environmental liabilities assumed in business combinations based on the estimated fair value of the environmental obligations caused by past operations of the acquired company.

Note 3 Acquisitions and Dispositions, page F-19

Significant Acquisitions, page F-20

8.                                      We note your acquisitions of the North American crude pipeline operations of Link Energy LLC and the interests of two entities of Shell Pipeline Company LP. Additionally, we note your other aggregate acquisitions in 2005. We were unable to locate the associated pro forma disclosures for these acquisitions prescribed by paragraphs 54-55 of SFAS 141. Please expand your disclosures accordingly or tell us why this literature would not apply.

Response:  The pro forma disclosures for the 2004 acquisitions were included in our 2004 10-K. These acquisitions were effective in March and April of 2004. Thus, the results of operations of these acquisitions are included in nine months or

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more of 2004 and the entire year of 2005. As a result, the reiteration of the 2004 pro forma information was not deemed to provide meaningful information to the readers of our 2005 10-K. The 2005 acquisitions were not material to our results of operations either individually or in the aggregate as they accounted for 0.1% of revenues in each year and 3.8% and 2.5% of net income in 2004 and 2005, respectively.

Note 8 Related Party Transactions, F-32

Reimbursement of Expenses of Our General Partner and Its Affiliates

9.                                      We note your disclosure indicating that you reimburse your General Partner for all direct and indirect costs. Please expand your disclosures to clarify how and when you record expense reimbursements to your general partner. Additionally, we note your statement that your general partner, “will determine the expenses allocated to us in any reasonable manner determined by our general partner in its sole discretion.” Please confirm that all costs of doing business are appropriately allocated to Plains All American Pipeline, L.P. Refer to SAB Topic 1:B.

Response:  We record expense reimbursements to our general partner in the period in which the expense is incurred by our general partner. Our general partner appropriately allocates to us all costs associated with carrying out our operations. Accordingly, we confirm that we believe all costs of doing business are properly reflected, in all material respects, in the Partnership’s consolidated financial statements.

Revised Disclosure:

We reimburse our general partner for all direct and indirect costs of services provided to us, including the costs of employee, officer and director compensation and benefits allocable to us, and all other expenses necessary or appropriate to the conduct of our business, and allocable to us. We record these costs on the accrual basis in the period in which our general partner incurs them.

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Performance Option Plan

10.                               We note your disclosure in which owners of your general partner contributed 450,000 subordinate units to the general partner in connection with your performance option plan, which appear to include variable exercise price terms. Additionally, we note your indication that because these units were contributed to the general partner no reimbursement obligation exists to the general partner for the cost of these units upon exercise of the options. Please clarify whether you recognized expense upon issuance and subsequent measurement of these options involving your subordinate units. Please tell us how you considered the application of SAB Topic I:B.2 and SAB Topic 5T as amended by SAB Topic 14.

Response:

The expense related to the performance option plan is determined using fair value and is not recorded on the Partnership’s books as it relates to costs incurred for services rendered to our general partner. This plan is specific to the general partner and not the Partnership. Accordingly, we believe that the performance option plan expense is appropriately recorded at the general partner level and all costs of doing business are properly reflected, in all material respects, in the Partnership’s consolidated financial statements.

We considered a variety of different literature, including but not limited to SAB Topic 1B, Question 2; SAB Topic 5T; SFAS 123; EITF 00-12 and others. The concepts in most of such guidance is not applicable because in this specific fact pattern, the general partner granted an award to an employee of its general partner (an economic interest holder in the general partner); however, the award is not equity in the general partner but rather an asset (i.e. subordinated units that subsequently converted to common units) owned by the general partner. In addition, the concept discussed within these references relates to costs incurred on behalf of an entity for services rendered to the entity. As further described below, the cost related to the performance option plan is specific to the general partner and the Partnership did not receive any benefit (i.e. the activities described below do not impact the Partnership) nor was the cost incurred on behalf of the Partnership. There is a separate and distinct compensation program for those individuals that perform services on behalf of the Partnership (see Item 11 and Note 9 to our Consolidated Financial Statements).

The performance option plan was implemented to provide incentives to the general partner management group to manage the activities of the general partner. These management responsibilities include a variety of duties, including but not limited to:

•      filing U.S. federal, state and Canadian tax returns for the general partner;

•      maintaining accounting records to file an audited balance sheet of the general partner as required by the Commission in transactional filings of the Partnership;

•      corporate governance of the general partner; and

•      other similar duties.

The percentage of the cost of these options when compared to the aggregate compensation received by these individuals (cash salary, bonuses, performance

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options and LTIPs) was approximately 10%, on average, of total compensation received from the Partnership and the general partner on a combined basis from 2001, the year of grant, through 2005. This is viewed as a reasonable portion specifically attributable to the management of the general partner. This reference is not to suggest that an allocation was used to determine the expense to be reflected on the Partnership’s financial statements, but rather to provide additional substance that the expense related to the awards of the performance option plan is properly recorded at the general partner level.

Accordingly, in considering all of the factors above, we continue to believe that the costs of doing business are reflected, in all material respects, in the Partnership’s consolidated financial statements. Further, the expense related to the performance option plan is reasonable in relation to the services performed for the general partner and is appropriately recorded at the general partner level.

We would propose clarifying our disclosure as follows:

Revised Disclosure:

In 2001, the owners of the general partner (other than PAA Management, L.P.) contributed an aggregate of 450,000 subordinated units (now converted into common units) to the general partner to provide a pool of units available for the grant of options to management and key employees. In that regard, the general partner adopted the Plains All American 2001 Performance Option Plan, pursuant to which options to purchase approximately 448,000 units have been granted. Because the awards are for services provided to the general partner, the expense associated with the awards is recorded on the general partner’s financial statements. Our general partner has recognized expense associated with these awards of $7.7 million, $2.6 million and $0.7 million for the years ended December 31, 2005, 2004 and 2003, respectively. As of December 31, 2005, approximately 169,000 options remain outstanding under the plan, all of which are fully vested. The original exercise price of the options was $22 per unit, declining over time by an amount equal to 80% of the quarterly distribution payable with respect to each unit. As of December 31, 2005, the exercise price was approximately $13.85 per unit. The

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terms of future grants may differ from those of the existing grants. Because the costs are specific to the general partner and the units underlying the plan were contributed to the general partner, the Partnership has no obligation to reimburse the general partner for the cost of the units upon exercise of the options. In November and December of 2005, our general partner sold approximately 170,000 of the units subject to the plan for cash. The proceeds of the sales were allocated among the payment of tax liabilities and cash payments to optionees and to owners of the general partner.

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Note 9 Long-Term Incentive Plan, page F-35

11.                               We note that your general partner maintains and controls the unit compensation plans associated with incentives implemented to operate your business, although it appears you are ultimately responsible for issuing the unit compensation. Please clarify how your general partner applies the guidance of APB 25 and SFAS 123 in accounting for unit compensation. Compare and contrast a “cash plan probability model”, as described on page F-17, to a fair value model and demonstrate why it is an appropriate model in formulating an expense reflective of your compensation costs of issuing your units. Additionally, describe how you have accounted for the declining exercise price terms in your employee phantom units.

Response:

Our general partner maintains and controls our 1998 and 2005 Long-Term Incentive Plans (the LTIPs). The plans are administered by the Compensation Committee of our general partner’s board of directors and our general partner’s board of directors, in its discretion, may terminate the LTIPs at any time with respect to any limited partner units for which a grant has not yet been made. In addition, regardless of the settlement method, our general partner is responsible for settling the awards granted under both plans. Limited partner units to be delivered upon the vesting of awards may be limited partner units acquired by our general partner in the open market or in private transactions, limited partner units already owned by our general partner, or any combination of the foregoing. In addition, our general partner has the unilateral right to instruct us to issue new units. In conjunction with our agreement to reimburse our general partner for all direct and indirect costs of services provided on our behalf, we will reimburse our general partner for any costs incurred in conjunction with settling the awards under the LTIPs.

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Our general partner considered both APB 25 and SFAS 123 in determining the appropriate accounting for the LTIPs. It is our understanding, based on FIN 44, that APB 25 is not applicable to awards that are granted to employees based on the stock of another entity. Additionally, it is our understanding that SFAS 123, as interpreted by EITF 96-18, applies to all transactions in which an entity acquires goods or services by issuing equity instruments or by incurring liabilities to the supplier in amounts based on the price of the entity’s common stock or other equity instruments. The use of the term “supplier” encompasses both employee and non-employee providers of goods and services.

As mentioned above, the LTIPs are controlled and administered by our general partner. As disclosed in Note 8 to our Consolidated Financial Statements, the Partnership does not directly employ any persons to manage or operate our business. These functions are provided primarily by our general partner and its employees. Our general partner has issued awards for which the underlying securities are the units of an equity method investee (at the time the Partnership was an equity method investee of our general partner, which was an equity method investee of its general partner). Accordingly, the accounting models prescribed by these standards are not applicable since the units granted are not equity instruments of the general partner.

Since APB 25 and SFAS 123 were not applicable, our general partner considered what the appropriate accounting model should be and determined that the appropriate model would be based on a concept similar to APB 12 whereby the amount accrued should be based on fair value using the probability that the grant provisions would be met and accrued over the period of service in a systematic and rational manner. In this case, the period of service would correspond to the vesting period, which is the date the employee has earned the award. This model would be comparable to a performance plan or cash plan model whereby the measurement of compensation expense would be required if it is probable that the performance goals will be attained by the end of the life of the awards. The amount required to settle the awards will be based on the unit price on the date that vesting occurs, and thus an estimate of the ultimate settlement price is used to determine the obligation that should be accrued at every reporting date.

Although our general partner has not followed SFAS 123 and thus has not calculated the fair value of the outstanding awards under that guidance, we believe that the model that has been applied would not have a materially different result over the life of the awards. The primary reason for this assertion is that the ultimate amount of compensation expense recognized under both models is based on the market price of the units on the date that the award is settled.

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As disclosed in Note 2 to our Consolidated Financial Statements, effective January 1, 2006 our general partner has adopted EITF 04-05, which resulted in the consolidation of the Partnership into the general partner. Following the adoption of EITF 04-05, we are part of the same consolidated group and thus SFAS 123(R) is applicable to the LTIPs. We adopted SFAS 123(R) effective January 1, 2006.

The last sentence of your Comment # 11 states, “Additionally, describe how you have accounted for the declining exercise price terms in your employee phantom units.”  All of the awards granted under the 1998 LTIP and 2005 LTIP are phantom units that do not have an exercise price and thus there is no declining exercise price.

Note 10 Commitments and Contingencies F-37

12.                               We note your disclosure regarding potential civil penalty enforcement action related to oil releases, your preliminary assessment of damages related to hurricanes and your general disclosure of various legal proceedings and claims. Please expand your disclosure to include assessments of the likelihood of these loss contingencies using terms as defined in paragraph 3 of SFAS 5. Confirm whether you have disclosed all reasonably possible contingent losses, which could individually or in the aggregate have a material impact on your financial condition.

Response:  Although we do not typically disclose our probability assessment on a case-by-case basis because we believe such disclosure provides an unwarranted advantage to adversary parties, we will expand our disclosure using the following or similar language. In addition, we confirm that we have disclosed all reasonably possible contingent losses that could individually or in the aggregate have a material impact on the Partnership’s financial condition.

Revised Disclosure:

Pipeline Releases.   In January 2005 and December 2004, we experienced two unrelated releases of crude oil that reached rivers located near the sites where the releases originated. In early January 2005, an overflow from a temporary storage tank located in East Texas resulted in the release of approximately 1,200 barrels of crude oil, a portion of which reached the Sabine River. In late December 2004, one of our pipelines in West Texas experienced a rupture that resulted in the release of approximately 4,500 barrels of crude oil, a portion of which reached a remote location of the Pecos River. In both cases, emergency response personnel under the supervision of a unified command structure consisting of

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representatives of Plains Pipeline, the U.S. Environmental Protection Agency (“EPA”), the Texas Commission on Environmental Quality and the Texas Railroad Commission conducted clean-up operations at each site. Approximately 980 and 4,200 barrels were recovered from the two respective sites. The unrecovered oil was removed or otherwise addressed by us in the course of site remediation. Aggregate costs associated with the releases, including estimated remediation costs, are estimated to be approximately $4.5 million to $5.0 million. In cooperation with the appropriate state and federal environmental authorities, we have substantially completed our work with respect to site restoration, subject to some ongoing remediation at the Pecos River site. We have been informed by EPA that it has referred these two crude oil releases, as well as several other smaller releases, to the U.S. Department of Justice for further investigation in connection with a possible civil penalty enforcement action under the Federal Clean Water Act. Our assessment is that it is probable we will pay penalties related to the two releases. We have accrued the estimated loss contingency, which is included in the estimated aggregate costs set forth above. It is reasonably possible that the loss contingency may exceed our estimate with respect to penalties assessed by EPA; however, we have no indication from EPA or the Department of Justice of what penalties might be sought. As a result, we are unable to estimate the range of a reasonably possible loss contingency in excess of our accrual.

General.   We, in the ordinary course of business, are a claimant and /or a defendant in various legal proceedings. To the extent we are able to assess the likelihood of a negative outcome for these proceedings, our assessments of such likelihood range from remote to probable. If we determine that a negative outcome is probable and the amount of loss is reasonably estimable, we accrue the estimated amount. We do not believe that the outcome of these legal proceedings, individually and in the aggregate, will have a materially adverse effect on our financial condition, results of operations or cash flows.

…………

Hurricanes Katrina and Rita.   During the third quarter of 2005, we experienced damage to various facilities and equipment resulting from hurricanes in the Gulf of Mexico. We have substantially completed preliminary assessments of damages and repair efforts are underway. Such repairs, which we believe all material amounts are subject to reimbursement under our insurance policies, are being expensed as incurred. Additionally, we have recognized approximately $1.0 million related to environmental remediation obligations incurred as a result of the hurricanes.

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Closing Comments

The Partnership acknowledges that:

•                  it is responsible for the adequacy and accuracy of the disclosure in the filing;

•                  staff comments or changes to disclosure in response to staff comments in the filings reviewed by the staff do not foreclose the Commission from taking any action with respect to the filing; and

•                  it may not assert staff comments as a defense in any proceeding initiated by the Commission or any person under the federal securities laws of the United States.

Should the Staff have any questions or comments, please contact the undersigned at 713.646.4100 or Phil Kramer, Chief Financial Officer of Plains All American Pipeline, L.P. at the same number.

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