Edgar Filing: PLAINS ALL AMERICAN PIPELINE LP

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TABLE OF CONTENTS
INDEX TO FINANCIAL STATEMENTS

As filed with the Securities and Exchange Commission on December 10, 2004

Registration No. 333-

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM S-4
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933

PLAINS ALL AMERICAN PIPELINE, L.P.
PAA FINANCE CORP.*
(Exact Name of Registrant as Specified in its Charter)

Delaware
Delaware
(State or Other Jurisdiction of
Incorporation or Organization)

4610
4610
(Primary Standard Industrial
Classification Code Number)

76-0582150
76-0669671
(I.R.S. Employer
Identification Number)

333 Clay Street, Suite 1600
Houston, Texas 77002
(713) 646-4100
(Address, Including Zip Code, and Telephone Number, including
Area Code, of Registrant's Principal Executive Offices)

Tim Moore
Vice President and General Counsel
333 Clay Street, Suite 1600
Houston, Texas 77002
(713) 646-4100
(Name, Address, Including Zip Code, and Telephone Number,
Including Area Code, of Agent for Service)

Copy to:
David P. Oelman
Vinson & Elkins L.L.P.
1001 Fannin Street, Suite 2300
Houston, Texas 77002
(713) 758-2222

Approximate date of commencement of proposed sale to the public: As soon as practicable after the effective date of this Registration Statement.

If the securities being registered on this Form are being offered in connection with the formation of a holding company and there is compliance with General Instruction G, check the following box. o

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

If this Form is a post effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

CALCULATION OF REGISTRATION FEE

Title of Each Class of Securities to be Registered	Amount to be Registered	Proposed Maximum Offering Price per Note	Proposed Maximum Aggregate Offering Price	Amount of Registration Fee


4.750% Senior Notes due 2009	$175,000,000	100%	$175,000,000	$22,173

Guarantees⁽²⁾	—	—	—	—

5.875% Senior Notes due 2016	$175,000,000	100%	$175,000,000	$22,173

Guarantees⁽²⁾	—	—	—	—

Total	$350,000,000	100%	$350,000,000	$44,346

⁽¹⁾: Determined in accordance with Rule 457(f) under the Securities Act of 1933, as amended.
⁽²⁾: No separate consideration will be received for the guarantees, and no separate fee is payable pursuant to Rule 457(a) under the Securities Act of 1933.
*: Includes certain subsidiaries of Plains All American Pipeline, L.P. identified on the following pages.

Plains Marketing, L.P. (Exact Name of Registrant As Specified In Its Charter)
Delaware		76-0684572
(State or Other Jurisdiction of Incorporation or Organization)		(I.R.S. Employer Identification Number)
Plains Pipeline, L.P. (Exact Name of Registrant As Specified In Its Charter)
Texas		76-0587185
(State or Other Jurisdiction of Incorporation or Organization)		(I.R.S. Employer Identification Number)
Plains Marketing GP Inc. (Exact Name of Registrant As Specified In Its Charter)
Delaware		76-0684572
(State or Other Jurisdiction of Incorporation or Organization)		(I.R.S. Employer Identification Number)
Plains Marketing Canada LLC (Exact Name of Registrant As Specified In Its Charter)
Delaware		76-0653735
(State or Other Jurisdiction of Incorporation or Organization)		(I.R.S. Employer Identification Number)
Plains Marketing Canada, L.P. (Exact Name of Registrant As Specified In Its Charter)
Canada		892946211
(State or Other Jurisdiction of Incorporation or Organization)		(GST Number)
PMC (Nova Scotia) Company (Exact Name of Registrant As Specified In Its Charter)
Nova Scotia		894798610
(State or Other Jurisdiction of Incorporation or Organization)		(GST Number)
Basin Holdings GP LLC (Exact Name of Registrant As Specified In Its Charter)
Delaware		13-4204744
(State or Other Jurisdiction of Incorporation or Organization)		(I.R.S. Employer Identification Number)
Basin Pipeline Holdings, L.P. (Exact Name of Registrant As Specified In Its Charter)
Delaware		13-4204757
(State or Other Jurisdiction of Incorporation or Organization)		(I.R.S. Employer Identification Number)
Rancho Holdings GP LLC (Exact Name of Registrant As Specified In Its Charter)
Delaware		13-4204734
(State or Other Jurisdiction of Incorporation or Organization)		(I.R.S. Employer Identification Number)
Rancho Pipeline Holdings, L.P. (Exact Name of Registrant As Specified In Its Charter)
Delaware		13-4204750
(State or Other Jurisdiction of Incorporation or Organization)		(I.R.S. Employer Identification Number)

The Registrants hereby amend this Registration Statement on such date or dates as may be necessary to delay its effective date until the Registrants shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the Registration Statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.

The information in this prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any state where the offer or sale is not permitted.

Subject To Completion, Dated December 10, 2004

Prospectus

Plains All American Pipeline, L.P.
PAA Finance Corp.

Offer to Exchange up to
$175,000,000 of 4.750% Senior Notes due 2009
for
$175,000,000 of 4.750% Senior Notes due 2009
that have been Registered under the Securities Act of 1933
and
Offer to Exchange up to
$175,000,000 of 5.875% Senior Notes due 2016
for
$175,000,000 of 5.875% Senior Notes due 2016
that have been Registered under the Securities Act of 1933

Terms of the Exchange Offers

• We are offering to exchange up to $175,000,000 of our outstanding 4.750% Senior Notes due 2009 ("2009 Notes") and up to $175,000,000 of our outstanding 5.875% Senior Notes due 2016 ("2016 Notes," and together with the 2009 Notes, the "Outstanding Notes") for new Notes with substantially identical terms that have been registered under the Securities Act and are freely tradable.

• We will exchange for an equal principal amount of new Notes all outstanding Notes of the same series that you validly tender and do not validly withdraw before the exchange offers expire.

•    Each exchange offer will expire at 5:00 p.m., New York City time, on                        , 200 , unless extended. We do not currently intend to extend either exchange offer.

•    Tenders of outstanding Notes may be withdrawn at any time prior to the expiration of the applicable exchange offer.

•    Each exchange of outstanding Notes for new Notes will not be a taxable event for U.S. federal income tax purposes.

Terms of the 2009 Notes Offered in the Exchange Offer

Maturity
•    The 2009 Notes will mature on August 15, 2009.

Interest
•    We will pay interest on the 2009 Notes semi-annually in arrears on February 15 and August 15 of each year, beginning February 15, 2005.

•    Interest will accrue from August 12, 2004.

Redemption
• We may redeem the 2009 Notes, in whole or in part, at any time at a price equal to 100% of the principal amount of the 2009 Notes to be redeemed plus a make-whole premium described in this prospectus, plus accrued and unpaid interest, if any, to the redemption date.

Ranking
• The 2009 Notes are unsecured. The 2009 Notes are general senior unsecured obligations of the issuers and will rank equally with the Notes of the other series and with the existing and future senior unsecured indebtedness of the issuers.

Terms of the 2016 Notes Offered in the Exchange Offer

Maturity
•    The 2016 Notes will mature on August 15, 2016.

Interest
•    We will pay interest on the 2016 Notes semi-annually in arrears on February 15 and August 15 of each year, beginning February 15, 2005.

•    Interest will accrue from August 12, 2004.

Redemption
• We may redeem the 2016 Notes, in whole or in part, at any time at a price equal to 100% of the principal amount of the 2016 Notes to be redeemed plus a make-whole premium described in this prospectus, plus accrued and unpaid interest, if any, to the redemption date.

Ranking
• The 2016 Notes are unsecured. The 2016 Notes are general senior unsecured obligations of the issuers and will rank equally with the Notes of the other series and with the existing and future senior unsecured indebtedness of the issuers.

Please read "Risk Factors" on page 7 for a discussion of factors you should consider before participating in the exchange offers.

These securities have not been approved or disapproved by the Securities and Exchange Commission or any state securities commission nor has the Securities and Exchange Commission passed upon the accuracy or adequacy of this prospectus. Any representation to the contrary is a criminal offense.

The date of this prospectus is , 2004.

This prospectus is part of a registration statement we filed with the Securities and Exchange Commission, or SEC. In making your investment decision, you should rely only on the information contained in this prospectus and in the accompanying letters of transmittal. We have not authorized anyone to provide you with any other information. If you receive any unauthorized information, you must not rely on it. We are not making offers to sell these securities in any state where the offers are not permitted. You should not assume that the information contained in this prospectus is accurate as of any date other than the date on the front cover of this prospectus.

Each broker-dealer that receives the Notes for its own account pursuant to these exchange offers must acknowledge in the applicable letter of transmittal that it will deliver a prospectus in connection with any resale of the Notes. This prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer in connection with resales of the Notes received in exchange for outstanding Notes where such outstanding Notes were acquired by such broker-dealer as a result of market-making activities or other trading activities. We have agreed to make this prospectus available for a period of one year from the expiration date of these exchange offers to any broker-dealer for use in connection with any such resale. See "Plan of Distribution."

TABLE OF CONTENTS

PROSPECTUS SUMMARY		1
RISK FACTORS		7
	Risks Related to Our Business	7
	Risks Related to the Exchange Offers and the Notes	11
USE OF PROCEEDS		15
RATIO OF EARNINGS TO FIXED CHARGES		15
EXCHANGE OFFERS		16
	Purpose and Effect of the Exchange Offers	16
	Resale of New Notes	18
	Terms of the Exchange Offers	18
	Expiration Date	19
	Extensions, Delays in Acceptance, Termination or Amendment	19
	Conditions to the Exchange Offers	20
	Procedures for Tendering	21
	Withdrawal of Tenders	22
	Fees and Expenses	23
	Transfer Taxes	23
	Consequences of Failure to Exchange	23
	Accounting Treatment	23
	Other	23
SELECTED HISTORICAL FINANCIAL AND OPERATING DATA		24
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		27
	Introduction	27
	Executive Summary	27
	Acquisitions	29
	Critical Accounting Policies and Estimates	34
	Recent Accounting Pronouncements	36
	Change in Accounting Principle	36
	Results of Operations	37
	Outlook	55

	Liquidity and Capital Resources	57
	Off-Balance Sheet Arrangements	65
	Quantitative and Qualitative Disclosures About Market Risks	65
BUSINESS		68
	General	68
	Business Strategy	68
	Financial Strategy	69
	Recent Developments	71
	Organizational History	72
	Partnership Structure and Management	73
	Acquisitions and Dispositions	74
	Description of Segments and Associated Assets	79
	Gathering, Marketing, Terminalling and Storage Operations	87
	Customers	94
	Competition	95
	Regulation	95
	Environmental, Health and Safety Regulation	99
	Operational Hazards and Insurance	103
	Title to Properties and Rights-of-Way	104
	Employees	104
	Litigation	105
	Unauthorized Trading Loss	106
MANAGEMENT		107
	Partnership Management and Governance	107
	Directors and Executive Officers	109
	Executive Compensation	114
	Employment Contracts and Termination of Employment and Change-in-Control Arrangements	115
	1998 Long-Term Incentive Plan	116
	2005 Long-Term Incentive Plan	118
	Other Equity Grants	118
	Compensation of Directors	118
	Reimbursement of Expenses of Our General Partner and its Affiliates	119
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS		120
	Our General Partner	120
	Transactions with Related Parties	120
DESCRIPTION OF NOTES		125
	General Description of the Notes and the Guarantees	125
	Further Issuances	126
	Principal, Maturity and Interest	126
	No Liability of General Partner	126
	The Guarantees	126
	Optional Redemption	127
	Events of Default	128
	Consolidation, Merger or Sale	129
	Modification of the Indenture	130
	Covenants	131
	SEC Reports	133
	Defeasance and Discharge	133
	Concerning the Trustee	134
	Governing Law	134
	Definitions	134

TAX CONSIDERATIONS			138
PLAN OF DISTRIBUTION			138
VALIDITY OF THE NEW NOTES			139
EXPERTS			139
WHERE YOU CAN FIND MORE INFORMATION			140
FORWARD-LOOKING STATEMENTS			141
INDEX TO FINANCIAL STATEMENTS			F-1

iii

PROSPECTUS SUMMARY

This summary may not contain all the information that may be important to you. You should read this entire prospectus before deciding to participate in the exchange offers. You should carefully consider the information set forth under "Risk Factors." In addition, certain statements include forward-looking information which involves risks and uncertainties. Please read "Forward-Looking Statements." References to the "Notes" in this prospectus include both the outstanding Notes and the new Notes.

In this prospectus, the terms "we," "our," "ours," and "us" refer to Plains All American Pipeline, L.P. and its subsidiaries, unless otherwise indicated or the context requires otherwise.

Plains All American Pipeline, L.P.

We are a publicly traded Delaware limited partnership 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. We refer to liquefied petroleum gas and other petroleum products collectively as "LPG." We have an extensive network of pipeline transportation, storage and gathering assets in key oil producing basins and at major market hubs in the United States and Canada. Several members of our existing management team founded this midstream crude oil business in 1992, and we completed our initial public offering in 1998.

We have operations in the United States and Canada, which can be categorized into two primary business activities: crude oil pipeline transportation operations and gathering, marketing, terminalling and storage operations.

Our executive offices are located at 333 Clay Street, Suite 1600, Houston, Texas 77002 and our telephone number is (713) 646-4100.

Business Strategy

Our principal business strategy is to capitalize on the regional crude oil supply and demand imbalances that exist in the United States and Canada by combining the strategic location and distinctive capabilities of our transportation and terminalling assets with our extensive marketing and distribution expertise to generate sustainable earnings and cash flow.

We intend to execute our business strategy by:

•: increasing and optimizing throughput on our existing pipeline and gathering assets and realizing cost efficiencies through operational improvements;
•: utilizing and expanding our Cushing Terminal and our other assets to service the needs of refiners and to profit from merchant activities that take advantage of crude oil pricing and quality differentials;
•: selectively pursuing strategic and accretive acquisitions of crude oil transportation assets, including pipelines, gathering systems, terminalling and storage facilities and other assets that complement our existing asset base and distribution capabilities;
•: optimizing and expanding our Canadian operations and our presence in the Gulf Coast and Gulf of Mexico to take advantage of anticipated increases in the volume and qualities of crude oil produced in these areas; and
•: prudently and economically leveraging our asset base, knowledge base and skill sets to participate in energy businesses that are closely related to, or significantly intertwined with, the crude oil business.

To a lesser degree, we also engage in a similar business strategy with respect to the wholesale marketing and storage of LPG, which we began as a result of an acquisition in mid-2001.

The Exchange Offers

On August 12, 2004, we completed private offerings of $175 million aggregate principal amount of our 4.750% senior notes due 2009 ("2009 Notes") and $175 million aggregate principal amount of our 5.875% senior notes due 2016 ("2016 Notes" and together with the 2009 Notes, the "outstanding Notes"). We entered into registration rights agreements with the initial purchasers in those offerings, in which we agreed to deliver to you this prospectus and to use our reasonable best efforts to complete the exchange offers within 240 days after the date we issued the outstanding Notes.

Exchange Offers	We are offering to exchange new Notes (the "New Notes") for:
	•	up to $175 million principal amount of our 4.750% 2009 Notes that have been registered under the Securities Act of 1933 (the "Securities Act"), for an equal amount of our outstanding 2009 Notes; and
	•	up to $175 million principal amount of our 5.875% 2016 Notes that have been registered under the Securities Act for an equal amount of our outstanding 2016 Notes
	to satisfy our obligations under the registration rights agreements that we entered into when we issued the outstanding Notes in transactions exempt from registration under the Securities Act.
	The terms of each series of the new Notes are substantially identical to those terms of each series of the outstanding Notes, except that the transfer restrictions, registration rights and provisions for additional interest relating to the outstanding Notes do not apply to the new Notes.
Expiration Date	Each exchange offer will expire at 5:00 p.m. New York City time, on , 200 , unless we decide to extend either exchange offer. We may extend one exchange offer without extending the other.
Condition to the Exchange Offers	The registration rights agreements do not require us to accept outstanding Notes for exchange if the applicable exchange offer or the making of any exchange by a holder of the outstanding Notes would violate any applicable law or interpretation of the staff of the SEC. A minimum aggregate principal amount of outstanding Notes being tendered is not a condition to either exchange offer.
Procedures for Tendering Outstanding Notes	To participate in an exchange offer, you must follow the procedures established by The Depository Trust Company, which we call "DTC," for tendering notes held in book-entry form. These automated tender offer program procedures, which we call "ATOP," require that (i) the exchange agent receive, prior to the expiration date of the applicable exchange offer, a computer generated message known as an "agent's message" that is transmitted through ATOP and (ii) DTC confirms that:
	•	DTC has received your instructions to exchange your Notes, and

	•	you agree to be bound by the terms of the applicable letter of transmittal.
	For more information on tendering your outstanding Notes, please refer to the sections in this prospectus entitled "Exchange Offers—Terms of the Exchange Offers" and "—Procedures for Tendering."
Guaranteed Delivery Procedures	None.
Withdrawal of Tenders	You may withdraw your tender of outstanding Notes under either exchange offer at any time prior to the expiration date. To withdraw, you must submit a notice of withdrawal to the exchange agent using ATOP procedures before 5:00 p.m. New York City time on the expiration date of the exchange offer. Please read "Exchange Offers—Withdrawal of Tenders."
Acceptance of Outstanding Notes and Delivery of New Notes	If you fulfill all conditions required for proper acceptance of outstanding Notes, we will accept any and all outstanding Notes that you properly tender in the applicable exchange offer on or before 5:00 p.m. New York City time on the expiration date. We will return to you, without expense as promptly as practicable after the expiration date, any outstanding Note that we do not accept for exchange. We will deliver the new Notes as promptly as practicable after the expiration date and acceptance of the outstanding Notes for exchange. Please refer to the section in this prospectus entitled "Exchange Offers—Terms of the Exchange Offers."
Fees and Expenses	We will bear all expenses related to each exchange offer. Please refer to the section in this prospectus entitled "Exchange Offers—Fees and Expenses."
Use of Proceeds	The issuance of the new Notes will not provide us with any new proceeds. We are making these exchange offers solely to satisfy our obligations under the registration rights agreements.
Consequences of Failure to Exchange Outstanding Notes	If you do not exchange your outstanding Notes in the applicable exchange offer, you will no longer be able to require us to register the outstanding Notes under the Securities Act except in the limited circumstances provided under the applicable registration rights agreement. In addition, you will not be able to resell, offer to resell or otherwise transfer the outstanding Notes unless we have registered the outstanding Notes under the Securities Act, or unless you resell, offer to resell or otherwise transfer them under an exemption from the registration requirements of, or in a transaction not subject to, the Securities Act.
Tax Considerations	The exchange of new Notes for 2009 Notes and the exchange of new Notes for 2016 Notes should not be a taxable event for U.S. federal income tax purposes. Please read "Tax Considerations."

Exchange Agent

We have appointed Wachovia Bank, National Association, as exchange agent for each of the exchange offers. You should direct questions and requests for assistance and requests for additional copies of this prospectus or the letters of transmittal to the exchange agent addressed as follows: Wachovia Bank, National Association, Customer Information Center, Corporate Trust Operations—NC1153, 1525 West W. T. Harris Blvd. Charlotte, North Carolina 28288-1153. Eligible institutions may make requests by facsimile at (704) 590-7628.

Terms of the New Notes

The new Notes will be identical to the outstanding Notes except that the new Notes are registered under the Securities Act and will not have transfer restrictions, registration rights or provisions for additional interest. The new Notes will evidence the same debt as the outstanding Notes, and the same indenture will govern the new Notes and the outstanding Notes.

The following summary contains basic information about the new Notes and is not intended to be complete. It does not contain all the information that is important to you. For a more complete understanding of the notes, please refer to the section of this prospectus entitled "Description of Notes."

Issuers		Plains All American Pipeline, L.P. and PAA Finance Corp. PAA Finance Corp., a Delaware corporation, is an indirect wholly owned subsidiary of Plains All American Pipeline, L.P. that has been organized for the purpose of co-issuing our existing notes, the Notes offered hereby, and the notes issued in any future offerings. PAA Finance Corp. does not have any operations of any kind and will not have any revenue other than as may be incidental to its activities as a co-issuer of the Notes.
Notes Offered		$175 million aggregate principal amount of the 2009 Notes.
		$175 million aggregate principal amount of the 2016 Notes.
Maturity Dates		August 15, 2009 for the 2009 Notes.
		August 15, 2016 for the 2016 Notes.
Interest Payment Dates		We will pay interest on the Notes of each series semi-annually in arrears on February 15 and August 15 of each year, beginning on February 15, 2005.
Optional Redemption		We may redeem the Notes of either series, in whole or in part, at any time and from time to time at a price equal to the greater of (i) 100% of the principal amount of Notes to be redeemed or (ii) the sum of the present values of the remaining scheduled payments of principal of and interest on the Notes to be redeemed discounted to the redemption date on a semi-annual basis at the Adjusted Treasury Rate (as defined herein) plus 20 basis points, in the case of the 2009 Notes, and 25 basis points, in the case of the 2016 Notes plus, in each case, accrued interest to the date of redemption. See "Description of Notes—Optional Redemption."
Guarantees		Initially, all payments with respect to the Notes (including principal and interest) are fully and unconditionally guaranteed, jointly and severally, by substantially all of our existing subsidiaries. In the future, our subsidiaries that guarantee other indebtedness of ours or another subsidiary must also guarantee the Notes. The guarantees are also subject to release in certain circumstances. The guarantees of each series are general unsecured obligations of the subsidiary guarantors and rank equally with the guarantees of the other series and with any existing and future senior unsecured indebtedness of the subsidiary guarantors.

Ranking	The Notes are general senior unsecured obligations of the issuers and rank equally with the Notes of the other series and with the existing and future senior unsecured indebtedness of the issuers.
Certain Covenants	The indenture governing the Notes contains covenants for your benefit. These covenants restrict our ability and our restricted subsidiaries' ability, with certain exceptions, to:
	•	incur liens on principal properties to secure debt;
	•	engage in sale-leaseback transactions; or
	•	merge or consolidate with another entity or sell, lease or transfer substantially all of our properties or assets to another entity.
Transfer Restrictions; Absence of a Public Market for the Notes	The new Notes generally will be freely transferable, but will also be new securities for which there will not initially be a market. There can be no assurance as to the development or liquidity of any market for the new Notes.
Form of New Notes	The new Notes will be represented by one or more global notes. The global notes of each series will be deposited with the trustee, as custodian for DTC. The global notes of each series will be shown on, and transfers of the global notes of each series will be effected only through, records maintained in book-entry form by DTC and its direct and indirect participants.
Same-Day Settlement	The new Notes will trade in DTC's Same Day Funds Settlement System until maturity or redemption. Therefore, secondary market trading activity in the new Notes will be settled in immediately available funds.
Trading	We do not expect to list the new Notes for trading on any securities exchange.
Trustee, Registrar and Exchange Agent	Wachovia Bank, National Association.
Governing Law	The new Notes and the indenture relating to the new Notes will be governed by, and construed in accordance with, the laws of the State of New York.

RISK FACTORS

In addition to the other information set forth elsewhere in this prospectus, you should carefully consider the risks relating to our partnership, the exchange offers and the Notes described below before deciding whether to participate in the exchange offers.

Risks Related to Our Business

The level of our profitability is dependent upon an adequate supply of crude oil from fields located offshore and onshore California. Production from these offshore fields has experienced substantial production declines since 1995.

A significant portion of our segment profit is derived from pipeline transportation margins associated with the Santa Ynez and Point Arguello fields located offshore California. We expect that there will continue to be natural production declines from each of these fields as the underlying reservoirs are depleted. We estimate that a 5,000 barrel per day decline in volumes shipped from these fields would result in a decrease in annual pipeline segment profit of approximately $3.1 million. In addition, any production disruption from these fields due to production problems, transportation problems or other reasons would have a material adverse effect on our business.

Our trading policies cannot eliminate all price risks. In addition, any non-compliance with our trading policies could result in significant financial losses.

Generally, it is our policy that as we purchase crude oil we establish a margin by selling crude oil for physical delivery to third party users, such as independent refiners or major oil companies, or by entering into a future delivery obligation under futures contracts on the NYMEX and over-the-counter. Through these transactions, we seek to maintain a position that is substantially balanced between purchases, on the one hand, and sales or future delivery obligations, on the other hand. Our policy is generally not to acquire and hold crude oil, futures contracts or derivative products for the purpose of speculating on price changes. This policy cannot, however, eliminate all price risks. For example, any event that disrupts our anticipated physical supply of crude oil could expose us to risk of loss resulting from price changes. Moreover, we are exposed to some risks that are not hedged, including certain basis risks and price risks on certain of our inventory, such as pipeline linefill, which must be maintained in order to transport crude oil on our pipelines. In addition, we engage in a controlled trading program for up to an aggregate of 500,000 barrels of crude oil. Although this activity is monitored independently by our risk management function, it exposes us to price risks within predefined limits and authorizations.

In addition, our trading operations involve the risk of non-compliance with our trading policies. For example, we discovered in November 1999 that our trading policy was violated by one of our former employees, which resulted in aggregate losses of approximately $181.0 million. We have taken steps within our organization to enhance our processes and procedures to detect future unauthorized trading. We cannot assure you, however, that these steps will detect and prevent all violations of our trading policies and procedures, particularly if deception or other intentional misconduct is involved.

If we do not make acquisitions on economically acceptable terms our future growth may be limited.

Our ability to grow is substantially dependent on our ability to make acquisitions that result in an increase in adjusted operating surplus per unit. If we are unable to make such accretive acquisitions either because (i) we are unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them, (ii) we are unable to raise financing for such acquisitions on economically acceptable terms or (iii) we are outbid by competitors, our future growth will be limited. In particular, competition for midstream assets and businesses has intensified substantially and as a result such assets and businesses have become more costly. As a result, we may not be able to complete

the number or size of acquisitions that we have targeted internally or to continue to grow as quickly as we have historically.

Our acquisition strategy requires access to new capital. Tightened capital markets or other factors which increase our cost of capital could impair our ability to grow.

Our business strategy is substantially dependent on acquiring additional assets or operations. We continuously consider and enter into discussions regarding potential acquisitions. These transactions can be effected quickly, may occur at any time and may be significant in size relative to our existing assets and operations. Any material acquisition will require access to capital. Any limitations on our access to capital or increase in the cost of that capital could significantly impair our ability to execute our acquisition strategy. Our ability to maintain our targeted credit profile, including maintaining our credit ratings, could impact our cost of capital as well as our ability to execute our acquisition strategy.

Our acquisition strategy involves risks that may adversely affect our business.

Any acquisition involves potential risks, including:

•: performance from the acquired assets and businesses that is below the forecasts we used in evaluating the acquisition;
•: a significant increase in our indebtedness and working capital requirements;
•: the inability to timely and effectively integrate the operations of recently acquired businesses or assets;
•: the incurrence of substantial unforeseen environmental and other liabilities arising out of the acquired businesses or assets, including liabilities arising from the operation of the acquired businesses or assets prior to our acquisition;
•: customer or key employee loss from the acquired businesses; and
•: the diversion of management's attention from other business concerns.

Any of these factors could adversely affect our ability to achieve anticipated levels of cash flows from our acquisitions, realize other anticipated benefits and our ability to meet our debt service requirements.

The nature of our assets and business could expose us to significant compliance costs and liabilities.

Our operations involving the storage, treatment, processing, and transportation of liquid hydrocarbons including crude oil are subject to stringent federal, state, and local laws and regulations governing the discharge of materials into the environment, otherwise relating to protection of the environment, operational safety and related matters. Compliance with these laws and regulations increases our overall cost of business, including our capital costs to construct, maintain and upgrade equipment and facilities, or claims for damages to property or persons resulting from our operations. Failure to comply with these laws and regulations may result in the assessment of administrative, civil, and criminal penalties, the imposition of investigatory and remedial liabilities, and the issuance of injunctions that may restrict or prohibit our operations or even claims of damages to property or persons resulting from our operations. The laws and regulations applicable to our operations are subject to change, and we cannot provide any assurance that compliance with current and future laws and regulations will not have a material effect on our results of operations or earnings. A discharge of hazardous liquids into the environment could, to the extent such event is not insured, subject us to substantial expense, including both the cost to comply with applicable laws and regulations and liability to private parties for personal injury or property damage.

The profitability of our pipeline operations depends on the volume of crude oil shipped by third parties.

Third party shippers generally do not have long-term contractual commitments to ship crude oil on our pipelines. A decision by a shipper to substantially reduce or cease to ship volumes of crude oil on our pipelines could cause a significant decline in our revenues. For example, we estimate that an average 10,000 barrel per day variance in the Basin Pipeline System, equivalent to an approximate 4% volume variance on that system, would change annualized segment profit by approximately $1.0 million. In addition, we estimate that an average 10,000 barrel per day variance on the Capline Pipeline System, equivalent to an approximate 7% volume variance on that system, would change annualized segment profit by approximately $1.5 million.

The success of our business strategy to increase and optimize throughput on our pipeline and gathering assets is dependent upon our securing additional supplies of crude oil.

Our operating results are dependent upon securing additional supplies of crude oil from increased production by oil companies and aggressive lease gathering efforts. The ability of producers to increase production is dependent on the prevailing market price of oil, the exploration and production budgets of the major and independent oil companies, the depletion rate of existing reservoirs, the success of new wells drilled, environmental concerns, regulatory initiatives and other matters beyond our control. There can be no assurance that production of crude oil will rise to sufficient levels to cause an increase in the throughput on our pipeline and gathering assets.

Our operations are dependent upon demand for crude oil by refiners in the Midwest and on the Gulf Coast. Any decrease in this demand could adversely affect our business.

Demand for crude oil is dependent upon the impact of future economic conditions, fuel conservation measures, alternative fuel requirements, governmental regulation or technological advances in fuel economy and energy generation devices, all of which could reduce demand. Demand also depends on the ability and willingness of shippers having access to our transportation assets to satisfy their demand by deliveries through those assets, and any decrease in this demand could adversely affect our business.

We face intense competition in our gathering, marketing, terminalling and storage activities.

Our competitors include other crude oil pipelines, the major integrated oil companies, their marketing affiliates, and independent gatherers, brokers and marketers of widely varying sizes, financial resources and experience. Some of these competitors have capital resources many times greater than ours and control greater supplies of crude oil. We estimate that a $0.01 per barrel variance in the aggregate average segment profit would have an approximate $2.5 million annual effect on segment profit.

The profitability of our gathering and marketing activities is generally dependent on the volumes of crude oil we purchase and gather.

To maintain the volumes of crude oil we purchase, we must continue to contract for new supplies of crude oil to offset volumes lost because of natural declines in crude oil production from depleting wells or volumes lost to competitors. Replacement of lost volumes of crude oil is particularly difficult in an environment where production is low and competition to gather available production is intense. Generally, because producers experience inconveniences in switching crude oil purchasers, such as delays in receipt of proceeds while awaiting the preparation of new division orders, producers typically do not change purchasers on the basis of minor variations in price. Thus, we may experience difficulty acquiring crude oil at the wellhead in areas where there are existing relationships between producers and other gatherers and purchasers of crude oil. We estimate that a 5,000 barrel per day decrease in

barrels gathered by us would have an approximate $1.0 million per year negative impact on segment profit. This impact is based on a reasonable margin throughout various market conditions. Actual margins vary based on the location of the crude oil, the strength or weakness of the market and the grade or quality of crude oil.

We are exposed to the credit risk of our customers in the ordinary course of our gathering and marketing activities.

There can be no assurance that we have adequately assessed the credit worthiness of our existing or future counterparties or that there will not be an unanticipated deterioration in their credit worthiness, which could have an adverse impact on us.

In those cases in which we provide division order services for crude oil purchased at the wellhead, we may be responsible for distribution of proceeds to all parties. In other cases, we pay all of or a portion of the production proceeds to an operator who distributes these proceeds to the various interest owners. These arrangements expose us to operator credit risk, and there can be no assurance that we will not experience losses in dealings with other parties.

Our pipeline assets are subject to federal, state and provincial regulation.

Our domestic interstate common carrier pipelines are subject to regulation by the Federal Energy Regulatory Commission (FERC) under the Interstate Commerce Act. The Interstate Commerce Act requires that tariff rates for petroleum pipelines be just and reasonable and non-discriminatory. We are also subject to the Pipeline Safety Regulations of the U.S. Department of Transportation. Our intrastate pipeline transportation activities are subject to various state laws and regulations as well as orders of regulatory bodies.

Our Canadian pipeline assets are subject to regulation by the National Energy Board and by provincial agencies. With respect to a pipeline over which it has jurisdiction, each of these Canadian agencies has the power to determine the rates we are allowed to charge for transportation on such pipeline. The extent to which regulatory agencies can override existing transportation contracts has not been fully decided.

Our pipeline systems are dependent upon their interconnections with other crude oil pipelines to reach end markets.

Reduced throughput on these interconnecting pipelines as a result of testing, line repair, reduced operating pressures or other causes could result in reduced throughput on our pipeline systems that would adversely affect our profitability.

Fluctuations in demand can negatively affect our operating results.

Fluctuations in demand for crude oil, such as caused by refinery downtime or shutdown, can have a negative effect on our operating results. Specifically, reduced demand in an area serviced by our transmission systems will negatively affect the throughput on such systems. Although the negative impact may be mitigated or overcome by our ability to capture differentials created by demand fluctuations, this ability is dependent on location and grade of crude oil, and thus is unpredictable.

The terms of our indebtedness may limit our ability to borrow additional funds or capitalize on business opportunities.

As of September 30, 2004, our total outstanding long-term debt was approximately $837.6 million. Various limitations in our indebtedness may reduce our ability to incur additional debt, to engage in

some transactions and to capitalize on business opportunities. Any subsequent refinancing of our current indebtedness or any new indebtedness could have similar or greater restrictions.

Changes in currency exchange rates could adversely affect our operating results.

Because we conduct operations in Canada, we are exposed to currency fluctuations and exchange rate risks that may adversely affect our results of operations.

Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to entity level taxation by states. If the IRS treats us as a corporation or we become subject to entity level taxation for state tax purposes, it would substantially reduce our ability to pay our debt service obligations.

If we were classified as a corporation for federal income tax purposes, we would pay federal income tax on our income at the corporate rate. Treatment of us as a corporation would cause a material reduction in our anticipated cash flow, which would materially and adversely affect our ability to pay our debt service obligations, including the New Notes.

In addition, because of widespread state budget deficits, several states are evaluating ways to subject partnerships to entity level taxation through the imposition of state income, franchise or other forms of taxation. Imposition of such forms of taxation would reduce our cash flow.

We will be required to comply with Section 404 of the Sarbanes Oxley Act for the first time.

The Sarbanes Oxley Act of 2002 has imposed many new requirements on public companies regarding corporate governance and financial reporting. Among these is the requirement under Section 404 of the Act, beginning with our 2004 Annual Report, for management to report on our internal control over financial reporting and for our independent public accountants to attest to management's report. During 2003, we commenced actions to enhance our ability to comply with these requirements, including but not limited to the addition of staffing in our internal audit department, documentation of existing controls and implementation of new controls or modification of existing controls as deemed appropriate. We have continued to devote substantial time and resources to the documentation and testing of our controls, and to planning for and implementation of remedial efforts in those instances where remediation is indicated. At this point, we have no indication that management will be unable to favorably report on our internal controls nor that our independent auditors will be unable to attest to management's findings. Both we and our auditors, however, must complete the process (which we have never completed before), so we cannot assure you of the results. It is unclear what impact failure to comply fully with Section 404 or the discovery of a material weakness in our internal control over financial reporting would have on us, but presumably it could result in the reduced ability to obtain financing, the loss of customers, and additional expenditures to meet the requirements.

Risks Related to the Exchange Offers and the Notes

If you do not properly tender your outstanding Notes, you will continue to hold unregistered outstanding Notes and your ability to transfer outstanding Notes will be adversely affected.

We will only issue new Notes in exchange for outstanding Notes that you timely and properly tender. Therefore, you should allow sufficient time to ensure timely delivery of the outstanding Notes and you should carefully follow the instructions on how to tender your outstanding Notes. Neither we nor the exchange agent is required to tell you of any defects or irregularities with respect to your tender of outstanding Notes.

If you do not exchange your outstanding Notes for new Notes pursuant to the applicable exchange offer, the outstanding Notes you hold will continue to be subject to the existing transfer restrictions. In general, you may not offer or sell the outstanding Notes except under an exemption from, or in a transaction not subject to, the Securities Act and applicable state securities laws. We do not plan to register outstanding Notes under the Securities Act unless our registration rights agreements with the initial purchasers of the outstanding Notes require us to do so. Further, if you continue to hold any outstanding Notes after the applicable exchange offer is consummated, you may have trouble selling them because there will be fewer Notes outstanding.

We have a holding company structure in which our subsidiaries conduct our operations and own our operating assets.

We are a holding company, and our subsidiaries conduct all of our operations and own all of our operating assets. We have no significant assets other than the partnership interests and the equity in our subsidiaries. As a result, our ability to make required payments on the Notes depends on the performance of our subsidiaries and their ability to distribute funds to us. The ability of our subsidiaries to make distributions to us may be restricted by, among other things, credit facilities and applicable state partnership laws and other laws and regulations. Pursuant to the credit facilities, we may be required to establish cash reserves for the future payment of principal and interest on the amounts outstanding under the credit facilities. If we are unable to obtain the funds necessary to pay the principal amount at maturity of either series of the Notes, we may be required to adopt one or more alternatives, such as a refinancing of the Notes. We cannot assure you that we would be able to refinance either series of the Notes.

Your right to receive payments on the Notes and the guarantees is unsecured and will be effectively subordinated to our existing and future secured indebtedness as well as to any existing and future indebtedness of our subsidiaries that do not guarantee the Notes.

The Notes are effectively subordinated to claims of our secured creditors, and the guarantees are effectively subordinated to the claims of our secured creditors as well as the secured creditors of our subsidiary guarantors. Although substantially all of our subsidiaries, other than PAA Finance Corp., the co-issuer of the Notes, will initially guarantee the Notes, in the future, under certain circumstances, the guarantees are subject to release and we may have subsidiaries that are not guarantors. In that case, the Notes would be effectively subordinated to the claims of all creditors, including trade creditors and tort claimants, of our subsidiaries that are not guarantors. In the event of the insolvency, bankruptcy, liquidation, reorganization, dissolution or winding up of the business of a subsidiary that is not a guarantor, creditors of that subsidiary would generally have the right to be paid in full before any distribution is made to us or the holders of the Notes.

Our leverage may limit our ability to borrow additional funds, comply with the terms of our indebtedness or capitalize on business opportunities.

Our leverage is significant in relation to our partners' capital. Various limitations in our credit agreements and other debt instruments may reduce our ability to incur additional debt, to engage in some transactions and to capitalize on business opportunities. Any subsequent refinancing of our current indebtedness or any new indebtedness could have similar or greater restrictions.

Our leverage could have important consequences to investors in the Notes. We will require substantial cash flow to meet our principal and interest obligations with respect to the Notes and our other consolidated indebtedness. Our ability to make scheduled payments, to refinance our obligations with respect to our indebtedness or our ability to obtain additional financing in the future will depend on our financial and operating performance, which, in turn, is subject to prevailing economic conditions and to financial, business and other factors. We believe that we will have sufficient cash flow from

operations and available borrowings under our bank credit facility to service our indebtedness, although the principal amount of the Notes of each series will likely need to be refinanced at maturity in whole or in part. However, a significant downturn in the hydrocarbon industry or other development adversely affecting our cash flow could materially impair our ability to service our indebtedness. If our cash flow and capital resources are insufficient to fund our debt service obligations, we may be forced to refinance all or a portion of our debt or sell assets. We cannot assure you that we would be able to refinance our existing indebtedness or sell assets on terms that are commercially reasonable. In addition, if one or more rating agencies were to lower our debt ratings, we could be required by some of our counterparties to post additional collateral, which would reduce our available liquidity and cash flow.

Our leverage may adversely affect our ability to fund future working capital, capital expenditures and other general partnership requirements, future acquisition, construction or development activities, or to otherwise fully realize the value of our assets and opportunities because of the need to dedicate a substantial portion of our cash flow from operations to payments on our indebtedness or to comply with any restrictive terms of our indebtedness. Our leverage may also make our results of operations more susceptible to adverse economic and industry conditions by limiting our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate and may place us at a competitive disadvantage as compared to our competitors that have less debt.

A court may use fraudulent conveyance considerations to void or subordinate the subsidiary guarantees.

Various applicable fraudulent conveyance laws have been enacted for the protection of creditors. A court may use fraudulent conveyance laws to subordinate or void the subsidiary guarantees of the Notes issued by any of our subsidiary guarantors. It is also possible that under certain circumstances a court could hold that the direct obligations of a subsidiary guaranteeing the Notes could be superior to the obligations under that guarantee.

A court could void or subordinate the guarantee of the Notes by any of our subsidiaries in favor of that subsidiary's other debts or liabilities to the extent that the court determined either of the following were true at the time the subsidiary issued the guarantee:

•

that subsidiary incurred the guarantee with the intent to hinder, delay or defraud any of its present or future creditors or that subsidiary contemplated insolvency with a design to favor one or more creditors to the total or partial exclusion of others; or

•

that subsidiary did not receive fair consideration or reasonable equivalent value for issuing the guarantee and, at the time it issued the guarantee, that subsidiary:

•: was insolvent or rendered insolvent by reason of the issuance of the guarantee;
•: was engaged or about to engage in a business or transaction for which the remaining assets of that subsidiary constituted unreasonably small capital; or
•: intended to incur, or believed that it would incur, debts beyond its ability to pay such debts as they matured.

The measure of insolvency for purposes of the foregoing will vary depending upon the law of the relevant jurisdiction. Generally, however, an entity would be considered insolvent for purposes of the foregoing if the sum of its debts, including contingent liabilities, were greater than the fair saleable value of all of its assets at a fair valuation, or if the present fair saleable value of its assets were less than the amount that would be required to pay its probable liability on its existing debts, including contingent liabilities, as they become absolute and matured.

Among other things, a legal challenge of a subsidiary's guarantee of the Notes on fraudulent conveyance grounds may focus on the benefits, if any, realized by that subsidiary as a result of our

issuance of the Notes. To the extent a subsidiary's guarantee of the Notes is voided as a result of fraudulent conveyance or held unenforceable for any other reason, the Note holders would cease to have any claim in respect of that guarantee.

Your ability to transfer the Notes may be limited by the absence of a trading market.

The Notes will be new securities for which currently there is no trading market. We do not currently intend to apply for listing of the Notes on any securities exchange or stock market. The liquidity of any market for the Notes of either series will depend on the number of holders of those Notes, the interest of securities dealers in making a market in those Notes and other factors. Accordingly, we cannot assure you as to the development or liquidity of any market for the Notes of either series.

We do not have the same flexibility as other types of organizations to accumulate cash, which may limit cash available to service the Notes or to repay them at maturity.

Unlike a corporation, our partnership agreement requires us to distribute, on a quarterly basis, 100% of our available cash to our unitholders of record and to our general partner. Available cash is generally all of our cash receipts adjusted for cash distributions and net changes to reserves. Our general partner will determine the amount and timing of such distributions and has broad discretion to establish and make additions to our reserves or the reserves of our operating partnerships in amounts the general partner determines in its reasonable discretion to be necessary or appropriate:

•: to provide for the proper conduct of our business and the businesses of our operating partnerships (including reserves for future capital expenditures and for our anticipated future credit needs),
•: to provide funds for distributions to our unitholders and the general partner for any one or more of the next four calendar quarters, or
•: to comply with applicable law or any of our loan or other agreements.

Although our payment obligations to our unitholders are subordinate to our payment obligations to you, the value of our units will decrease in direct correlation with decreases in the amount we distribute per unit. Accordingly, if we experience a liquidity problem in the future, we may not be able to issue equity to recapitalize.

USE OF PROCEEDS

Each exchange offer is intended to satisfy our obligations under the related registration rights agreement. We will not receive any cash proceeds from the issuance of the new Notes in the exchange offers. In consideration for issuing the new Notes as contemplated by this prospectus, we will receive outstanding Notes in a like principal amount. The form and terms of the new Notes are identical in all respects to the form and terms of the outstanding Notes, except the new Notes do not include certain transfer restrictions, registration rights or provisions for additional interest. Outstanding Notes surrendered in exchange for the new Notes will be retired and cancelled and will not be reissued. Accordingly, the issuance of the new Notes will not result in any change in our outstanding indebtedness.

RATIO OF EARNINGS TO FIXED CHARGES

The ratio of earnings to fixed charges for each of the periods indicated are as follows:

			Year Ended December 31,
	Nine Months Ended September 30, 2004		Year Ended December 31,
	Nine Months Ended September 30, 2004		2003		2002		2001		2000⁽²⁾		1999⁽²⁾⁽³⁾
RATIO OF EARNINGS TO FIXED CHARGES⁽¹⁾	3.77	x	2.39	x	2.77	x	2.26	x	3.33	x	—

⁽¹⁾: For purposes of computing the ratio of earnings to fixed charges, "earnings" consist of pretax income from continuing operations plus fixed charges (excluding capitalized interest). "Fixed charges" represent interest incurred (whether expensed or capitalized), amortization of debt expense, and that portion of rental expense on operating leases deemed to be the equivalent of interest.
⁽²⁾: The 1999 and 2000 periods include losses of $1.5 million and $15.1 million, respectively, related to early extinguishment of debt previously classified as extraordinary items. Effective with our adoption of SFAS 145, "Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections" in January 2003, such items are included in income from continuing operations.
⁽³⁾: In 1999, available earnings failed to cover fixed charges by $103.4 million.

EXCHANGE OFFERS

We sold the outstanding Notes on August 12, 2004, pursuant to a purchase agreement dated as of August 5, 2004, by and among us, PAA Finance Corp., certain of our subsidiaries and the initial purchasers named therein. The outstanding Notes were subsequently offered by the initial purchasers to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to non-U.S. persons pursuant to Regulation S under the Securities Act.

Purpose and Effect of the Exchange Offers

In connection with the issuance of the outstanding Notes, we entered into registration rights agreements with respect to each series of Notes. Under the registration rights agreements, we agreed to use our reasonable best efforts to:

•: within 120 days of the original issuance of the Notes on August 12, 2004, file a registration statement with the SEC with respect to a registered offer to exchange the outstanding Notes for new Notes substantially identical to such Notes of such series except that the new Notes will not contain terms with respect to transfer restrictions, registration rights or provisions for additional interest;
•: cause the registration statement to be declared effective within 210 days of the original issuance of the outstanding Notes;
•: to consummate the exchange of the outstanding Notes for new Notes within 240 days of the original issuance of the outstanding Notes;
•: promptly following the effectiveness of the registration statement, offer the new Notes in exchange for surrender of the outstanding Notes; and
•: keep the exchange offers open for not less than 20 business days (or longer if required by applicable law) after the date notice of the exchange offers is mailed to the holders of the outstanding Notes.

We have fulfilled the agreements described in the first preceding bullet point and are now offering eligible holders of the outstanding Notes the opportunity to exchange their outstanding Notes for new Notes registered under the Securities Act. Holders are eligible if they are not prohibited by any law or policy of the SEC from participating in each exchange offer. The new Notes will be substantially identical to the outstanding Notes except that the new Notes will not contain terms with respect to transfer restrictions, registration rights or additional interest.

Under limited circumstances, we agreed to use our reasonable best efforts to cause the SEC to declare effective a shelf registration statement for the resale of the outstanding Notes. We also agreed to use our reasonable best efforts to keep the shelf registration statement effective for up to two years after its effective date. The circumstances include if:

•: a change in law or applicable interpretations thereof by the staff of the SEC do not permit us to effect the exchange offers;
•: for any other reason the applicable exchange offer is not consummated within 240 days from the date of the original issuance of the applicable series of outstanding Notes;
•: any initial purchaser notifies us that outstanding Notes held by it are not eligible to be exchanged for new Notes in the applicable exchange offer and are held by it following consummation of the applicable exchange offer; or
•: any holder other than an initial purchaser is not eligible to participate in the applicable exchange offer.

Subject to certain exceptions, we will pay additional cash interest on the applicable outstanding Notes if:

•: the registration statement is not filed with the SEC on or before the 120th day after the original issuance of the outstanding Notes;
•: the registration statement is not declared effective by the SEC on or before the 210th day of the original issuance of the outstanding Notes;
•: the exchange offers are not consummated on or before the 240th day of the original issuance of the outstanding Notes;
•: obligated to file a shelf registration statement, we fail to file the shelf registration statement with the SEC on or prior to the 120th day after the date on which the obligation to file a shelf registration statement arises;
•: obligated to file a shelf registration statement, the shelf registration statement is not declared effective on or prior to the 210th day after the date on which the obligation to file a shelf registration statement arises; or
•: after this registration statement or the shelf registration statement, as the case may be, is declared effective, such registration statement thereafter ceases to be effective (subject to certain exceptions) (each such event referred to in the preceding clauses being a "registration default").

Such additional interest will be payable from and including the date on which any such registration default occurs to the date on which all registration defaults have been cured.

The rate of the additional interest will be 0.25% per annum for the first 90-day period immediately following the occurrence and during the continuation of the registration default, and such rate will increase by an additional 0.25% per annum for each subsequent 90-day period until all registration defaults have been cured, up to a maximum additional interest rate of 0.50% per annum. We will pay such additional interest on regular interest payment dates. Such additional interest will be in addition to any other interest payable from time to time with respect to the outstanding Notes and the new Notes.

Upon the filing or effectiveness of this registration statement, the consummation of the exchange offers, the filing or effectiveness of a shelf registration statement, or the effectiveness of a succeeding registration statement, as the case may be, the interest rate borne by the Notes from the date of such filing, effectiveness or consummation, as the case may be, will be reduced to the original interest rate. However, if after any such reduction in interest rate, a different event specified in the clauses above occurs, the interest rate may again be increased pursuant to the preceding provisions.

To exchange your outstanding Notes for transferable new Notes in the applicable exchange offer, you will be required to represent that at the time of the consummation of the applicable exchange offer:

•: any new Notes will be acquired in the ordinary course of your business;
•: you have no arrangement or understanding with any person or entity to participate in the distribution of the new Notes;
•: you are not engaged in and do not intend to engage in the distribution of the new Notes;
•: if you are a broker-dealer that will receive new Notes for your own account in exchange for outstanding Notes, you acquired those notes as a result of market-making activities or other trading activities and you will deliver a prospectus, as required by law, in connection with any resale of such new Notes; and
•: you are not our "affiliate," as defined in Rule 405 of the Securities Act.

In addition, we may require you to provide information to be used in connection with the shelf registration statement to have your outstanding Notes included in the shelf registration statement. A holder who sells outstanding Notes under the shelf registration statement generally will be required to be named as a selling securityholder in the related prospectus and to deliver a prospectus to purchasers. Such a holder will also be subject to the civil liability provisions under the Securities Act in connection with such sales and will be bound by the provisions of the registration rights agreement that are applicable to such a holder, including indemnification obligations.

The description of the registration rights agreements contained in this section is a summary only. For more information, you should review the provisions of the registration rights agreements that we filed with the SEC as an exhibit to the registration statement of which this prospectus is a part.

Resale of New Notes

Based on no action letters of the SEC staff issued to third parties, we believe that new Notes may be offered for resale, resold and otherwise transferred by you without further compliance with the registration and prospectus delivery provisions of the Securities Act if:

•: you are not our "affiliate" within the meaning of Rule 405 under the Securities Act;
•: such new Notes are acquired in the ordinary course of your business; and
•: you do not intend to participate in a distribution of the new Notes.

The SEC, however, has not considered either exchange offer for the new Notes in the context of a no action letter, and the SEC may not make a similar determination as in the no action letters issued to these third parties.

If you tender in an exchange offer with the intention of participating in any manner in a distribution of the new Notes, you

•: cannot rely on such interpretations by the SEC staff; and
•: must comply with the registration and prospectus delivery requirements of the Securities Act in connection with a secondary resale transaction.

Unless an exemption from registration is otherwise available, any security holder intending to distribute new Notes should be covered by an effective registration statement under the Securities Act. The registration statement should contain the selling securityholder's information required by Item 507 of Regulation S-K under the Securities Act.

This prospectus may be used for an offer to resell, resale or other retransfer of new Notes only as specifically described in this prospectus. Failure to comply with the registration and prospectus delivery requirements by a holder subject to these requirements could result in that holder incurring liability for which it is not indemnified by us. If you are a broker-dealer, you may participate in an exchange offer only if you acquired the outstanding Notes as a result of market-making activities or other trading activities. Each broker-dealer that receives new Notes for its own account in exchange for outstanding Notes, where such outstanding Notes were acquired by such broker-dealer as a result of market-making activities or other trading activities, must acknowledge in the applicable letter of transmittal that it will deliver a prospectus in connection with any resale of the new Notes. Please read the section captioned "Plan of Distribution" for more details regarding the transfer of new Notes.

Terms of the Exchange Offers

Subject to the terms and conditions described in this prospectus and in the applicable letter of transmittal, we will accept for exchange any outstanding Notes properly tendered and not withdrawn prior to 5:00 p.m. New York City time on the expiration date. We will issue new Notes in principal

amount equal to the principal amount of outstanding Notes of the same series surrendered under the applicable exchange offer. Outstanding Notes may be tendered only for new Notes and only in minimum principal amounts of $2,000 and integral multiples of $2,000.

Neither exchange offer is conditioned upon any minimum aggregate principal amount of outstanding Notes being tendered for exchange. Each exchange offer will be conducted independently from the other exchange offer, and consummation of one exchange offer will not be conditioned upon consummation of the other.

As of the date of this prospectus, $175 million in aggregate principal amount of the 2009 Notes are outstanding and $175 million in aggregate principal amount of the 2016 Notes are outstanding. This prospectus is being sent to DTC, the sole registered holder of the outstanding Notes, and to all persons that we can identify as beneficial owners of the outstanding Notes. There will be no fixed record date for determining registered holders of outstanding Notes entitled to participate in either exchange offer.

We intend to conduct each exchange offer in accordance with the provisions of the applicable registration rights agreement, the applicable requirements of the Securities Act and the Securities Exchange Act of 1934 and the rules and regulations of the SEC. Outstanding Notes that the holders thereof do not tender for exchange in the applicable exchange offer will remain outstanding and continue to accrue interest. These outstanding Notes will be entitled to the rights and benefits such holders have under the respective indenture relating to the Notes and the applicable registration rights agreement.

We will be deemed to have accepted for exchange properly tendered outstanding Notes when we have given oral or written notice of the acceptance to the exchange agent and complied with the applicable provisions of the registration rights agreement. The exchange agent will act as agent for the tendering holders for the purposes of receiving the new notes from us.

If you tender outstanding Notes in an exchange offer, you will not be required to pay brokerage commissions or fees or, subject to the letter of transmittal, transfer taxes with respect to the exchange of outstanding Notes. We will pay all charges and expenses, other than certain applicable taxes described below, in connection with each exchange offer. It is important that you read the section labeled "—Fees and Expenses" for more details regarding fees and expenses incurred in an exchange offer.

We will return any outstanding Notes that we do not accept for exchange for any reason without expense to their tendering holder as promptly as practicable after the expiration or termination of the applicable exchange offer.

Expiration Date

Each exchange offer will expire at 5:00 p.m. New York City time on , 200 , unless, in our sole discretion, we extend it. We may extend one exchange offer without extending the other.

Extensions, Delays in Acceptance, Termination or Amendment

We expressly reserve the right, at any time or various times, to extend the period of time during which either exchange offer is open. During any such extensions, all outstanding Notes previously tendered will remain subject to the applicable exchange offer, and we may accept them for exchange.

In order to extend an exchange offer, we will notify the exchange agent orally or in writing of any extension. We will notify the registered holders of outstanding Notes of the extension no later than 9:00 a.m., New York City time, on the business day after the previously scheduled expiration date.

If any of the conditions described below under "—Conditions to the Exchange Offers" have not been satisfied, in relation to either exchange offer, we reserve the right, in our sole discretion

•: to delay accepting for exchange any outstanding Notes,
•: to extend the exchange offer, or
•: to terminate the exchange offer,

by giving oral or written notice of such delay, extension or termination to the exchange agent. Subject to the terms of the applicable registration rights agreement, we also reserve the right to amend the terms of either exchange offer in any manner.

Any such delay in acceptance, extension, termination or amendment will be followed as promptly as practicable by oral or written notice thereof to the registered holders of outstanding Notes. If we amend an exchange offer in a manner that we determine to constitute a material change, we will promptly disclose such amendment by means of a prospectus supplement. The supplement will be distributed to the registered holders of the outstanding Notes that are subject to the applicable exchange offer. Depending upon the significance of the amendment and the manner of disclosure to the registered holders, we will extend such exchange offer if such exchange offer would otherwise expire during such period. If an amendment constitutes a material change to an exchange offer, including the waiver of a material condition, we will extend the applicable exchange offer, if necessary, to remain open for at least five business days after the date of the amendment. In the event of any increase or decrease in the price of the outstanding Notes or in the percentage of outstanding Notes being sought by us, we will extend the applicable exchange offer to remain open for at least 10 business days after the date we provide notice of such increase or decrease to the registered holders of outstanding Notes.

Conditions to the Exchange Offers

We will not be required to accept for exchange, or exchange any new Notes for, any outstanding Notes if the applicable exchange offer, or the making of any exchange by a holder of outstanding Notes, would violate applicable law or any applicable interpretation of the staff of the SEC. Similarly, we may terminate either exchange offer as provided in this prospectus before accepting outstanding Notes for exchange in the event of such a potential violation.

In addition, we will not be obligated to accept for exchange the outstanding Notes of any holder that has not made to us the representations described under "—Purpose and Effect of the Exchange Offers," "—Procedures for Tendering" and "Plan of Distribution" and such other representations as may be reasonably necessary under applicable SEC rules, regulations or interpretations to allow us to use an appropriate form to register the new Notes under the Securities Act.

We will not accept for exchange any outstanding Notes tendered, and will not issue new Notes in exchange for any such outstanding Notes, if at such time any stop order has been threatened or is in effect with respect to (1) the registration statement of which this prospectus constitutes a part or (2) the qualification of the applicable indenture relating to the Notes under the Trust Indenture Act of 1939.

We expressly reserve the right to amend or terminate either exchange offer, and to reject for exchange any outstanding Notes not previously accepted for exchange, upon the occurrence of any of the conditions to the exchange offers specified above. We will give oral or written notice of any extension, amendment, non-acceptance or termination to the holders of the outstanding Notes as promptly as practicable.

These conditions are for our sole benefit, and we may assert them or waive them in whole or in part at any time or at various times in our sole discretion. If we fail at any time to exercise any of these

rights, this failure will not mean that we have waived our rights. Each such right will be deemed an ongoing right that we may assert at any time or at various times.

Each exchange offer is independent of the other, and the closing of one exchange offer is not conditioned upon the closing of the other.

Procedures for Tendering

In order to participate in an exchange offer, you must properly tender your outstanding Notes to the exchange agent as described below. It is your responsibility to properly tender your Notes. We have the right to waive any defects. However, we are not required to waive defects and are not required to notify you of defects in your tender.

If you have any questions or need help in exchanging your Notes, please call the exchange agent, whose address and phone number are set forth in "Prospectus Summary—The Exchange Offers—Exchange Agent."

All of the outstanding Notes were issued in book-entry form, and all of the outstanding Notes are currently represented by global certificates held for the account of DTC. We have confirmed with DTC that the outstanding Notes may be tendered using the Automated Tender Offer Program ("ATOP") instituted by DTC. The exchange agent will establish an account with DTC for purposes of the exchange offers promptly after the commencement of the exchange offers and DTC participants may electronically transmit their acceptance of the exchange offer by causing DTC to transfer their outstanding Notes to the exchange agent using the ATOP procedures. In connection with the transfer, DTC will send an "agent's message" to the exchange agent. The agent's message will state that DTC has received instructions from the participant to tender outstanding Notes and that the participant agrees to be bound by the terms of the applicable letter of transmittal.

By using the ATOP procedures to exchange outstanding Notes, you will not be required to deliver a letter of transmittal to the exchange agent. However, you will be bound by its terms just as if you had signed it.

There is no procedure for guaranteed late delivery of the outstanding Notes.

Determinations Under the Exchange Offers

We will determine in our sole discretion all questions as to the validity, form, eligibility, time of receipt, acceptance of tendered outstanding Notes and withdrawal of tendered outstanding Notes. Our determination will be final and binding. We reserve the absolute right to reject any outstanding Notes not properly tendered or any outstanding Notes our acceptance of which would, in the opinion of our counsel, be unlawful. We also reserve the right to waive any defect, irregularities or conditions of tender as to particular outstanding Notes. Our interpretation of the terms and conditions of either exchange offer, including the instructions in the applicable letter of transmittal, will be final and binding on all parties. Unless waived, all defects or irregularities in connection with tenders of outstanding Notes must be cured within such time as we shall determine. Although we intend to notify holders of defects or irregularities with respect to tenders of outstanding Notes, neither we, the exchange agent nor any other person will incur any liability for failure to give such notification. Tenders of outstanding Notes will not be deemed made until such defects or irregularities have been cured or waived. Any outstanding Notes received by the exchange agent that are not properly tendered and as to which the defects or irregularities have not been cured or waived will be returned to the tendering holder, unless otherwise provided in the applicable letter of transmittal, as soon as practicable following the applicable expiration date.

When We Will Issue New Notes

In all cases, we will issue new Notes for outstanding Notes that we have accepted for exchange under an exchange offer only after the exchange agent timely receives:

•: a book-entry confirmation of such outstanding Notes into the exchange agent's account at DTC; and
•: a properly transmitted agent's message.

Return of Outstanding Notes Not Accepted or Exchanged

If we do not accept any tendered outstanding Notes for exchange or if outstanding Notes are submitted for a greater principal amount than the holder desires to exchange, the unaccepted or non-exchanged outstanding Notes will be returned without expense to their tendering holder. Such non-exchanged outstanding Notes will be credited to an account maintained with DTC. These actions will occur as promptly as practicable after the expiration or termination of the applicable exchange offer.

Your Representations to Us

By agreeing to be bound by the applicable letter of transmittal, you will represent to us that, among other things:

•: any new Notes that you receive will be acquired in the ordinary course of your business;
•: you have no arrangement or understanding with any person or entity to participate in the distribution of the new Notes;
•: you are not engaged in and do not intend to engage in the distribution of the new Notes;
•: if you are a broker-dealer that will receive new Notes for your own account in exchange for outstanding Notes, you acquired those notes as a result of market-making activities or other trading activities and you will deliver a prospectus, as required by law, in connection with any resale of such new Notes; and
•: you are not our "affiliate," as defined in Rule 405 of the Securities Act.

Withdrawal of Tenders

Except as otherwise provided in this prospectus, you may withdraw your tender at any time prior to 5:00 p.m. New York City time on the expiration date. For a withdrawal to be effective you must comply with the appropriate procedures of DTC's ATOP system. Any notice of withdrawal must specify the name and number of the account at DTC to be credited with withdrawn outstanding Notes and otherwise comply with the procedures of DTC.

We will determine all questions as to the validity, form, eligibility and time of receipt of notice of withdrawal. Our determination shall be final and binding on all parties. We will deem any outstanding Notes so withdrawn not to have been validly tendered for exchange for purposes of the applicable exchange offer.

Any outstanding Notes that have been tendered for exchange but are not exchanged for any reason will be credited to an account maintained with DTC for the outstanding Notes. This return or crediting will take place as soon as practicable after withdrawal, rejection of tender or termination of the applicable exchange offer. You may retender properly withdrawn outstanding Notes by following the procedures described under "—Procedures for Tendering" above at any time prior to 5:00 p.m., New York City time, on the applicable expiration date.

Fees and Expenses

We will bear the expenses of soliciting tenders with respect to each exchange offer. The principal solicitation is being made by mail; however, we may make additional solicitation by telegraph, telephone or in person by our officers and regular employees and those of our affiliates.

We have not retained any dealer manager in connection with the exchange offers and will not make any payments to broker-dealers or others soliciting acceptances of the exchange offers. We will, however, pay the exchange agent reasonable and customary fees for its services and reimburse it for its related reasonable out of pocket expenses.

We will pay the cash expenses to be incurred in connection with each exchange offer. They include:

•: SEC registration fees;
•: fees and expenses of the exchange agent and trustee;
•: accounting and legal fees and printing costs; and
•: related fees and expenses.

Transfer Taxes

We will pay all transfer taxes, if any, applicable to the exchange of outstanding Notes under each exchange offer. The tendering holder, however, will be required to pay any transfer taxes, whether imposed on the registered holder or any other person, if a transfer tax is imposed for any reason other than the exchange of outstanding Notes under the applicable exchange offer.

Consequences of Failure to Exchange

If you do not exchange new Notes for your outstanding Notes under the applicable exchange offer, you will remain subject to the existing restrictions on transfer of the outstanding Notes. In general, you may not offer or sell the outstanding Notes unless they are registered under the Securities Act, or if the offer or sale is exempt from the registration under the Securities Act and applicable state securities laws. Except as required by the registration rights agreements, we do not intend to register resales of the outstanding Notes under the Securities Act.

Accounting Treatment

We will record the new Notes in our accounting records at the same carrying value as the outstanding Notes of the same series. This carrying value is the aggregate principal amount of the outstanding Notes less any bond discount, as reflected in our accounting records on the date of exchange. Accordingly, we will not recognize any gain or loss for accounting purposes in connection with either exchange offer.

Other

Participation in an exchange offer is voluntary, and you should carefully consider whether to accept. You are urged to consult your financial and tax advisors in making your own decision on what action to take.

We may in the future seek to acquire untendered outstanding Notes in open market or privately negotiated transactions, through subsequent exchange offers or otherwise. We have no present plans to acquire any outstanding Notes that are not tendered in the exchange offers or to file a registration statement to permit resales of any untendered outstanding Notes.

SELECTED HISTORICAL FINANCIAL AND OPERATING DATA

We have derived the historical financial information and operating data below from our audited consolidated financial statements as of and for the years ended December 31, 2003, 2002, 2001, 2000 and 1999 and from our unaudited financial statements as of and for the nine months ended September 30, 2004 and 2003. The selected financial data should be read in conjunction with the consolidated financial statements, including the notes thereto, and "Management's Discussion and Analysis of Financial Condition and Results of Operations" included in this prospectus.

	Nine Months Ended September 30,						Year Ended December 31,
	2004			2003			2003			2002			2001			2000			1999
	(in millions except per unit data)
Statement of operations data:
Revenues	$	14,803.4		$	9,044.8		$	12,589.8		$	8,384.2		$	6,868.2		$	6,641.2		$	10,910.4
Cost of sales and field operations (excluding LTIP charge)		14,558.3			8,879.9			12,366.6			8,209.9			6,720.9			6,506.5			10,800.1
Unauthorized trading losses and related expenses		—			—			—			—			—			7.0			166.4
Inventory valuation adjustment		—			—			—			—			5.0			—			—
LTIP charge—operations⁽¹⁾		0.6			1.4			5.7			—			—			—			—
General and administrative expenses (excluding LTIP charge)		54.6			37.4			50.0			45.7			46.6			40.8			23.2
LTIP charge—general and administrative⁽¹⁾		3.7			6.0			23.1			—			—			—			—
Depreciation and amortization		45.9			34.2			46.8			34.0			24.3			24.5			17.3
Restructuring expense		—			—			—			—			—			—			1.4

Total costs and expenses		14,663.1			8,958.9			12,492.3			8,289.6			6,796.8			6,578.8			11,008.4
Gain on sale of assets		0.6			0.6			0.6			—			1.0			48.2			16.4

Operating income		140.9			86.5			98.2			94.6			72.4			110.6			(81.6	)
Interest expense		(32.2	)		(26.5	)		(35.2	)		(29.1	)		(29.1	)		(28.7	)		(21.1	)
Interest income and other, net⁽²⁾		(0.3	)		(0.4	)		(3.6	)		(0.2	)		0.4			(4.4	)		(0.6	)

Income (loss) from continuing operations before cumulative effect of change in accounting principle⁽¹²⁾	$	108.4		$	59.6		$	59.4		$	65.3		$	43.7		$	77.5		$	(103.4	)

Basic net income (loss) per limited partner unit before cumulative effect of change in accounting principle^(2)(12)	$	1.63		$	1.06		$	1.01		$	1.34		$	1.12		$	2.13		$	(3.21	)
Diluted net income (loss) per limited partner unit before cumulative effect of change in accounting principle^(2)(12)	$	1.63		$	1.05		$	1.00		$	1.34		$	1.12		$	2.13		$	(3.21	)
Basic weighted average number of limited partner units outstanding		61.9			51.7			52.7			45.5			37.5			34.4			31.6
Diluted weighted average number of limited partner units outstanding		61.9			52.4			53.4			45.5			37.5			34.4			31.6
Balance sheet data (at end of period):
Total assets	$	3,106.0		$	1,810.1		$	2,095.6		$	1,666.6		$	1,261.2		$	885.8		$	1,223.0
Total long-term debt⁽³⁾⁽⁴⁾		837.6			453.7			519.0			509.7			354.7			320.0			424.1
Total debt⁽⁴⁾		960.5			488.9			646.2			609.0			456.2			321.3			482.8
Partners' capital		1,044.4			705.4			746.7			511.6			402.8			214.0			193.0
Other data:
Maintenance capital expenditures	$	6.1		$	5.5		$	7.6		$	6.0		$	3.4		$	1.8		$	1.7
Net cash provided by (used in) operating activities⁽⁵⁾		113.1			236.1			115.3			185.0			(16.2	)		(33.5	)		(71.2	)
Net cash provided by (used in) investing activities⁽⁵⁾		(567.3	)		(185.2	)		(272.1	)		(374.9	)		(263.2	)		211.0			(186.1	)
Net cash provided by (used in) financing activities		453.4			(51.0	)		157.2			189.5			279.5			(227.8	)		305.6
Declared distributions per limited partner unit^(6)(7)(8)		1.70			1.64			2.19			2.11			1.95			1.83			1.59

Table continued on following page.

			Nine Months Ended September 30,		Year Ended December 31,
			2004	2003	2003	2002	2001	2000	1999
Operating Data:
Volumes (thousands of barrels per day)⁽⁹⁾
Pipeline segment:
	Tariff activities
		All American	55	60	59	65	69	74	103
		Link acquisition	248	N/A	N/A	N/A	N/A	N/A	N/A
		Capline	115	N/A	N/A	N/A	N/A	N/A	N/A
		Basin	275	264	263	93	N/A	N/A	N/A
		Other domestic⁽¹⁰⁾	420	283	299	219	144	130	61
		Canada	257	191	203	187	132	N/A	N/A
	Pipeline margin activities		72	80	78	73	61	60	54

		Total	1,442	878	902	637	406	264	218

Gathering, marketing, terminalling and storage segment:
	Crude oil lease gathering		576	430	437	410	348	262	265
	Crude oil bulk purchases⁽¹¹⁾		143	84	90	68	46	28	138

		Total	719	514	527	478	394	290	403

LPG sales			39	31	38	35	19	N/A	N/A

⁽¹⁾: Compensation expense related to our Long Term Incentive Plan ("LTIP"), see "Management—1998 Long Term Incentive Plan—Restricted Unit Plan."
⁽²⁾: The 2000 and 1999 periods include $15.1 million and $1.5 million, respectively, related to losses on the early extinguishment of debt previously classified as an extraordinary item. Effective with our adoption of Statement of Financial Accounting Standards ("SFAS") 145, "Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections" in January 2003, such items are now shown as impacting income from continuing operations. As a result of this reclassification, basic and diluted net income (loss) per limited partner unit before cumulative effect of change in accounting principle for 2000 and 1999 were reduced by $0.44 and $0.05, respectively. In addition, effective with the issuance of the Emerging Issues Task Force Issue No. 03-06 ("EITF 03-06"), "Participating Securities and the Two Class Method under FASB Statement No. 128," the 2000 amount was further reduced by $0.07.
⁽³⁾: Includes current maturities of long-term debt of $8.0 million, $9.0 million, $3.0 million, and $50.7 million at September 30, 2003, and December 31, 2002, 2001 and 1999, respectively, classified as long-term because of our ability and intent to refinance these amounts under our long-term revolving credit facilities.
⁽⁴⁾: The 1999 amount includes a $114.0 million note payable to our former general partner.
⁽⁵⁾: In conjunction with the change in accounting principle we adopted as of January 1, 2004, we have classified cash flows associated with purchases and sales of linefill on assets that we own as cash flows from investing activities instead of the historical classification as cash flows from operating activities.
⁽⁶⁾: Distributions represent those declared and paid in the applicable period.
⁽⁷⁾: No distributions were declared or paid on subordinated units in the first quarter of 2000. A distribution of $0.45 per unit was declared and paid to holders of common units in that period.
⁽⁸⁾: Our general partner is entitled to receive 2% proportional distributions and also incentive distributions if the amount we distribute with respect to any quarter exceeds levels specified in our partnership agreement. See Note 7 "Partners' Capital and Distributions" in the December 31, 2003 "Notes to the Consolidated Financial Statements."
⁽⁹⁾: 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.
⁽¹⁰⁾: We have decreased the number of barrels previously disclosed in the "Other domestic" line for the 2002 period by approximately 9,000. The adjustment reflects an elimination of the duplication caused by reflecting volumes that were transported by truck in addition to being transported by pipeline. We believe this elimination more accurately reflects our business on this pipeline.
⁽¹¹⁾: We have decreased the number of barrels previously disclosed in the "Bulk purchases" line for the 2002 period by approximately 12,000. The adjustment reflects an elimination of crude oil volumes improperly classified as bulk purchases.

⁽¹²⁾: Income from continuing operations before cumulative effect of change in accounting principle pro forma for the impact of changing our method of accounting for pipeline linefill in third party assets would have been $61.4 million, $64.8 million, $38.4 million and $78.2 million for each of the four years ended December 31, 2003, respectively. In addition, basic net income per limited partner unit before cumulative effect of change in accounting principle would have been $1.05 ($1.04 diluted), $1.33 ($1.33 diluted), $0.97 ($0.97 diluted) and $2.15 ($2.15 diluted) for each of the four years ended December 31, 2003, respectively. The change had no impact on 1999.

MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Introduction

The following discussion is intended to provide investors with an understanding of our financial condition and results of our operations and should be read in conjunction with our historical consolidated financial statements and accompanying notes included elsewhere in this prospectus.

Our discussion and analysis includes the following:

•: Executive Summary
•: Acquisitions
•: Critical Accounting Policies and Estimates
•: Recent Accounting Pronouncements
•: Change in Accounting Principle
•: Results of Operations
•: Outlook
•: Liquidity and Capital Resources
•: Off-Balance Sheet Arrangements

Executive Summary

Company Overview. Plains All American Pipeline, L.P. is a Delaware limited partnership formed in September of 1998. Our operations are conducted directly and indirectly through our operating subsidiaries, Plains Marketing, L.P., Plains Pipeline, L.P. and Plains Marketing Canada, L.P. We are 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. We refer to liquified petroleum gas and other petroleum products collectively as "LPG." We own an extensive network of pipeline transportation, terminalling, storage and gathering assets in key oil producing basins and at major market hubs in the United States and Canada.

We are one of the largest midstream crude oil companies in North America. As of September 30, 2004, we owned approximately 15,000 miles of crude oil pipelines, approximately 37 million barrels of terminalling and storage capacity and a full complement of truck transportation and injection assets. Currently, we handle an average of over 2.5 million barrels per day of physical crude oil through our extensive network of assets located in major oil producing regions of the United States and Canada. Our operations consist of two operating segments: (i) pipeline operations ("Pipeline Operations") and (ii) gathering, marketing, terminalling and storage operations ("GMT&S"). Through our pipeline segment, we engage in interstate and intrastate crude oil pipeline transportation and certain related margin activities. Through our GMT&S segment, we engage in purchases and resales of crude oil and LPG at various points along the distribution chain and we operate certain terminalling and storage assets. Please read "Business—Recent Developments" for more details regarding our recent acquisitions.

Overview of Operating Results and Significant Activities

Nine Months Ended September 30, 2004. During the first nine months of 2004, we recognized net income and earnings per limited partner unit of $105.3 million and $1.58, respectively, both of which were substantial increases over the first nine months of 2003. The results for the first nine months of 2004 as compared to the first nine months of 2003 include significant contributions from acquisitions completed during the second half of 2003 and during 2004.

We had the following significant activities during the first nine months of 2004:

•: We consummated several acquisitions aggregating approximately $544 million. For a description of these acquisitions, please read "—Acquisitions—2004 Acquisitions" and "—Liquidity and Capital Resources."
•: Despite significant acquisitions, we maintained the relative strength of our overall capital structure and maintained substantial liquidity through changes in our credit facilities, a series of equity issuances and senior notes issuances. During the nine month period, we expanded our secured hedged inventory facility. In addition, we raised approximately $262 million of equity capital in two separate transactions (including our general partner's proportionate capital contributions and net of costs associated with the offerings) and we accessed the debt capital markets by issuing an aggregate $350 million of five-year and twelve-year senior notes ($175 million tranche each) at effective yields of 4.75 percent and 5.88 percent, respectively.
•: We changed our method of accounting for pipeline linefill in third party assets resulting in a cumulative effect of change in accounting principle of a charge of $3.1 million in the 2004 nine- month period. Historically, we have viewed pipeline linefill, whether in our assets or third party assets, as having long-term characteristics rather than characteristics typically associated with the short-term classification of operating inventory. Following this change in accounting principle, the linefill in third party assets that we have historically classified as a portion of "Pipeline Linefill" on the face of the balance sheet (a long-term asset) and carried at historical cost, will be included in "Inventory" (a current asset) in determining the average cost of operating inventory and applying the lower of cost or market analysis. At the end of each period, we will reclassify linefill in third party assets not expected to be liquidated within the succeeding twelve months out of "Inventory" (a current asset) and into "Inventory in Third Party Assets" (a long-term asset) at average cost, which is now reflected as a separate line item within other assets on the consolidated balance sheet.
•: Under generally accepted accounting principles, we are required to recognize an expense when vesting of LTIP units becomes probable as determined by management. Our results of operations include a charge of $4.2 million in the nine months ended September 30, 2004.
•: Recognized a foreign exchange gain of $3.4 million related to the impact of changes in the Canadian dollar to U.S. dollar exchange rate on a net U.S. dollar denominated liability in our Canadian subsidiary. This is primarily attributable to our LPG business, a substantial amount of which is transacted in U.S. Dollars.
•: Recognized a non-cash gain of approximately $1.4 million resulting from the mark-to-market of open derivative instruments pursuant to Statement of Financial Accounting Standard No. 133, as amended ("SFAS 133"), while the first nine months of 2003 includes a non-cash loss of approximately $1.7 million.
•: In July 2004, Standard & Poor's removed us from credit watch with negative implications and affirmed their BBB- stable senior unsecured rating (an investment grade rating). In September 2004, Moody's Investors Service completed their review and upgraded our senior unsecured rating to Baa3 with a stable outlook (an investment grade rating). You should note that a credit rating is not a recommendation to buy, sell or hold securities and may be subject to revision or withdrawal at any time.

Fiscal Year 2003. During 2003:

•: We enhanced and strengthened our overall capital structure and maintained substantial liquidity through changes in our credit facility, a series of equity issuances and a ten-year senior notes issuance. During the year, we successfully syndicated a new $950 million credit facility that significantly reduced our incremental borrowing costs by reducing our LIBOR based credit spread by over 100 basis points. As a result of this transaction, we recognized a non-cash charge

of approximately $3.3 million associated with the write-off of unamortized debt issue costs. In addition, we raised approximately $250 million of equity capital in three separate transactions and we accessed the debt capital markets by issuing $250 million of ten-year senior notes at an effective yield of 5.7 percent.

•: We satisfied the final requirements of the multi-year subordination tests under our partnership agreement that caused the conversion of our subordinated units into common units, thus simplifying our capital structure. The conversion also triggered the vesting in 2003 and 2004 of a portion of the outstanding phantom units under our Long-Term Incentive Plan. During 2003, we accrued a portion of the estimated expense associated with the anticipated 2004 vesting, resulting in a charge of approximately $28.8 million.
•: We completed a total of ten accretive and strategic acquisition transactions for aggregate consideration of $159.5 million. An integral component of our business strategy and growth objective is to acquire assets and operations that are strategic and complementary of our existing operations. Our historical acquisition activity is discussed under "—Acquisitions" below.
•: We realized year over year growth in segment profit from both our pipeline operations segment and our GMT&S segment, including the impact of the charges discussed above. This growth was primarily driven by (i) the impact of the current year acquisitions subsequent to their acquisition during 2003 and the inclusion of a full year contribution from those assets that we acquired during 2002 coupled with (ii) the positive results in volatile market conditions of our counter cyclically balanced activities in our GMT&S segment.
•: We raised our distribution level on our limited partner units on two separate occasions by a total of $0.10 per unit to $2.25 per unit on an annualized basis.

Acquisitions

We completed several acquisitions that have impacted the results of operations and liquidity discussed herein. The following acquisitions were accounted for, and the purchase price was allocated, in accordance with the purchase method of accounting. We adopted SFAS No. 141, "Business Combinations" in 2001 and followed the provisions of that statement for all business combinations initiated after June 30, 2001. Our ongoing acquisition activity is discussed further in "—Liquidity and Capital Resources" below.

2004 Acquisitions

In the first nine months of 2004, we completed several acquisitions for aggregate consideration of approximately $544.1 million. The aggregate consideration includes cash paid, estimated transaction costs and assumed liabilities and net working capital items. The following table summarizes our 2004 acquisitions, and a description of each of these follows the table:

Acquisition		Effective Date	Acquisition Price		Operating Segment
			(in millions)
Capline and Capwood Pipeline Systems		03/01/04	$	158.5	Pipeline
Link Energy LLC		04/01/04		332.1	Pipeline/GMT&S
Cal Ven Pipeline System		05/01/04		19.0	Pipeline
Schaefferstown Propane Storage Facility		08/25/04		32.0	GMT&S
Other⁽¹⁾				2.5

	Total 2004 Acquisitions through September 30, 2004		$	544.1

⁽¹⁾: Includes acquisitions that had an immaterial impact on results of operations for the period.

Capline and Capwood Pipeline Systems. In March 2004, we completed the acquisition of all of Shell Pipeline Company LP's interests in two entities for approximately $158.0 million in cash

(including a $15.8 million deposit paid in December 2003) and approximately $0.5 million of transaction and other costs. In December 2003, subsequent to the announcement of the acquisition and in anticipation of closing, we issued approximately 2.8 million common units for net proceeds of approximately $88.4 million, after paying approximately $4.1 million of transaction costs. The proceeds from this issuance were used to pay down our revolving credit facility. At closing, the cash portion of this acquisition was funded from cash on hand and borrowings under our revolving credit facility.

The principal assets of the entities are: (i) an approximate 22% undivided joint interest in the Capline Pipeline System, and (ii) an approximate 76% undivided joint interest in the Capwood Pipeline System. The Capline Pipeline System is a 633-mile, 40-inch mainline crude oil pipeline originating in St. James, Louisiana, and terminating in Patoka, Illinois. The Capwood Pipeline System is a 57-mile, 20-inch mainline crude oil pipeline originating in Patoka, Illinois, and terminating in Wood River, Illinois. The results of operations and assets from this acquisition (the "Capline acquisition") have been included in our consolidated financial statements and in our pipeline operations segment since March 1, 2004. These pipelines provide one of the primary transportation routes for crude oil shipped into the Midwestern U.S. and delivered to several refineries and other pipelines.

The purchase price was allocated as follows (in millions):

Crude oil pipelines and facilities		$	151.4
Crude oil storage and terminal facilities			5.7
Land			1.3
Office equipment and other			0.1

	Total	$	158.5

Link Energy LLC. On April 1, 2004, we completed the acquisition of all of the North American crude oil and pipeline operations of Link for approximately $332 million, including $268 million of cash (net of approximately $5.5 million subsequently returned to us from an indemnity escrow account) and approximately $64 million of net liabilities assumed and acquisition related costs. The Link crude oil business consists of approximately 7,000 miles of active crude oil pipeline and gathering systems, over 10 million barrels of crude oil storage capacity, a fleet of approximately 200 owned or leased trucks and approximately 2 million barrels of crude oil linefill and working inventory. The Link assets complement our assets in West Texas and along the Gulf Coast and allow us to expand our presence in the Rocky Mountain and Oklahoma/Kansas regions. The results of operations and assets from this acquisition (the "Link acquisition") have been included in our consolidated financial statements and both our pipeline operations and GMT&S operations segments since April 1, 2004.

The purchase price was allocated as follows and includes goodwill primarily related to Link's gathering and marketing business (in millions):

Fair value of assets acquired:
Property and equipment			$	262.3
Inventory				1.1
Linefill				48.4
Inventory in third party assets				15.1
Goodwill				5.0
Other long term assets				0.2

	Subtotal			332.1
Accounts receivable⁽¹⁾				405.4
Other current assets				1.8

	Subtotal			407.2
		Total assets acquired		739.3
Fair value of liabilities assumed:
Accounts payable and accrued liabilities⁽¹⁾				(455.4	)
Other current liabilities				(8.5	)
Other long-term liabilities				(7.4	)

		Total liabilities assumed		(471.3	)
Cash paid for acquisition⁽²⁾			$	268.0

⁽¹⁾: Accounts receivable and accounts payable are gross and do not reflect the adjustment of approximately $250 million to net settle, based on contractual agreements with our counterparties.
⁽²⁾: Cash paid is net of $5.5 million subsequently returned to us from an indemnity escrow account and does not include the subsequent payment of various transaction and other acquisition related costs.

We are in the process of evaluating certain estimates made in the purchase price and related allocation; thus, the purchase price and allocation are both subject to refinement.

The acquisition was initially funded with cash on hand and borrowings under our existing credit facilities as well as under a new $200 million, 364-day credit facility. In connection with the acquisition, on April 15, 2004, we completed the private placement of 3,245,700 Class C common units to a group of institutional investors. During the third quarter of 2004, we completed a public offering of common units and the sale of the outstanding Notes. A portion of the proceeds from these transactions was used to retire the $200 million, 364-day credit facility.

Cal Ven Pipeline System. On May 7, 2004 we completed the acquisition of the Cal Ven Pipeline System from Cal Ven Limited, a subsidiary of Unocal Canada Limited. The total purchase price was approximately $19 million, including transaction costs. The transaction was funded through a combination of cash on hand and borrowings under our revolving credit facilities. The Cal Ven Pipeline System includes approximately 195 miles of 8-inch and 10-inch gathering and mainline crude oil pipelines. The system is located in northern Alberta and delivers crude oil into the Rainbow Pipeline System. The Rainbow Pipeline System then transports the crude south to the Edmonton market, where it can be used in local refineries or shipped on connecting pipelines to the U.S. market. The results of operations and assets from this acquisition have been included in our consolidated financial statements and our pipeline operations segment since May 1, 2004.

Schaefferstown Propane Storage Facility. In August 2004, we completed the acquisition of the Schaefferstown Propane Storage Facility from Koch Hydrocarbon, L.P. The total purchase price was approximately $32 million, including transaction costs. In connection with the transaction, we also acquired an additional $14.2 million of inventory. The transaction was funded through a combination of cash on hand and borrowings under our revolving credit facilities. The results of operations and assets from this acquisition have been included in our consolidated financial statements and our gathering, marketing, terminalling and storage operations segment since August 25, 2004. The preliminary purchase price was primarily allocated to property and equipment.

2003 Acquisitions

During 2003, we completed ten acquisitions for aggregate consideration of approximately $159.5 million. The aggregate consideration includes cash paid, estimated transaction costs, assumed liabilities and estimated near-term capital costs. The acquisitions were initially financed with borrowings under our credit facilities, which were subsequently repaid with a portion of the proceeds from our equity issuances and the issuance of senior notes. See "—Liquidity and Capital Resources." The businesses acquired during 2003 impacted our results of operations subsequent to the effective date of each acquisition as indicated below. These acquisitions included mainline crude oil pipelines, crude oil gathering lines, terminal and storage facilities, and an underground LPG storage facility. With the exception of $0.5 million that was allocated to goodwill and other intangible assets and $4.7 million associated with crude oil linefill and working inventory, the remaining aggregate purchase price was allocated to property and equipment. The following table details our 2003 acquisitions:

Acquisition		Effective Date	Acquisition Price		Operating Segment
			(in millions)
Red River Pipeline System		02/01/03	$	19.4	Pipeline
Iatan Gathering System		03/01/03		24.3	Pipeline
Mesa Pipeline Facility⁽¹⁾		05/05/03		2.9	Pipeline
South Louisiana Assets⁽²⁾		06/01/03		13.4	Pipeline/GMT&S
Alto Storage Facility		06/01/03		8.5	GMT&S
Iraan to Midland Pipeline System		06/30/03		17.6	Pipeline
ArkLaTex Pipeline System		10/01/03		21.3	Pipeline/GMT&S
South Saskatchewan Pipeline System		11/01/03		47.7	Pipeline
Atchafalaya Pipeline System⁽³⁾		12/01/03		4.4	Pipeline

	Total 2003 Acquisitions		$	159.5

⁽¹⁾: Consists of an 8.8% undivided interest.
⁽²⁾: Includes a 33.3% interest in Atchafalaya Pipeline L.L.C. as well as other assets.
⁽³⁾: Includes two acquisitions each for 33.3% interests in Atchafalaya Pipeline L.L.C., that when combined with the acquisition referenced in (2) above, results in a total ownership of 100%.

2002 Acquisitions

Shell West Texas Assets. On August 1, 2002, we acquired interests in approximately 2,000 miles of gathering and mainline crude oil pipelines and approximately 9.0 million barrels (net to our interest) of above ground crude oil terminalling and storage assets in West Texas from Shell Pipeline Company LP and Equilon Enterprises LLC (the "Shell acquisition") for approximately $324 million. The primary assets included in the transaction are interests in the Basin Pipeline System, the Permian Basin Gathering System and the Rancho Pipeline System. The entire purchase price was allocated to property and equipment.

The acquired assets are primarily fee-based mainline crude oil pipeline transportation assets that gather crude oil in the Permian Basin and transport the crude oil to major market locations in the Mid-Continent and Gulf Coast regions. The Permian Basin has long been one of the most stable crude oil producing regions in the United States, dating back to the 1930s. The acquired assets complement our existing asset infrastructure in West Texas and represent a transportation link to Cushing, Oklahoma, where we provide storage and terminalling services. The Rancho Pipeline System was taken out of service in March 2003, pursuant to the operating agreement. See "Business—Acquisitions and Dispositions—Shutdown and Sale of Rancho Pipeline System."

Other 2002 Acquisitions. During February and March of 2002, we completed two other acquisitions for aggregate consideration totaling $15.9 million, with effective dates of February 1, 2002 and March 31, 2002, respectively. These acquisitions include an equity interest in a crude oil pipeline company and crude oil gathering and marketing assets.

2001 Acquisitions

CANPET Energy Group. In July 2001, we acquired the assets of CANPET Energy Group Inc., a Calgary based Canadian crude oil and LPG marketing company (the "CANPET acquisition"), for approximately $24.6 million plus excess inventory at the closing date of approximately $25.0 million. A portion of the purchase price, payable in common units or cash, at our option, was deferred subject to various performance standards being met. On April 30, 2004, we satisfied the deferred payment with the issuance of approximately 385,000 common units (representing approximately $13.1 million in value as of the date of issuance) and the payment of $6.5 million in cash. In addition, an incremental $3.7 million in cash was paid for the distributions that would have been paid on the common units had they been outstanding since the effective date of the acquisition.

At the time of the acquisition, CANPET's activities consisted of gathering approximately 75,000 barrels per day of crude oil and marketing an average of approximately 26,000 barrels per day of natural gas liquids or LPGs. The principal assets acquired include a crude oil handling facility, a 130,000-barrel tank facility, LPG facilities, existing business relationships and operating inventory. The purchase price, as adjusted for post-closing adjustments of $1.0 million, was allocated as follows (in millions):

Inventory		$	28.1
Goodwill			35.4
Intangible assets (contracts)			1.0
Pipeline linefill			4.3
Crude oil gathering, terminalling and other assets			5.1

	Total	$	73.9

Murphy Oil Company Ltd. Midstream Operations. In May 2001, we completed the acquisition of substantially all of the Canadian crude oil pipeline, gathering, storage and terminalling assets of Murphy Oil Company Ltd. for approximately $158.4 million in cash after post-closing adjustments, including financing and transaction costs (the "Murphy acquisition"). Initial financing for the acquisition was provided through borrowings under our credit facilities. The purchase price included $6.5 million for excess inventory in the pipeline systems. The principal assets acquired include approximately 560 miles of crude oil and condensate mainlines (including dual lines on which condensate is shipped for blending purposes and blended crude is shipped in the opposite direction) and associated gathering and lateral lines, approximately 1.1 million barrels of crude oil storage and terminalling capacity located primarily in Kerrobert, Saskatchewan, approximately 254,000 barrels of pipeline linefill and tank inventories, and 121 trailers used primarily for crude oil transportation.

Murphy agreed to continue to transport production from fields previously delivering crude oil to these pipeline systems, under a long-term contract. At the time of acquisition, these volumes averaged approximately 11,000 barrels per day. Total volumes transported on the pipeline system in 2001 were approximately 223,000 barrels per day of light, medium and heavy crudes, as well as condensate.

The purchase price, as adjusted post-closing, was allocated as follows (in millions):

Crude oil pipeline, gathering and terminal assets		$	148.0
Pipeline linefill			7.6
Networking capital items			2.0
Other property and equipment			0.5
Other assets, including debt issue costs			0.3

	Total	$	158.4

Other 2001 Acquisitions. In December 2001, we consummated the acquisition of the Wapella Pipeline System from private investors for approximately $12.0 million, including transaction costs. The entire purchase price was allocated to property and equipment. The system further expands our market in Canada.

Critical Accounting Policies and Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities, as well as the disclosure of contingent assets and liabilities, at the date of the financial statements. Such estimates and assumptions also affect the reported amounts of revenues and expenses during the reporting period. Although we believe these estimates are reasonable, actual results could differ from these estimates. The critical accounting policies that we have identified are discussed below.

Purchase and Sales Accruals

We routinely make accruals based on estimates for certain components of our revenues and cost of sales due to the timing of compiling billing information, receiving third party information and reconciling our records with those of third parties. Where applicable, these accruals are based on nominated volumes expected to be purchased, transported and subsequently sold. Uncertainties involved in these estimates include levels of production at the wellhead, access to certain qualities of crude oil, pipeline capacities and delivery times, utilization of truck fleets to transport volumes to their destinations, weather, market conditions and other forces beyond our control. These estimates are generally associated with a portion of the last month of each reporting period. We currently estimate that less than 2% of total annual revenues and cost of sales are recorded using estimates and less than 8% of total quarterly revenues and cost of sales are recorded using estimates. Accordingly, a variance from this estimate of 10% would impact the respective line items by less than 1% on both an annual and quarterly basis. Although the resolution of these uncertainties has not historically had a material impact on our reported results of operations or financial condition, because of the high volume, low margin nature of our business, we cannot provide assurance that actual amounts will not vary significantly from estimated amounts. Variances from estimates are reflected in the period actual results become known, typically in the month following the estimate.

Mark-to-Market Accrual

In situations where we are required to make mark-to-market estimates pursuant to SFAS 133, the estimates of gains or losses at a particular period end do not reflect the end results of particular transactions, and will most likely not reflect the actual gain or loss at the conclusion of a transaction. We reflect estimates for these items based on our internal records and information from third parties.

A portion of the estimates we use are based on internal models or models of third parties because they are not quoted on a national market. Additionally, values may vary among different models due to a difference in assumptions applied such as the estimate of prevailing market prices, volatility, correlations and other factors and may not be reflective of the price at which they can be settled due to the lack of a liquid market. Less than 1% of total revenues are based on estimates derived from these models. Although the resolution of these uncertainties has not historically had a material impact on our results of operations or financial condition, we cannot provide assurance that actual amounts will not vary significantly from estimated amounts.

Contingent Liability Accruals

We accrue reserves for contingent liabilities including, but not limited to, environmental remediation, insurance claims and potential legal claims. Accruals are made when our assessment indicates that it is probable that a liability has occurred and the amount of liability can be reasonably estimated. Our estimates are based on all known facts at the time and our assessment of the ultimate outcome. Among the many uncertainties that impact our estimates are the necessary regulatory approvals for, and potential modification of, our remediation plans, the limited amount of data available upon initial assessment of the impact of soil or water contamination, changes in costs associated with environmental remediation services and equipment, costs of medical care associated with worker's compensation insurance claims, and the possibility of existing legal claims giving rise to additional claims. Our estimates and contingent liability accruals are increased or decreased as additional information is obtained or resolution is achieved. A variance of 10% in our aggregate estimate would have an approximate $3.0 million impact on earnings. Although the resolution of these uncertainties has not historically had a material impact on our results of operations or financial condition, we cannot provide assurance that actual amounts will not vary significantly from estimated amounts.

Fair Value of Assets and Liabilities Acquired and Identification of Associated Goodwill and Intangible Assets

In conjunction with each acquisition, we must allocate the cost of the acquired entity to the assets and liabilities assumed based on their estimated fair values at the date of acquisition. We also estimate the amount of transaction costs that will be incurred in connection with each acquisition. As additional information becomes available, we may adjust the original estimates within a short time period subsequent to the acquisition. In addition, in conjunction with the adoption of SFAS 141, we are required to recognize intangible assets separately from goodwill. Goodwill and intangible assets with indefinite lives are not amortized but instead are periodically assessed for impairment. The impairment testing entails estimating future net cash flows relating to the asset, based on management's estimate of market conditions including pricing, demand, competition, operating costs and other factors. Intangible assets with finite lives are amortized over the estimated useful life determined by management. Determining the fair value of assets and liabilities acquired, as well as intangible assets that relate to such items as customer relationships, contracts, and industry expertise involves professional judgment and is ultimately based on acquisition models and management's assessment of the value of the assets acquired and, to the extent available, third party assessments. Uncertainties associated with these estimates include changes in production decline rates, production interruptions, fluctuations in refinery capacity or product slates, economic obsolescence factors in the area and potential future sources of cash flow. Although the resolution of these uncertainties has not historically had a material impact on our results of operations or financial condition, we cannot provide assurance that actual amounts will not vary significantly from estimated amounts.

Recent Accounting Pronouncements

In March 2004, the Emerging Issues Task Force issued Issue No. 03-06 ("EITF 03-06"), "Participating Securities and the Two-Class Method under FASB Statement No. 128." EITF 03-06 addresses a number of questions regarding the computation of earnings per share by companies that have issued securities, other than common stock, that contractually entitle the holder to participate in dividends and earnings of the company when, and if, it declares dividends on its common stock. The issue also provides further guidance in applying the two-class method of calculating earnings per share, clarifying what constitutes a participating security and how to apply the two-class method of computing earnings per share once it is determined that a security is participating, including how to allocate undistributed earnings to such a security. EITF 03-06 was effective for fiscal periods beginning after March 31, 2004. The adoption of EITF 03-06 may have an impact on earnings per limited partner unit in future periods if net income exceeds distributions or if other participating securities are issued. The effect of applying EITF 03-06 on prior periods was not material except for the year ended December 31, 2000, which has been restated as shown below.

Basic and Diluted Income Before Extraordinary Item and Cumulative Effect of Change in Accounting Principle per Limited Partner Unit:

	For the Year Ended December 31, 2000
Prior to the adoption of SFAS 145⁽¹⁾ or EITF 03-06	$	2.64
After the adoption of SFAS 145 but prior to the adoption of EITF 03-06	$	2.20
After the adoption of both SFAS 145 and EITF 03-06	$	2.13

⁽¹⁾: SFAS 145 "Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13 and Technical Corrections."

Change in Accounting Principle

During the second quarter of 2004, we changed our method of accounting for pipeline linefill in third party assets. Historically, we have viewed pipeline linefill, whether in our assets or third party assets, as having long-term characteristics rather than characteristics typically associated with the short-term classification of operating inventory. Therefore, previously we have not included linefill barrels in the same average costing calculation as our operating inventory, but instead have carried linefill at historical cost. Following this change in accounting principle, the linefill in third party assets that we have historically classified as a portion of "Pipeline Linefill" on the face of the balance sheet (a long-term asset) and carried at historical cost, is included in "Inventory" (a current asset) in determining the average cost of operating inventory and applying the lower of cost or market analysis. At the end of each period, we will reclassify the linefill in third party assets not expected to be liquidated within the succeeding twelve months out of "Inventory" (a current asset), at average cost, and into "Inventory in Third Party Assets" (a long-term asset), which is now reflected as a separate line item within other assets on the consolidated balance sheet.

This change in accounting principle is effective January 1, 2004 and is reflected in our consolidated statement of operations for the nine months ended September 30, 2004 and our consolidated balance sheet as of September 30, 2004. The cumulative effect of this change in accounting principle as of January 1, 2004, is a charge of approximately $3.1 million, representing a reduction in Inventory of approximately $1.7 million, a reduction in Pipeline Linefill of approximately $30.3 million and an increase in Inventory in Third Party Assets of $28.9 million. The pro forma impact for the first nine months of 2003 would have been an increase to net income of approximately $2.2 million ($0.04 per basic and diluted limited partner unit) resulting in pro forma net income of $61.8 million and pro forma basic net income per limited partner unit of $1.10 and pro forma diluted net income per limited partner unit of $1.09.

In conjunction with this change in accounting principle, we have classified cash flows associated with purchases and sales of linefill on assets that we own as cash flows from investing activities instead of the historical classification of cash flows from operating activities. Accordingly, our statement of cash flows for the nine months ended September 30, 2003 has been revised to reclassify the cash paid for linefill in assets owned from operating activities to investing activities. The effect of the reclassification was an increase to net cash provided by operating activities and net cash used in investing activities of $40.4 million for the nine months ended September 30, 2003. As a result of this change in classification, net cash provided by operating activities for the years ended December 31, 2003 and 2002 would increase to $115.3 million from $68.5 million and to $185.0 million from $173.9 million, respectively. Net cash used in investing activities for the years ended December 31, 2003 and 2002 would increase to $272.1 million from $225.3 million and $374.8 million from $363.8 million, respectively. In addition, net cash used in operating activities for the year ended December 31, 2001 would decrease from $30 million to $16.2 million and net cash used in investing activities would increase to $263.2 million from $249.5 million. This change in classification had no impact on the years ended 2000 and 1999.

Results of Operations

Analysis of Operating Segments

Our operations consist of two operating segments: (1) our Pipeline Operations, through which we engage in interstate and intrastate crude oil pipeline transportation and certain related merchant activities; and (2) our GMT&S Operations, through which we engage in purchases and resales of crude oil and LPG at various points along the distribution chain and the operation of certain terminalling and storage assets. We believe that the combination of our terminalling and storage activities and gathering and marketing activities provides a counter-cyclical balance that has a stabilizing effect on our results of operations and cash flow. In a contango market (oil prices for future deliveries are higher than for current deliveries), we use our tankage to improve our gathering margins by storing crude oil we have purchased at lower prices in the current month for delivery at higher prices in future months. In a backwardated market (oil prices for future deliveries are lower than for current deliveries), we use and lease less storage capacity, but increased marketing margins (premiums for prompt delivery) provide an offset to this reduced cash flow.

We evaluate segment performance based on segment profit and maintenance capital. We define segment profit as revenues less (i) purchases, (ii) field operating costs and (iii) segment general and administrative ("G&A") expenses. Each of the items above excludes depreciation and amortization. As a master limited partnership, we make quarterly distributions of our "available cash" (as defined in our partnership agreement) to our unitholders. Therefore, we look at each period's earnings before non-cash depreciation and amortization as an important measure of segment performance. The exclusion of depreciation and amortization expense could be viewed as limiting the usefulness of segment profit as a performance measure because it does not account in current periods for the implied reduction in value of our capital assets, such as crude oil pipelines and facilities, caused by aging and wear and tear. Management compensates for this limitation by recognizing that depreciation and amortization are largely offset by repair and maintenance costs, which keep the actual value of our principal fixed assets from declining. These maintenance costs are a component of field operating costs included in segment profit or in maintenance capital, depending on the nature of the cost. Maintenance capital consists of capital expenditures required either to maintain the existing operating capacity of partially or fully depreciated assets or to extend their useful lives. Capital expenditures made to expand our existing capacity, whether through construction or acquisition, are not considered maintenance capital expenditures. Repair and maintenance expenditures associated with existing assets that do not extend the useful life or expand the operating capacity are charged to expense as incurred.

Pipeline Operations

As of September 30, 2004 and December 31, 2003, we owned approximately 15,000 miles (of which approximately 13,100 miles are included in our pipeline segment) and 7,000 miles, respectively, of gathering and mainline crude oil pipelines located throughout the United States and Canada. Our activities from pipeline operations generally consist of transporting volumes of crude oil for a fee and third party leases of pipeline capacity (collectively referred to as "tariff activities"), as well as barrel exchanges and buy/sell arrangements (collectively referred to as "pipeline margin activities"). In connection with certain of our merchant activities conducted under our gathering and marketing business, we are also shippers on certain of our own pipelines. These transactions are conducted at published tariff rates and eliminated in consolidation. Tariffs and other fees on our pipeline systems vary by receipt point and delivery point. The segment profit generated by our tariff and other fee-related activities depends on the volumes transported on the pipeline and the level of the tariff and other fees charged as well as the fixed and variable field costs of operating the pipeline. Segment profit from our pipeline capacity leases, barrel exchanges and buy/sell arrangements generally reflect a negotiated amount.

Gathering, Marketing, Terminalling and Storage Operations

As of September 30, 2004, and December 31, 2003, respectively, we owned approximately 37 million barrels (of which approximately 13.6 million barrels of capacity are used in our GMT&S segment) and 23.4 million barrels of above-ground crude oil terminalling and storage facilities, including a crude oil terminalling and storage facility at Cushing, Oklahoma. Cushing, which we refer to as the Cushing Interchange, is one of the largest crude oil market hubs in the United States and the designated delivery point for New York Mercantile Exchange, or NYMEX, crude oil futures contracts. Terminals are facilities where crude oil is transferred to or from storage or a transportation system, such as a pipeline, to another transportation system, such as trucks or another pipeline. The operation of these facilities is called "terminalling." Approximately 13.6 million barrels of our 37 million barrels of tankage is used primarily in our GMT&S Operations segment and the balance is used in our Pipeline Operations segment. On a stand-alone basis, segment profit from terminalling and storage activities is dependent on the throughput of volumes, the volume of crude oil stored and the level of fees generated from our terminalling and storage services. Our terminalling and storage activities are integrated with our gathering and marketing activities and the level of tankage that we allocate for our arbitrage activities (and therefore not available for lease to third parties) varies throughout crude oil price cycles. This integration enables us to use our storage tanks in an effort to counter-cyclically balance and hedge our gathering and marketing activities. In a contango market (when oil prices for future deliveries are higher than for current deliveries), we use our tankage to improve our gathering margins by storing crude oil we have purchased at lower prices in the current month for delivery at higher prices in future months. In a backwardated market (when oil prices for future deliveries are lower than for current deliveries), we use and lease less storage capacity, but increased marketing margins (premiums for prompt delivery) provide an offset to this reduced cash flow. We believe that this combination of our terminalling and storage activities and gathering and marketing activities provides a counter-cyclical balance that has a stabilizing effect on our results of operations and cash flows.

Our revenues from gathering and marketing activities reflect the sale of gathered and bulk-purchased crude oil and LPG volumes, plus the sale of additional barrels exchanged through buy/sell arrangements entered into to supplement the margins of the gathered and bulk-purchased volumes. Because the commodities that we buy and sell are generally indexed to the same pricing indices for both the purchase and the sale, revenues and costs related to purchases will increase and decrease with changes in market prices. However, the margins related to those purchases and sales will not necessarily have corresponding increases and decreases. For example, our revenues increased

approximately 66% in the first nine months of 2004 compared to the first nine months of 2003, while our segment profit increased almost 30% in the same period.

Revenues from our GMT&S operations were approximately $14.2 billion and $8.6 billion for the nine months ended September 30, 2004 and 2003, respectively. Revenues and costs related to purchases for the 2004 period were impacted by higher average prices and higher volumes as compared to the 2003 period. Approximately 52% of the increase in revenues resulted from higher average prices in the 2004 period and the remainder was attributable to increased sales volumes. The average NYMEX price for crude oil was $39.09 per barrel and $31.03 per barrel for the nine months ended September 30, 2004 and 2003, respectively.

Generally, we expect our segment profit to increase or decrease directionally with increases or decreases in lease gathered volumes and LPG sales volumes. Although we believe that the combination of our lease gathering business and our storage assets provides a counter-cyclical balance that provides stability in our margins, these margins are not fixed and may vary from period to period. In order to evaluate the performance of this segment, management focuses on the following metrics: (i) segment profit (ii) crude oil lease gathered volumes and LPG sales volumes and (iii) segment profit per barrel calculated on these volumes.

Nine Months Ended September 30, 2004 and 2003

For the nine months ended September 30, 2004, we reported consolidated net income of $105.3 million on total revenues of $14.8 billion compared to net income for the same period in 2003 of $59.6 million on total revenues of $9.0 billion. The following table reflects our results of operations

and maintenance capital for each segment (note that each of the items in the following table excludes depreciation and amortization):

	Pipeline			GMT&S
	(in millions)
Nine Months Ended September 30, 2004⁽¹⁾
Revenues	$	639.5		$	14,247.6
Purchases		(408.4	)		(14,075.8	)
Field operating costs (excluding LTIP charge)		(84.8	)		(73.3	)
LTIP charge—operations		(0.1	)		(0.4	)
Segment G&A expenses (excluding LTIP charge)⁽²⁾		(27.3	)		(27.2	)
LTIP charge—general and administrative		(1.7	)		(2.0	)

Segment profit	$	117.2		$	68.9

Noncash SFAS 133 impact⁽³⁾	$	—		$	1.4

Maintenance capital	$	4.1		$	2.0

Nine Months Ended September 30, 2003⁽¹⁾
Revenues	$	489.1		$	8,594.8
Purchases		(362.9	)		(8,457.2	)
Field operating costs (excluding LTIP charge)		(42.3	)		(56.6	)
LTIP charge—operations		(0.4	)		(1.0	)
Segment G&A expenses (excluding LTIP charge)⁽²⁾		(13.7	)		(23.7	)

LTIP charge—general and administrative		(2.6	)		(3.4	)

Segment profit	$	67.2		$	52.9

Noncash SFAS 133 impact⁽³⁾	$	—		$	(1.7	)

Maintenance capital	$	4.8		$	0.7

⁽¹⁾: Revenues and purchases include intersegment amounts.
⁽²⁾: Segment G&A expenses 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 following table sets forth our operating results from our Pipeline Operations segment for the periods indicated:

			Nine Months Ended September 30,
			2004			2003
Operating Results⁽¹⁾ (in millions)
	Revenues
		Tariff activities	$	215.3		$	112.4
		Pipeline margin activities		424.2			376.7

	Total pipeline operations revenues			639.5			489.1
	Costs and Expenses
		Pipeline margin activities purchases		(408.4	)		(362.9	)
		Field operating costs (excluding LTIP charge)		(84.8	)		(42.3	)
		LTIP charge—operations		(0.1	)		(0.4	)
		Segment G&A expenses (excluding LTIP charge)⁽²⁾		(27.3	)		(13.7	)
		LTIP charge—general and administrative		(1.7	)		(2.6	)

	Segment profit		$	117.2		$	67.2

	Maintenance capital		$	4.1		$	4.8

Average Daily Volumes⁽³⁾ (thousands of barrels per day)
	Tariff activities
		All American		55			60
		Basin		275			264
		Link acquisition		248			N/A
		Capline		115			N/A
		Other domestic		420			283
		Canada		257			191

	Total tariff activities			1,370			798
	Pipeline margin activities			72			80

		Total		1,442			878

⁽¹⁾: Revenues and purchases include intersegment amounts.
⁽²⁾: Segment G&A expenses 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⁾: 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.

Total revenues from our pipeline operations were approximately $639.5 million and $489.1 million for the nine months ended September 30, 2004 and 2003, respectively. An increase in revenues from tariff activities accounted for $102.9 million of the increase (see discussion below). Additionally, revenues from our margin activities increased by approximately $47.5 million in the 2004 period. This increase was related to higher average prices for crude oil sold and transported on our SJV gathering system in the 2004 period as compared to the 2003 period, partially offset by lower buy/sell volumes. As mentioned above, because the barrels that we buy and sell are generally indexed to the same pricing indices, revenues and purchases will increase and decrease with changes in market prices without significant changes to our margins related to those purchases and sales. Volumes transported on the SJV system have decreased from the 2003 period. This is primarily related to (i) the first quarter of

2003 including additional shipments that typically move on other pipelines and (ii) the use by refineries of foreign crude oil instead of crude oil transported on the SJV system.

Segment profit, our primary measure of segment performance, increased approximately 74% to $117.2 million for the nine months ended September 30, 2004 as compared to the 2003 period. The primary drivers impacting the 2004 period as compared to the 2003 period are:

•: Increased volumes and related tariff revenues—The increase in volumes and related tariff revenues is primarily related to the Link acquisition and other acquisitions completed during 2004 and late 2003.
•: Higher realized prices on our loss allowance oil—Higher crude oil prices during 2004 as compared to 2003 have resulted in increased revenues related to loss allowance oil.
•: Increased field operating costs—Our continued growth, primarily from the Link acquisition and other acquisitions completed during 2004 and late 2003 is the principal driver of the increase in field operating costs of $42.2 million to $84.9 million for the third quarter of 2004. The increased costs are primarily in payroll and benefits and utilities. In addition, costs related to our pipeline integrity management program have increased in 2004.
•: Increased segment G&A expenses—Segment G&A expenses have increased approximately $12.7 million to $29.0 million in the third quarter of 2004 from the third quarter of 2003. The increase in the current quarter is primarily related to the Link acquisition coupled with the percentage of indirect costs allocated to the pipeline operations segment continuing to increase in the 2004 period as our pipeline operations have grown. G&A costs have also increased because of increased headcount from our continued growth and higher costs related to Sarbanes-Oxley requirements. These items were partially offset by the inclusion of an LTIP charge of approximately $2.6 million in the 2003 period.

As discussed above, the increase in pipeline operations segment profit is largely related to our acquisition activities. We have completed a number of acquisitions during 2004 and 2003 that have impacted our results of operations. The following presentation helps summarize the impact of recent acquisitions on volumes and revenues related to our tariff activities.

		Nine Months Ended September 30,
		2004			2003
		Volumes	Revenues		Volumes	Revenues
		(volumes in thousands of barrels per day and revenues in millions)
Tariff activities⁽¹⁾⁽²⁾
	2004 acquisitions	471	$	77.7	—	$	—
	2003 acquisitions	168		27.7	58		8.0
	All other pipeline systems	731		109.9	740		104.4

	Total tariff activities	1,370	$	215.3	798	$	112.4

⁽¹⁾: Revenues include intersegment amounts.
⁽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.

Average daily volumes from our tariff activities increased 72% to approximately 1.4 million barrels per day and revenues from our tariff activities increased 92% to $215.3 million. The increase in the third quarter of 2004 is predominately related to (i) the inclusion of an average of 248,000 barrels per day and $52.7 million of revenues from the pipelines acquired in the Link acquisition and (ii) 223,000 barrels per day and $25.0 million of revenues from other businesses acquired in 2004.

Volumes from pipeline systems acquired in 2003 have increased to an average of 168,000 barrels per day from an average of 58,000 barrels per day, while related revenues increased to $27.7 million from $8.0 million. The increase is primarily the result of the inclusion of several pipeline systems in the 2004 period that were acquired during or after 2003 (See "Acquisitions"), coupled with higher realized prices on our loss allowance oil. Volumes and revenues from all other pipeline systems were relatively flat between years.

The following table sets forth our operating results from our GMT&S Operations segment for the comparative periods indicated:

		Nine Months Ended September 30,
		2004			2003
Operating Results⁽¹⁾ (in millions)
	Revenues	$	14,247.6		$	8,594.8
	Purchases and related costs		(14,075.8	)		(8,457.2	)
	Field operating costs (excluding LTIP charge)		(73.3	)		(56.6	)
	LTIP charge—operations		(0.4	)		(1.0	)
	Segment G&A expenses (excluding LTIP charge)⁽²⁾		(27.2	)		(23.7	)
	LTIP charge—general and administrative		(2.0	)		(3.4	)

	Segment profit	$	68.9		$	52.9

	Noncash SFAS 133 impact⁽³⁾	$	1.4		$	(1.7	)

	Maintenance capital	$	2.0		$	0.7

Average Daily Volumes⁽⁴⁾ (thousands of barrels per day)
Crude oil lease gathering			576			430
Crude oil bulk purchases			143			84

	Total		719			514

LPG sales⁽⁵⁾			39			31

⁽¹⁾: Revenues and purchases and related costs include intersegment amounts.
⁽²⁾: Segment G&A expenses 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.
⁽⁴⁾: 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.
⁽⁵⁾: Prior period volumes have been adjusted for consistency of comparison between years. Sales reflect only third party volumes.

Segment profit increased approximately 30% to $68.9 million for the first nine months of 2004 as compared to the first nine months of 2003. The primary drivers for the increase in the current year were:

•: Increased crude oil lease gathered volumes and LPG sales volumes—The crude oil volumes gathered from producers, using our assets or third-party assets, has increased by approximately 34% to 576,000 barrels per day for the first nine months of 2004. The increase is primarily related to the Link acquisition, which has offset natural production declines. In addition, we marketed 39,000 barrels per day of LPG during the current period compared to 31,000 barrels per day in 2003.

•: Favorable market conditions—During the first nine months of 2004, market conditions were favorable as the market was relatively volatile, with periods of strong backwardation as well as a short-lived contango structure. The NYMEX benchmark price of crude ranged from $32.20 to $50.20 during the period. This volatile market allowed us to optimize and enhance the margins of both our gathering and marketing assets and our terminalling and storage assets at different times during the period. The market conditions in the first nine months of 2003 were also favorable as there was relatively high volatility and strong backwardation throughout the period. During the first nine months of 2003, the NYMEX benchmark price of crude ranged from $25.04 to $39.99.
•: Change in impact from the SFAS 133 mark-to-market adjustment—The first nine months of 2004 included a non-cash gain of approximately $1.4 million resulting from the mark-to-market of open derivative instruments pursuant to SFAS 133, while the first nine months of 2003 included a non-cash loss of approximately $1.7 million.
•: Impact of change in Canadian dollar to U.S. dollar exchange rate—The 2004 period includes a foreign exchange gain of $3.4 million. The gain is related to the impact of changes in the Canadian dollar to U.S. dollar exchange rate on a net U.S. dollar denominated liability in our Canadian subsidiary. This is primarily attributable to our LPG business, a substantial amount of which is transacted in US Dollars.
•: Increased field operating costs—Field operating costs increased to approximately $73.7 million in the current period from $57.6 million in the 2003 period primarily related to the Link acquisition. This increase was partially offset by the $1 million charge related to our LTIP in the 2003 period compared to $0.4 million in the 2004 period.
•: Increased segment G&A expenses—G&A expense was approximately $2.1 million higher in the 2004 period than in the 2003 period. The increase is primarily related to increased headcount resulting from continued growth and higher costs related to Sarbanes-Oxley requirements partially offset by a decrease in the percentage of indirect costs allocated to the GMT&S operations segment as the growth in our pipeline operations segment has outpaced growth in our GMT&S operations segment. The increase is partially offset by the $3.4 million charge related to our LTIP in the 2003 period compared to $2.0 million in the 2004 period.

The impact of the items discussed above resulted in segment profit per barrel (calculated based on our lease gathered crude oil and LPG barrels) of $0.41 per barrel for the nine months ended September 30, 2004, compared to $0.42 for the nine months ended September 30, 2003.

Other Expenses

Depreciation and Amortization. Depreciation and amortization expense was $45.9 million for the nine months ended September 30, 2004, compared to $34.2 million for the nine months ended September 30, 2003. The increase relates primarily to the assets from our 2004 acquisitions and our various 2003 acquisitions being included for the full nine months in 2004 versus only a part or none of the nine months in 2003. Additionally, several capital projects were completed during late 2003 that were not included in the first nine months of 2003 depreciation expense. Amortization of debt issue costs was $1.9 million and $3.0 million in the first nine months of 2004 and 2003, respectively.

Interest Expense. During the first nine months of 2004, our average debt balance was approximately $719 million. This balance consisted of fixed rate senior notes averaging $514 million and borrowings under our revolving credit facilities averaging $205 million. During the comparable 2003 period, our average debt balance was approximately $525 million and consisted of fixed rate senior notes with a face amount of $200 million and borrowings under our revolving credit facilities of $325 million. The higher average debt balance in the 2004 period was primarily related to the portion

of our acquisitions that were not refinanced with equity. Our financial growth strategy is to fund our acquisitions using a balance of debt and equity.

The changes to our debt structure and our interest rate hedging instruments mentioned above resulted in an increase in the average amount of fixed rate debt outstanding in the first nine months of 2004 to approximately 72% as compared to approximately 38% in the first nine months of 2003. In addition, during these two periods the average three-month LIBOR rate rose to 1.4% in 2004 from 1.1% in 2003.

The net impact of the items discussed above was an increase in interest expense for the nine months ended 2004 of approximately $5.7 million to a total of $32.2 million. The higher average debt balance in the 2004 period resulted in additional interest expense of approximately $8.3 million, while at the same time our commitment and other fees decreased by approximately $1.6 million. Our weighted average interest rate, excluding commitment and other fees, was approximately 5.7% for the nine months ended 2004 compared to 6.0% for the nine months ended 2003. The lower weighted average rate decreased interest expense by approximately $1.0 million during the nine months ended 2004 compared to the nine months ended 2003.

Other. During the third quarter of 2004, we completed the issuance of 4,968,000 common units and the outstanding Notes. We used the proceeds from these issuances to, among other things, repay amounts outstanding under our revolving credit facilities, including all amounts outstanding under the $200 million, 364-day facility we used to fund the Link acquisition. The repayment and termination of this facility resulted in a non-cash charge of approximately $0.7 million associated with the write-off of unamortized debt issue costs.

Three Years Ended December 31, 2003

The following table reflects our results of operations and maintenance capital for each segment (note that each of the items in the following table excludes depreciation and amortization).

	Pipeline			GMT&S
	(in millions)
Year Ended December 31, 2003⁽¹⁾
Revenues	$	658.6		$	11,985.6
Purchases		(487.1	)		(11,799.8	)
Field operating costs (excluding LTIP charge)		(60.9	)		(73.3	)
LTIP charge—operations		(1.4	)		(4.3	)
Segment G&A expenses (excluding LTIP charge)⁽²⁾		(18.3	)		(31.6	)
LTIP charge—general and administrative		(9.6	)		(13.5	)

Segment profit	$	81.3		$	63.1

Noncash SFAS 133 impact⁽³⁾	$	—		$	0.4

Maintenance capital	$	6.4		$	1.2

Year Ended December 31, 2002⁽¹⁾
Revenues	$	486.2		$	7,921.8
Purchases		(362.2	)		(7,765.1	)
Field operating costs		(40.1	)		(66.3	)
Segment G&A expenses⁽²⁾		(13.2	)		(31.5	)

Segment profit	$	70.7		$	58.9

Noncash SFAS 133 impact⁽³⁾	$	—		$	0.3

Maintenance capital	$	3.4		$	2.6

Year Ended December 31, 2001⁽¹⁾
Revenues	$	357.4		$	6,528.3
Purchases		(266.7	)		(6,383.6	)
Field operating costs		(19.4	)		(73.7	)
Segment G&A expenses⁽²⁾		(12.4	)		(28.5	)

Segment profit	$	58.9		$	42.5

Noncash SFAS 133 impact⁽³⁾	$	—		$	0.2

Maintenance capital	$	0.5		$	2.9

⁽¹⁾: Revenues and purchases include intersegment amounts.
⁽²⁾: Segment G&A expenses 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 following table sets forth our operating results from our Pipeline Operations segment for the periods indicated:

			Year Ended December 31,
			2003			2002			2001
Operating Results⁽¹⁾ (in millions)
Revenues
	Tariff activities		$	153.3		$	103.7		$	69.4
	Pipeline margin activities			505.3			382.5			288.0

Total pipeline operations revenues				658.6			486.2			357.4
Costs and Expenses
	Pipeline margin activities purchases			(487.1	)		(362.2	)		(266.7	)
	Field operating costs (excluding LTIP charge)			(60.9	)		(40.1	)		(19.4	)
	LTIP charge—operations			(1.4	)		—			—
	Segment G&A expenses (excluding LTIP charge)⁽²⁾			(18.3	)		(13.2	)		(12.4	)
	LTIP charge—general and administrative			(9.6	)		—			—

Segment profit			$	81.3		$	70.7		$	58.9

Maintenance capital			$	6.4		$	3.4		$	0.5

Average Daily Volumes⁽³⁾⁽⁴⁾ (thousands of barrels per day)
Tariff activities
	All American			59			65			69
	Basin			263			93			N/A
	Other domestic			299			219			144
	Canada			203			187			132

Total tariff activities				824			564			345
Pipeline margin activities				78			73			61

		Total		902			637			406

⁽¹⁾: Revenues and purchases include intersegment amounts.
⁽²⁾: Segment G&A expenses 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⁾: 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.
⁽⁴⁾: We have decreased the number of barrels previously disclosed in the "Other domestic" line for the 2002 period by approximately 9,000. The adjustment reflects an elimination of the duplication caused by reflecting volumes that were transported by truck in addition to being transported by pipeline. We believe this elimination more accurately reflects our business on this pipeline.

Total average daily volumes transported were approximately 902,000 barrels per day for the year ended December 31, 2003, compared to 637,000 barrels per day and 406,000 barrels per day for the years ended December 31, 2002 and 2001, respectively. As discussed above, we have completed a number of acquisitions during 2003 and 2002 that have impacted the results of operations.

The following table reflects our total average daily volumes from our tariff activities by year of acquisition for comparison purposes:

			Year Ended December 31,
			2003		2002		2001
			(thousands of barrels per day)
Tariff activities⁽¹⁾
	2003 acquisitions			82	$	—	$	—
	2002 acquisitions			344		171		—
	2001 acquisitions			200		193		134
	All other pipeline systems			198		200		211

		Total tariff activities	$	824	$	564	$	345

⁽¹⁾: 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.

The increase in average daily volumes from our tariff activities to 824,000 barrels per day in 2003 from 564,000 barrels per day and 345,000 barrels per day in 2002 and 2001, respectively, resulted primarily from our acquisition activities discussed above. The following discussion explains year-to-year variances based on the comparison of volumes in the table above.

2003 Acquisitions—Approximately 82,000 barrels per day of the increase in 2003 volumes over 2002 volumes is related to systems acquired during 2003.

2002 Acquisitions—An additional 173,000 barrels per day of the increase in 2003 resulted from the inclusion of assets acquired in 2002 for the entire year in 2003 as compared to only a portion of 2002. The assets acquired in the Shell acquisition accounted for 171,000 barrels per day of this increase as increased barrels per day on the Basin Pipeline System and the Permian Basin Gathering System coupled with the impact of including a full year results in 2003 as compared to only five months in 2002 more than offset the decrease in barrels per day resulting from the shut-down of the Rancho Pipeline System. See "Business—Acquisitions and Dispositions—Shutdown and Sale of Rancho Pipeline System."

2001 Acquisitions—In addition, volumes on pipeline systems acquired in 2001 increased by approximately 7,000 barrels per day in the 2003 period as Canadian volumes benefited from the completion of capital expansion projects that allowed for additional volumes on certain pipelines. Barrels per day on these systems increased in the 2002 period as compared to the 2001 period primarily due to the inclusion of the Murphy acquisition for a full year in 2002 compared to only a portion of the year in 2001.

All other pipeline systems—Volumes on all other pipeline systems decreased approximately 2,000 barrels per day primarily because of a 6,000 barrel per day decrease in our All American tariff volumes and various other decreases totaling 4,000 barrels per day on several of our pipeline systems. The decrease in All American tariff volumes is attributable to a decline in California outer continental shelf ("OCS") production. Partially offsetting these decreases was an 8,000 barrel per day increase in our West Texas Gathering System volumes. Our West Texas Gathering System has benefited from the shutdown of the Rancho pipeline and also from temporary refinery problems that have diverted crude oil barrels from other systems. Volumes on all other pipeline systems decreased by approximately 11,000 barrels per day in 2002 as compared to 2001, primarily because of an approximate 4,000 barrel per day decrease in our All American tariff volumes and a 4,000 barrel per day decrease in our West Texas Gathering System volumes.

Revenues. Total revenues from our pipeline operations were approximately $658.6 million for the year ended December 31, 2003, compared to $486.2 million and $357.4 million for the years ended December 31, 2002 and 2001, respectively. The increase in revenues was primarily related to our pipeline margin activities, which increased by approximately $122.8 million in 2003. This increase was related to higher average crude oil prices coupled with increased volumes on our buy/sell arrangements on our San Joaquin Valley gathering system in 2003. Because the barrels that we buy and sell are generally indexed to the same pricing indices, revenues and purchases will increase and decrease with changes in market prices without significant changes to our margins related to those purchases and sales. The increase in 2002 over 2001 also was primarily related to our pipeline margin activities on our San Joaquin Valley gathering system. Increased volumes and higher average prices on our buy/sell arrangements were the primary drivers of the increase.

Revenues from our tariff activities increased approximately 48% or $49.6 million in 2003 as compared to 2002. The following table reflects revenues from our tariff activities by year of acquisition for comparison purposes:

			Year Ended December 31,
			2003		2002		2001
			(in millions)
Tariff activities⁽¹⁾
	2003 acquisitions		$	14.8	$	—	$	—
	2002 acquisitions			54.2		23.1		—
	2001 acquisitions			28.0		21.6		9.9
	All other pipeline systems			56.3		59.0		59.5

		Total tariff activities	$	153.3	$	103.7	$	69.4

⁽¹⁾: Revenues include intersegment amounts.

The increase in revenues from our tariff activities to $153.3 million in 2003 from $103.7 million and $69.4 million in 2002 and 2001, respectively, resulted predominantly from our acquisition activities discussed above. The following discussion explains year-to-year variances based on the comparison of revenues in the table above.

2003 Acquisitions—Approximately $14.8 million of the increase in 2003 revenues over 2002 revenues is related to systems acquired during 2003.

2002 Acquisitions—An additional $31.1 million of the increase in 2003 revenues from our tariff activities resulted from the inclusion of assets acquired in 2002 for the entire year in 2003 as compared to only a portion of 2002. This increase was entirely related to the assets acquired in the Shell acquisition as increased revenues on the Basin Pipeline System and the Permian Basin Gathering System coupled with the impact of including a full year results in 2003 as compared to only five months in 2002 more than offset the decrease in revenues resulting from the shut-down of the Rancho Pipeline System. See "Business—Acquisitions and Dispositions—Shutdown and Sale of Rancho Pipeline System."

2001 Acquisitions—In addition, revenues from 2001 acquisitions increased approximately $6.4 million in 2003 as compared to 2002. This increase predominately resulted from increased Canadian revenues of $6.5 million in the 2003 period primarily due to expanded capacity, higher tariffs and a $3.4 million favorable exchange rate impact. The favorable exchange rate impact has resulted from a decrease in the Canadian dollar to U.S. dollar exchange rate to an average rate of 1.40 to 1 for the year ended December 31, 2003, from an average rate of 1.57 to 1 for the year ended December 31, 2002. Revenues from these systems increased to $21.6 million in 2002 from $9.9 million in 2001

primarily because of the inclusion of the Murphy acquisition for a full year in 2002 and increases in the tariff of certain pipeline systems acquired in the Murphy acquisition.

All other pipeline systems—Revenues from all other pipeline systems were relatively flat for all of the comparable periods as the decrease in volumes attributable to OCS production on our All American system (on which we receive the highest per barrel tariffs among our pipeline operations) was offset in each period by other increases, including increases in the tariffs for OCS volumes transported.

Field Operating Costs. Field operating costs increased to $62.3 million in 2003 from $40.1 million and $19.4 million in 2002 and 2001, respectively. The 2003 increase in costs includes $1.4 million related to the accrual made for the probable vesting of unit grants under our LTIP and approximately $1.0 million related to a pipeline spill in Mississippi. The remaining increase is predominately related to our continued growth, primarily from acquisitions, coupled with higher utility costs.

The increase in field operating costs in 2002 as compared to 2001 was primarily related to the acquisition of businesses in 2002 and late 2001 and the inclusion of the results of the Murphy acquisition for all of 2002 compared to only a portion of 2001. Our field operating costs for the 2002 period also includes a $1.2 million noncash charge associated with the establishment of a liability for potential cleanup of environmental conditions associated with our 1999 acquisitions, based on additional information. In many cases, the actual cash expenditure may not occur for ten years or more.

Segment G&A Expenses. Segment G&A expenses were approximately $27.9 million in 2003, compared to approximately $13.2 million and $12.4 million in 2002 and 2001, respectively. The increase in 2003 is primarily a result of a $9.6 million accrual related to the probable vesting of unit grants under our LTIP. Additionally, the percentage of indirect costs allocated to the pipeline operations segment has increased in 2003 as our pipeline operations have grown. The increase in segment G&A expenses in 2002 as compared to 2001 was partially due to increased costs from the assets acquired in the Murphy acquisition related to the inclusion of these assets for all of 2002 compared to only a portion of 2001.

Segment Profit. Our pipeline operations segment profit increased 15% to approximately $81.3 million for the year ended December 31, 2003. Pipeline segment profit was approximately $58.9 million in 2001. The primary reasons for the increase in segment profit are discussed above. In addition, segment profit includes a $2.0 million favorable impact resulting from the decrease in the average Canadian dollar to U.S. dollar exchange rate for the 2003 period as compared to the 2002 period.

Maintenance Capital. For the periods ended December 31, 2003, 2002 and 2001, maintenance capital expenditures were approximately $6.4 million, $3.4 million and $0.5 million, respectively for our pipeline operations segment. The increases between the years are related to our continued growth, primarily through acquisitions.

The following table sets forth our operating results from our GMT&S segment for the periods indicated:

		December 31,
		2003			2002			2001
Operating Results⁽¹⁾ (in millions)
Revenues		$	11,985.6		$	7,921.8		$	6,528.3
Purchases and related costs			(11,799.8	)		(7,765.1	)		(6,383.6	)
Field operating costs (excluding LTIP charge)			(73.3	)		(66.3	)		(73.7	)
LTIP charge—operations			(4.3	)		—			—
Segment G&A expenses (excluding LTIP charge)⁽²⁾			(31.6	)		(31.5	)		(28.5	)
LTIP charge—general and administrative			(13.5	)		—			—

Segment profit		$	63.1		$	58.9		$	42.5

Noncash SFAS 133 impact⁽³⁾		$	0.4		$	0.3		$	0.2

Maintenance capital		$	1.2		$	2.6		$	2.9

Average Daily Volumes⁽⁴⁾ (thousands of barrels per day)
Crude oil lease gathering			437			410			348
Crude oil bulk purchases⁽⁵⁾			90			68			46

	Total		527			478			394

LPG sales			38			35			19

⁽¹⁾: Revenue and purchases include intersegment amounts.
⁽²⁾: Segment G&A expenses 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.
⁽⁴⁾: 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.
⁽⁵⁾: We have decreased the number of barrels previously disclosed in the "Crude oil bulk purchases" line for the 2002 period by approximately 12,000. The adjustment reflects an elimination of crude oil volumes improperly classified as bulk purchases.

Revenues increased approximately 51% in 2003 compared to the prior year, while our segment profit increased 7% in the same period. Approximately 55% of the increase in revenues related to increased sales volumes and the remaining 45% of the increase resulted from higher average prices in 2003. The increase in sales volumes primarily related to barrels sold under buy/sell and bulk purchase arrangements, both of which generate significantly less margin than our lease gathered barrels. We do not consider barrels sold under these arrangements to be a primary driver of segment performance and they are not included in the volumes we disclose as lease gathered barrels, which are a primary driver of segment performance. Segment profits from these arrangements are generally lower and not as sustainable as our lease purchased barrels, as they are driven mainly by market opportunity, and can vary significantly from month to month. With respect to a relationship between volumes and segment profit, we expect our segment profit to increase or decrease directionally with increases or decreases in lease gathered volumes and LPG sales volumes.

As a result of completing our Phase II and III expansions at our Cushing facility, total Cushing tankage dedicated to our Gathering, Marketing, Terminalling and Storage Operations was approximately 1.5 million barrels greater in 2003 relative to 2002. A portion of such tankage was

employed in hedging activities related to our gathering and marketing activities in 2003 and the latter portion of 2002.

During 2003, market conditions were extremely volatile as a confluence of several events caused the NYMEX benchmark price of crude oil to fluctuate widely with prices ranging from as high as $39.99 per barrel to as low as $25.04 per barrel. For much of the first eight months of 2003, the crude oil market was in steep backwardation. Although the crude oil market was characterized by high absolute prices in the fourth quarter, the average backwardation for the quarter was in line with a normal crude oil market. These market conditions and volatility, in conjunction with our hedging strategies, enhanced the returns of our gathering and marketing activities. This was partially offset by the negative impact that the August 2003 blackout had on our fourth quarter margins. In contrast, market conditions during 2002 were less favorable as the crude oil market alternated between periods of weak contango and strong backwardation. In 2001, the market alternated between weak contango and weak backwardation.

The following factors contributed to our growth in segment profit during 2003 as compared to 2002:

•: the overall counter cyclical balance of our assets and the flexibility embedded in our business strategy;
•: increased tankage available to our gathering and marketing business;
•: increased lease gathering volumes;
•: the backwardated market structure and volatile market conditions;
•: increased sales and higher margins in our LPG activities for the first quarter because of cold weather throughout the U.S. and Canada; and
•: appreciation of Canadian currency (the Canadian dollar to U.S. dollar exchange rate appreciated to an average of 1.40 to 1 for the year ended December 31, 2003, from an average of 1.57 to 1 for the year ended December 31, 2002).

As discussed above, 2002 market conditions were characterized by periods of weak contango and strong backwardation. Although these conditions are generally disadvantageous for our gathering and marketing activities, the 2001 market conditions were even less favorable. These market conditions and increased crude oil lease gathering volumes contributed to the growth in our segment profit in 2002 as compared to 2001. The increased volumes resulted predominantly from the inclusion of the assets acquired in the CANPET acquisition for the entire year in 2002 as compared to only a portion of 2001. The increase in segment profit was also impacted by decreased field operating costs in the 2002 period as compared to the 2001 period as discussed further below.

Field operating costs included in segment profit increased to approximately $77.6 million in the year ended December 31, 2003 compared to $66.3 million and $73.7 million for the years ended December 31, 2002 and 2001, respectively. The increase in 2003 includes $4.3 million related to the probable vesting of unit grants under our LTIP. The remaining increase was partially related to our continued growth, primarily from acquisitions, coupled with increased regulatory compliance activities and higher fuel costs. The decrease in field operating costs in 2002 as compared to 2001 was primarily related to the inclusion in 2001 of a $5.0 million noncash writedown of operating crude oil inventory and a $2.0 million noncash reserve for doubtful accounts.

Segment G&A expenses include the costs directly associated with the segments, as well as a portion of corporate overhead costs considered allocable. See "—Other Income and Expenses." Segment G&A expense increased to $45.1 million in 2003 compared to $31.5 million and $28.5 million for 2002 and 2001, respectively. Included in the 2003 amount is $13.5 million related to the accrual for

the probable vesting of unit grants under our LTIP. The percentage of indirect costs allocated to the Gathering, Marketing, Terminalling and Storage Operations segment has decreased from period to period as our pipeline operations have grown, partially offsetting the impact of the overall increase in G&A resulting from our continued growth. Segment G&A expenses increased in 2002 from 2001 primarily because of increased costs of $5.6 million from the assets acquired in the CANPET acquisition due to the inclusion of those assets for all of 2002 compared to only a portion of 2001. This increase was offset by decreased segment G&A of $2.6 million from our domestic operations. This decrease was partially related to a reduction in accounting and consulting costs in 2002 from those that had been incurred in 2001. Partially offsetting these items is the approximately $2.4 million favorable impact on segment profit because of the appreciation of the Canadian dollar.

The crude oil volumes gathered from producers, using our assets or third party assets, has increased by 7% and 18% during 2003 and 2002, respectively. The increase in 2003 is primarily related to organic growth and acquisitions, which has offset natural production declines. The increase in 2002 resulted primarily from our acquisition activities. In addition, we marketed 38,000 barrels per day of LPG during 2003 compared to 35,000 barrels per day and 19,000 barrels per day in 2002 and 2001, respectively. The increase in 2002 is primarily related to the inclusion of a full year of our LPG operations in the 2002 period compared to only six months during 2001. Segment profit per barrel calculated based on our lease gathered crude oil and LPG barrels was $0.36 per barrel for the year ended December 31, 2003, compared to $0.36 and $0.32 for the years ended December 31, 2002 and 2001, respectively.

Revenues from our gathering, marketing, terminalling and storage operations were approximately $12.0 billion, $7.9 billion and $6.5 billion for the years ended December 31, 2003, 2002 and 2001, respectively. As discussed above, revenues and costs related to purchases for 2003 were impacted by higher average prices and higher volumes in the 2003 period as compared to the 2002 period. The average NYMEX price for crude oil was $31.08 per barrel and $26.10 per barrel for 2003 and 2002, respectively. The increase in revenues and costs related to purchases in 2002 as compared to 2001 was predominantly related to higher sales volumes, as the average NYMEX price for crude oil in 2002 was only $0.12 higher than the $25.98 average in 2001.

Maintenance capital. For the periods ended December 31, 2003, 2002 and 2001, maintenance capital expenditures were approximately $1.2 million, $2.6 million and $2.9 million, respectively for our gathering, marketing, terminalling and storage operations segment. The decrease in 2003 as compared to 2002 and 2001 is primarily because of a reduction in costs associated with information systems and the replacement of a portion of our fleet.

Other Income and Expenses

Unallocated G&A Expenses. Total G&A expenses were $73.0 million, $45.7 million and $46.6 million for the years ended December 31, 2003, 2002 and 2001, respectively. We have included in the above segment discussion the G&A expenses for each of these years that were attributable to our segments either directly or by allocation. During 2002, we were unsuccessful in our pursuit of several sizable acquisition opportunities determined by auction and one negotiated transaction that had advanced nearly to the execution stage when it was abruptly terminated by the seller. As a result, our 2002 results reflect a $1.0 million charge to G&A expenses associated with the third party costs of these unsuccessful transactions.

During 2001, we incurred charges of $5.7 million that were not attributable to a segment, related to incentive compensation paid to certain officers and key employees of Plains Resources and its affiliates. In 1998 (in connection with our IPO) and 2000, Plains Resources granted certain officers and key employees of the former general partner the right to earn ownership in a portion of our common units owned by it. These rights provided for vesting over a three-year period, subject to distributions

being paid on the common and subordinated units. In connection with the general partner transition in 2001, these rights, as well as grants to directors under our LTIP, vested. This resulted in a charge to our 2001 income of approximately $6.1 million, of which Plains Resources funded approximately 94%. Approximately $5.7 million of the charge was noncash and was not allocated to a segment.

Depreciation and Amortization. Depreciation and amortization expense was $46.8 million for the year ended December 31, 2003, compared to $34.1 million and $24.3 million for the years ended December 31, 2002 and 2001, respectively. The increase in 2003 relates primarily to the inclusion of the assets from the Shell acquisition for the entire year as compared to a portion of 2002. Additionally, several acquisitions were completed during the year along with various capital projects. Amortization of debt issue costs was $3.8 million in 2003, and was essentially unchanged from $3.7 million in 2002.

The increase in 2002 over 2001 consists of approximately $4.1 million related to the inclusion of assets from the Shell acquisition and approximately $3.5 million related to the inclusion of the assets from the Murphy and CANPET acquisitions for all of 2002 compared to only a portion of 2001. The remainder of the increase is related to increased debt issue costs related to the amendment of our credit facilities during 2002 and late 2001, the sale of senior notes in September 2002 and the completion of various capital projects.

Interest Expense. Interest expense was $35.2 million for the year ended December 31, 2003, compared to $29.1 million for each of the years ended December 31, 2002 and 2001, respectively. The increase in 2003 compared to 2002 was primarily related to an increase in the average debt balance during the 2003 period to approximately $525.5 million from approximately $444.6 million in the 2002 period, which resulted in additional interest expense of approximately $5.0 million. The higher average debt balance was primarily due to the portion of the Shell acquisition that was not financed with equity. This debt was outstanding for all of 2003 versus only a portion of 2002. Also, increased commitment and other fees coupled with lower capitalized interest resulted in approximately $2.2 million of the increase in the 2003 period. Our weighted average interest rate decreased slightly during 2003 to 6.0% versus 6.2% in 2002, which decreased our interest expense by approximately $1.1 million. Although the change in our weighted average interest rate was nominal, the change was the net result of various factors that included an increase in the amount of fixed rate, long-term debt, long-term interest rate hedges and declining short-term interest rates. In mid-September 2002, we issued $200 million of ten-year bonds bearing a fixed interest rate of 7.75%. In the fourth quarter of 2002 and the first quarter of 2003, we entered into hedging arrangements to lock in interest rates on approximately $50 million of our floating rate debt. In addition, the average three month LIBOR rate declined from approximately 1.8% during 2002 to approximately 1.2% during 2003. The net impact of these factors, increased commitment fees and changes in average debt balances decreased the average interest rate by 0.2%.

Interest expense was relatively flat in the 2002 period as compared to 2001 due to the impact of higher debt levels and commitment fees offset by lower average interest rates and the capitalization of interest. The overall increased average debt balance in 2002 is due to the portion of the Shell acquisition in August 2002 which was not financed with the issuance of equity. During the third quarter of 2001, we issued a $200 million senior secured term B loan, the proceeds of which were used to reduce borrowings under our revolver. As such, our commitment fees on our revolver increased as they are based on unused availability. The lower interest rates in 2002 are due to a decrease in LIBOR and prime rates in the current year. In addition, approximately $0.8 million of interest expense was capitalized during 2002, in conjunction with expansion construction on our Cushing terminal compared to approximately $0.2 million in the 2001 period.

Other. During the fourth quarter of 2003 we completed the refinancing of our bank credit facilities with new senior unsecured credit facilities totaling $750 million and a $200 million uncommitted facility for the purchase of hedged crude oil. In addition, during the third quarter of 2003

we made a $34 million prepayment on our senior secured term B loan in anticipation of the refinancing. The completion of these transactions resulted in a non-cash charge of approximately $3.3 million associated with the write-off of unamortized debt issue costs.

Outlook

This section identifies certain matters of risk and uncertainty that may affect our financial performance and results of operations in the future.

Ongoing Acquisition Activities. Consistent with our business strategy, we are continuously engaged in discussions with potential sellers regarding the possible purchase by us of transportation, gathering, terminalling or storage assets and related businesses. These acquisition efforts often involve assets which, if acquired, would have a material effect on our financial condition and results of operations. In an effort to prudently and economically leverage our asset base, knowledge base and skill sets, management has also expanded its efforts to encompass businesses that are closely related to, or significantly intertwined with, the crude oil business. We can give no assurance that our current or future acquisition efforts will be successful or that any such acquisition will be completed on terms considered favorable to us.

OCS Production. In October 2004, Plains Exploration and Production ("PXP") announced that it had successfully completed an initial development well into the Rocky Point field, which is accessible from the Point Arguello platforms and that drilling operations are underway on a second development well. Such drilling activities, if successful, are not expected to have a significant impact on pipeline shipments on our All American Pipeline system in 2004, but could lead to increased volumes in future periods. We can give no assurances, however, that our volumes transported would increase as a result of this drilling activity.

Pipeline Integrity and Storage Tank Testing Compliance. Although we believe our short-term estimates of costs under the pipeline integrity management rules and API 653 (and similar Canadian regulations) are reasonable, a high degree of uncertainty exists with respect to estimating such costs, as we continue to test existing assets and as we acquire new assets.

Sarbanes Oxley Act and New SEC Rules. Several regulatory and legislative initiatives were introduced in 2002 and 2003 in response to developments during 2001 and 2002 regarding accounting issues at large public companies, resulting disruptions in the capital markets and ensuing calls for action to prevent recurrence of similar events. Implementation of reforms in connection with these initiatives have added and will add to the costs of doing business for all publicly traded entities, including us as a partnership. These costs will have an adverse impact on future income and cash flow.

Among the new requirements is the requirement under Section 404 of the Act, beginning with our 2004 Annual Report, for management to report on our internal control over financial reporting and for our independent public accountants to attest to management's report. During 2003, we commenced actions to enhance our ability to comply with these requirements, including but not limited to the addition of staffing in our internal audit department, documentation of existing controls and implementation of new controls or modification of existing controls as deemed appropriate. We have continued to devote substantial time and resources to the documentation and testing of our controls, and to planning for and implementation of remedial efforts in those instances where remediation is indicated. At this point, we have no indication that management will be unable to favorably report on our internal controls nor that our independent auditors will be unable to attest to management's findings. Both we and our auditors, however, must complete the process (which we have never completed before), so we cannot assure you of the results. It is unclear what impact failure to comply fully with Section 404 or the discovery of a material weakness in our internal control over financial reporting would have on us, but presumably it could result in the reduced ability to obtain financing, the loss of customers, and additional expenditures to meet the requirements.

Longer Term Outlook. Our longer-term outlook, spanning a period of five or more years, is influenced by many factors affecting the North American crude oil sector. Some of the more significant trends and factors include:

1.: Continued overall depletion of U.S. crude oil production.
2.: The continuing convergence of worldwide crude oil supply and demand lines.
3.: Aggressive practices in the U.S. to maintain working crude oil inventory levels below historical levels.
4.: Industry compliance with the Department of Transportation's adoption of the American Petroleum Institute's standard 653 for testing and maintenance of storage tanks, which will require significant investments to maintain existing crude oil storage capacity or, alternatively, will result in a reduction of existing storage capacity by 2009.
5.: The introduction of increased crude oil production from North American supplies (primarily Canadian oil sands and deepwater Gulf of Mexico sources) that will, of economic necessity, compete for U.S. markets currently being supplied by non-North American foreign crude imports.

We believe the collective impact of these trends, factors and developments, many of which are beyond our control, will result in an increasingly volatile crude oil market that is subject to more frequent short-term swings in market prices and grade differentials and shifts in market structure. In an environment of reduced inventories and tight supply and demand balances, even relatively minor supply disruptions can cause significant price swings. Conversely, despite a relatively balanced market on a global basis, competition within a given region of the U.S. could cause downward pricing pressure and significantly impact regional crude oil price differentials among crude oil grades and locations. Although we believe our business strategy is designed to manage these trends, factors and potential developments, and that we are strategically positioned to benefit from certain of these developments, there can be no assurance that we will not be negatively affected.

Liquidity and Capital Resources

Liquidity

Cash generated from operations and our credit facilities are our primary sources of liquidity. At September 30, 2004, we had a working capital deficit of approximately $50.5 million, approximately $401.1 million of availability under our committed revolving credit facilities and $240.5 million of unused capacity under our uncommitted hedged inventory facility. Usage of the credit facilities is subject to compliance with covenants. We believe we are currently in compliance with all covenants.

In the third quarter of 2004, we completed a public offering of 4,968,000 common units for $33.25 per unit. The offering resulted in gross proceeds of approximately $165.2 million from the sale of units and approximately $3.4 million from our general partner's proportionate capital contribution. Total costs associated with the offering, including underwriter fees and other expenses, were approximately $7.7 million. Net proceeds of $160.9 million were used to permanently reduce outstanding borrowings under the $200 million, 364-day credit facility.

On August 12, 2004, we sold the outstanding Notes. We used the net proceeds, after deducting initial purchaser discounts and offering costs, of approximately $345.3 million to repay amounts outstanding under our credit facilities, including the remaining balance under the $200 million, 364-day facility we used to fund the Link acquisition, and for general partnership purposes. In connection with this repayment, we terminated the facility. Subsequent to the notes offering, we also terminated our $125 million, 364-day facility, which was scheduled to expire in November 2004.

In November 2004, we entered into a new $750 million, five-year senior credit facility, which contains a sub-facility for Canadian borrowings up to $300 million. The new facility extends our maturities, lowers our cost of credit and provides an additional $125 million of liquidity over our previous facility. The facility can be expanded to $1 billion. Also in November 2004, we increased the capacity of our uncommitted senior secured hedged inventory facility to $400 million (with the ability to increase in the future by an incremental $100 million), and extended the maturity to November 2005.

Capital Expenditures

We have made and will continue to make capital expenditures for acquisitions, expansion capital and maintenance capital. Historically, we have financed these expenditures primarily with cash generated by operations, credit facility borrowings, the issuance of senior unsecured notes and the sale of additional common units.

We expect to spend approximately $139.4 million on expansion capital projects during 2004. This includes our original estimate of expansion capital, newly announced projects and expansion capital

associated with the Link acquisition. Our 2004 expansion capital projects include the following notable projects with the estimated cost for the entire year.

	Incurred Through September 30, 2004		Estimated to be Incurred in the Fourth Quarter of 2004		2004 Total
			(in millions)
Cushing to Caney pipeline project	$	14.6	$	27.4	$	42.0
Trenton pipeline expansion		0.7		18.6		19.3
Capital projects and upgrades associated with the Link acquisition		4.8		4.2		9.0
Capital projects and upgrades associated with the Cal Ven acquisition		—		2.5		2.5
Cushing Phase IV expansion		10.0		—		10.0
Upgrade and expansion related to acquisitions made in 2003		8.2		0.9		9.1
Iatan System expansion		3.7		—		3.7
Other		25.6		18.2		43.8

	$	67.6	$	71.8	$	139.4

In addition, we expect to spend approximately $10.1 million on maintenance capital projects during 2004. For the first nine months of 2004, we have incurred approximately $6.1 million on maintenance capital projects.

We believe that we have sufficient liquid assets, cash flow from operations and borrowing capacity under our credit agreements to meet our financial commitments, debt service obligations, contingencies and anticipated capital expenditures. However, we are subject to business and operational risks that could adversely affect our cash flow. A material decrease in our cash flows would likely produce a corollary adverse effect on our borrowing capacity.

Cash Flows

Cash flows for the nine months ended September 30, 2004 and 2003 were as follows:

		Nine Months Ended September 30,
		2004			2003
		(in millions)
Cash provided by (used in):
	Operating activities	$	113.1		$	236.1
	Investing activities		(567.3	)		(185.2	)
	Financing activities		453.4			(51.0	)

Operating Activities. The primary drivers of our cash flow from 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, general and administrative expenses and interest expense. 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 in the months that we store inventory because of contango market conditions or in months that we increase linefill. The storage of crude oil in periods of a contango market can have a material impact on our cash flows from operating activities for the period we pay for and store the crude oil and the subsequent period that we receive proceeds from the sale of the crude oil. When we store crude oil, we borrow on our credit facilities to pay for the crude oil and the impact on operating cash flow is negative. Conversely, cash flow from operations increases

in the period we collect the cash from the sale of the stored crude oil. To a lesser extent, our cash flow from operating activities is also impacted by the level of LPG inventory stored at period end. Cash flow from operations was $113.1 million and $236.1 million in 2004 and 2003, respectively.

Investing Activities. Net cash used in investing activities in 2004 and 2003 consisted predominantly of cash paid for acquisitions. Net cash used in 2004 was $567.3 million and was primarily comprised of (i) $142.5 million paid for the Capline and Capwood Pipeline Systems acquisition (a deposit had been paid in December 2003) (ii) approximately $283 million paid for the Link acquisition, (iii) approximately $19 million paid for the CalVen acquisition (iv) approximately $46.2 million paid for the Schaefferstown acquisition (including inventory of $14.2 million) (v) approximately $63.6 million paid for additions to property and equipment, and (vi) approximately $10.2 million paid for linefill on assets that we own. Some of the major items included in cash paid for additions to property and equipment is (i) approximately $8.6 million related to the Cushing Phase IV expansion, (ii) approximately $5.0 million related to the Iatan System expansion, (iii) approximately $5.4 million of maintenance capital, (iv) approximately $10.7 million related to the Cushing to Caney pipeline project, and (v) approximately $6.6 million related to our Red River pipeline system. Net cash used in investing activities in 2003 includes approximately $99.9 million paid for acquisitions and approximately $52.2 million for additions to property and equipment. In addition, approximately $40.4 million was paid for linefill on assets that we own. We received proceeds from sales of assets of approximately $7.1 million.

Financing Activities. Cash provided by financing activities in 2004 was approximately $453.4 million and was comprised of (i) approximately $100.8 million of proceeds from the issuance of Class C common units, (ii) approximately $160.9 million of proceeds from the issuance of common units, (iii) approximately $346.4 million of proceeds from the sale of the outstanding Notes, (iv) net short and long-term borrowings under our revolving credit facility of approximately $4.7 million, (v) net repayments under our short-term letter of credit and hedged inventory facility of approximately $42.2 million resulting from the collection of receivables related to prior year sales of inventory that was stored because of contango market conditions and (vi) $114.5 million of distributions paid to common unitholders and the general partner. Cash used in financing activities in 2003 consisted of (i) approximately $161.9 million of proceeds from the issuance of common units used to pay down outstanding balances on the revolving credit facility and a secured term loan, (ii) $89.3 million of distributions paid to unitholders and the general partner, (iii) a $43.0 million of principal repayments of our term loans, (iv) net long-term repayments under our revolving credit facilities of $13.1 million, and (v) net short-term debt repayments of $67.3 million primarily from the proceeds of inventory sales.

Cash flows for the years ended December 31, 2003, 2002 and 2001 were as follows:

		Year ended December 31,
		2003			2002			2001
		(in millions)
Cash provided by (used in):
	Operating activities	$	115.3		$	185.0		$	(16.2	)
	Investing activities		(272.1	)		(374.9	)		(263.2	)
	Financing activities		157.2			189.5			279.5

Operating Activities. Our positive cash flow from operations 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 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 counter parties 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.

Our positive cash flow from operations for 2002 resulted from cash generated by our recurring operations. In addition, we received approximately $93 million of proceeds during 2002 associated with crude oil hedged and stored during 2001. This was partially offset by the payment of approximately $74 million for crude oil purchased and stored during 2002 but for which receipt of the proceeds occurred during 2003. In addition, our 2002 cash flow from operating activities was positively impacted by the collection of approximately $21 million of prepayments from counter parties to mitigate our credit risks and the collection of approximately $9.1 million of amounts that had been outstanding primarily since 1999 and 2000.

Our negative cash flow from operations for 2001 resulted from positive cash generated by our recurring operations offset by the payment of approximately $93 million for crude oil hedged and stored during 2001 for which receipt of the proceeds occurred during 2002.

Investing Activities. Net cash used in investing activities in 2003, 2002 and 2001 consisted predominantly of cash paid for acquisitions and purchases of linefill. Net cash used in 2003 was $272.1 million and was comprised of (i) an aggregate $152.6 million paid primarily for ten acquisitions completed during 2003, (ii) a $15.8 million deposit paid on the acquisition from Shell Pipeline Company; see "—Acquisitions", (iii) proceeds of approximately $8.5 million from sales of assets, and (iv) $65.4 million paid for additions to property and equipment, including $19.2 million related to the construction of crude oil gathering and transmission lines in West Texas, and (v) crude oil linefill purchases of approximately $47 million, primarily attributable to increased linefill requirements related to 2003 and 2002 acquisitions. Net cash used in 2002 was $374.9 million and was comprised of (i) an aggregate $324.6 million paid for three acquisitions completed during 2002; see "—Acquisitions", and (ii) $40.6 million paid for additions to property and equipment, primarily related to our Cushing expansion and the construction of the Marshall terminal in Canada, and (iii) crude oil linefill purchases of approximately $11 million. Net cash used in 2001 was $263.2 million and was comprised of (i) an aggregate $229.2 million paid for three acquisitions completed during 2001; see "—Acquisitions", and (ii) $21.1 million paid for additions to property and equipment, and (iii) approximately $13.7 million of crude oil linefill attributable to increased linefill requirements.

Financing Activities. Cash provided by financing activities in 2003 consisted primarily of $499.7 million of net proceeds from the issuance of common units and senior unsecured notes, used primarily to fund capital projects and acquisitions and pay down outstanding balances on our revolving credit facilities and senior term loans. Net repayments of our short-term and long-term revolving credit facilities and related senior term loans were $215.4 million. In addition, $121.8 million of distributions were paid to our unitholders and general partner. Cash provided by financing activities in 2002 consisted of approximately $344.6 million of net proceeds from the issuance of common units and senior unsecured notes, used primarily to fund capital projects and acquisitions and pay down outstanding balances on the revolving credit facility. Net repayments of our short-term and long-term revolving credit facilities during 2002 were $49.9 million. In addition, $99.8 million of distributions were paid to our unitholders and general partner during the year ended December 31, 2002.

Cash provided by financing activities in 2001 consisted primarily of net short-term and long-term borrowings of $134.3 million, proceeds from the issuance of common units of $227.5 million, and the payment of $75.9 million in distributions to our unitholders and general partner.

Contingencies

Industry Credit Markets and Accounts Receivable. Throughout the latter part of 2001 and all of 2002, there were significant disruptions and extreme volatility in the financial markets and credit markets. Because of the credit intensive nature of the energy industry and extreme financial distress at

several large, diversified energy companies, the energy industry was especially impacted by these developments. We believe that these developments have created an increased level of direct and indirect counterparty credit and performance risk.

The majority of our credit extensions relate to our gathering and marketing activities that can generally be described as high volume and low margin activities. During periods of relatively higher prices, our absolute exposure to any given counterparty may be increased. In our credit approval process, we make a determination of the amount, if any, of the line of credit to be extended to any given customer and the form and amount of financial performance assurances we require. Such financial assurances are commonly provided to us in the form of standby letters of credit, advance cash payments or "parental" guarantees. As of September 30, 2004, we had received approximately $24.4 million of advance cash payments and prepayments from third parties to mitigate credit risk.

Pipeline and Storage Regulation. Some of our petroleum pipelines and storage tanks in the United States are subject to regulation by the U.S. Department of Transportation ("DOT") with respect to the design, installation, testing, construction, operation, replacement and management of pipeline and tank facilities. In addition, we must permit access to and copying of records, and must make certain reports available and provide information as required by the Secretary of Transportation. Comparable regulation exists in Canada and in some states in which we conduct intrastate common carrier or private pipeline operations. See "Business—Regulation—Pipeline and Storage Regulation."

Regulatory compliance costs include those related to pipeline integrity management and the adoption by the DOT of API 653 as the standard for the inspection, repair, alteration and reconstruction of jurisdictional storage tanks. For our estimates of costs associated with these regulations, see "Business—Regulation—Pipeline and Storage Regulation."

Export License Matter. In our gathering and marketing activities, we import and export crude oil from and to Canada. Exports of crude oil are subject to the "short supply" controls of the Export Administration Regulations ("EAR") and must be licensed by the Bureau of Industry and Security (the "BIS") of the U.S. Commerce Department. In 2002, we determined that we may have exceeded our licenses with respect to the quantity of crude oil exported and the end-users in Canada. Export of crude oil except as authorized by license is a violation of the EAR. In October 2002, we submitted to the BIS an initial notification of voluntary disclosure. The BIS subsequently informed us that we could continue to export while previous exports were under review. We applied for and received several new licenses allowing for export volumes and end users that more accurately reflect our anticipated business and customer needs. We also conducted reviews of new and existing contracts and implemented new procedures and practices in order to monitor compliance with applicable laws regarding the export of crude oil to Canada. As a result, we subsequently submitted additional information to the BIS in October 2003 and May 2004. In August 2004, we received a request from the BIS for additional information. We have responded to this and subsequent requests, and continue to cooperate fully with BIS officials. At this time, we have received neither a warning letter nor a charging letter, which could involve the imposition of penalties, and no indication of what penalties the BIS might assess. As a result, we cannot reasonably estimate the ultimate impact of this matter.

L.P. common unitholders, asserts breach of fiduciary duty and breach of contract claims against us, Plains AAP, L.P., and Plains All American GP LLC and its directors, as well as breach of fiduciary duty claims against Plains Resources Inc. and its directors. The complaint seeks to enjoin or rescind a proposed acquisition of all of the outstanding stock of Plains Resources Inc., as well as declaratory relief, an accounting, disgorgement and the imposition of a constructive trust, and an award of damages, fees, expenses and costs, among other things. This lawsuit has been settled in principle, subject to the preparation and execution of appropriate settlement documentation and court approval.

General. We, in the ordinary course of business, are a claimant and/or a defendant in various legal proceedings. We do not believe that the outcome of these legal proceedings, individually or in the aggregate, will have a materially adverse effect on our financial condition, results of operations or cash flows.

Environmental. We may experience future releases of crude oil into the environment from our pipeline, gathering and storage operations, or discover past releases that were previously unidentified. Although we maintain an inspection program designed to prevent and, as applicable, to detect and address such releases promptly, damages and liabilities incurred due to any such environmental releases from our assets may substantially affect our business. At September 30, 2004, our reserve for environmental liabilities totaled approximately $21.4 million. Approximately $13.8 million of the reserve is related to liabilities assumed as part of the Link acquisition. Although we believe our reserve is adequate, no assurance can be given that any costs incurred in excess of this reserve would not have a material adverse effect on our financial condition, results of operations or cash flows.

Other. A pipeline, terminal or other facility may experience damage as a result of an accident or natural disaster. These hazards can cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage and suspension of operations. We maintain insurance of various types that we consider adequate to cover our operations and properties. The insurance covers our assets in amounts considered reasonable. The insurance policies are subject to deductibles that we consider reasonable and not excessive. Our insurance does not cover every potential risk associated with operating pipelines, terminals and other facilities, including the potential loss of significant revenues. The trend appears to be a contraction in the breadth and depth of available coverage, while costs, deductibles and retention levels have increased. Absent a material favorable change in the insurance markets, this trend is expected to continue as we continue to grow and expand. As a result, we anticipate that we will elect to self-insure more of our activities.

The occurrence of a significant event not fully insured, indemnified or reserved against, or the failure of a party to meet its indemnification obligations, could materially and adversely affect our operations and financial condition. We believe we are adequately insured for public liability and property damage to others with respect to our operations. With respect to all of our coverage, no assurance can be given that we will be able to maintain adequate insurance in the future at rates we consider reasonable, or that we have established adequate reserves to the extent that such risks are not insured.

Credit Facilities and Long-Term Debt

During August 2004, we completed the sale of the outstanding Notes to which this exchange relates. We used the proceeds from the sale of the outstanding Notes to repay amounts outstanding

under our credit facilities, including the remaining balance under the $200 million, 364-day facility funded in connection with the Link acquisition, and for general partnership purposes. In connection with this repayment, we terminated the facility. The repayment and termination of this facility resulted in a non-cash charge of approximately $0.7 million associated with the write-off of unamortized debt issue costs. Subsequent to the Notes offering, we also terminated our $125 million, 364-day facility that was scheduled to expire in November 2004.

During December 2003, we completed the sale of $250 million of 5.625% senior notes due December 2013. The notes were issued by us and a 100% owned finance subsidiary (neither of which have independent assets or operations) at a discount of $0.7 million, resulting in an effective interest rate of 5.66%. Interest payments are due on June 15 and December 15 of each year. The notes are fully and unconditionally guaranteed, jointly and severally, by all of our existing 100% owned subsidiaries, except for subsidiaries that are minor.

In November 2004, we entered into a new $750 million, five-year senior unsecured credit facility, which contains a sub-facility for Canadian borrowings of up to $300 million. The new credit facility extends our maturities, lowers our cost of credit and provides an additional $125 million of liquidity over our previous facilities. This facility can be expanded to $1 billion. As of November 30, 2004, we had approximately $195.5 million outstanding under this credit facility, as well as $58.7 million in letters of credit outstanding, resulting in unused capacity under the facility of approximately $495.8 million.

Also in November 2004, we amended and restated our secured hedged inventory facility; increasing the facility to $400 million, with the ability to further increase the facility in the future by an incremental $100 million. This facility is an uncommitted working capital facility, which is used to finance the purchase of hedged crude oil inventory for storage when market conditions warrant. Borrowings under the hedged inventory facility are secured by the inventory purchased under the facility and the associated accounts receivable, and will be repaid with the proceeds from the sale of such inventory. This facility expires in November 2005. As of November 30, 2004, we had approximately $124.8 million outstanding and no letters of credit issued under our hedged crude oil inventory facility resulting in unused uncommitted capacity under this facility of approximately $275.2 million.

Our credit agreements, the indentures governing the outstanding Notes and our other senior notes contain cross default provisions. Our credit agreements prohibit distributions on, or purchases or redemptions of, units if any default or event of default is continuing. In addition, the agreements contain various covenants limiting our ability to, among other things:

•: incur indebtedness if certain financial ratios are not maintained;
•: grant liens;
•: engage in transactions with affiliates;
•: enter into sale-leaseback transactions;
•: sell substantially all of our assets or enter into a merger or consolidation.

Our credit facility treats a change of control as an event of default and also requires us to maintain:

•: an interest coverage ratio that is not less than 2.75 to 1.0; and
•: a debt coverage ratio which will not be greater than 4.75 to 1.0 on all outstanding debt and 5.25 to 1.0 on all outstanding debt during an acquisition period (generally, the period consisting of three fiscal quarters following an acquisition greater than $50 million).

For covenant compliance purposes, letters of credit and borrowings to fund hedged inventory and margin requirements are excluded when calculating the debt coverage ratio.

A default under our credit facility would permit the lenders to accelerate the maturity of the outstanding debt. As long as we are in compliance with our credit agreements, our ability to make distributions of available cash is not restricted. We are currently in compliance with the covenants contained in our credit agreements and indentures.

Commitments

Contractual Obligations. In the ordinary course of doing business we enter into various contractual obligations for varying terms and amounts. The following table includes our non-cancelable contractual obligations as of September 30, 2004, and our best estimate of the period in which the obligation will be settled:

	2004		2005		2006		2007		2008		Thereafter		Total
					(in millions)
Long-term debt	$	—	$	—	$	0.4	$	30.0	$	—	$	810.0	$	840.4
Operating leases⁽¹⁾		4.1		15.9		13.9		10.3		5.7		13.1		63.0
Capital expenditure obligations		46.0		8.7		—		—		—		—		54.7
Other long-term liabilities		0.8		0.5		0.2		—		—		—		1.5

Total	$	50.9	$	25.1	$	14.5	$	40.3	$	5.7	$	823.1	$	959.6

⁽¹⁾: Operating leases are primarily for office rent and trucks used in our gathering activities.

In addition to the items in the table above, we have entered into various operational commitments and agreements related to pipeline operations and to the marketing, transportation, terminalling and storage of crude oil and the marketing and storage of LPG. The majority of these contractual commitments are for the purchase of crude oil and LPG that are made under contracts that range in term from a thirty-day evergreen to three years. A substantial portion of the contracts that extend beyond thirty days include cancellation provisions that allow us to cancel the contract with thirty days written notice. From time to time, we also enter into various types of sale and exchange transactions including fixed price delivery contracts, floating price collar arrangements, financial swaps and crude oil futures contracts as hedging devices. Through these transactions, we seek to maintain a position that is substantially balanced between crude oil and LPG purchases and sales and future delivery obligations. The volume and prices of these purchase and sale contracts are subject to market volatility and fluctuate with changes in the NYMEX price of crude oil from period to period. During the third quarter 2004, these purchases averaged approximately $1.8 billion per month.

Letters of Credit. In connection with our crude oil marketing, we provide certain suppliers and transporters with irrevocable standby letters of credit to secure our obligation for the purchase of crude oil. Our liabilities with respect to these purchase obligations are recorded in accounts payable on our balance sheet in the month the crude oil is purchased. Generally, these letters of credit are issued for up to seventy-day periods and are terminated upon completion of each transaction. At September 30, 2004, we had outstanding letters of credit of approximately $123.9 million.

Distributions. We will distribute 100% of our available cash within 45 days after the end of each quarter to unitholders of record and to our general partner. Available cash is generally defined as all cash and cash equivalents on hand at the end of the quarter less reserves established by our general partner for future requirements. On November 12, 2004, we paid a cash distribution of $0.60 per unit on all outstanding units. The total distribution paid was approximately $43.9 million, with approximately $40.4 million paid to our common unitholders and approximately $3.5 million paid to our general partner for its general partner ($0.8 million) and incentive distribution interests ($2.7 million).

Our general partner is entitled to incentive distributions if the amount we distribute with respect to any quarter exceeds levels specified in our partnership agreement. Under the quarterly incentive

distribution provisions, our general partner is entitled, without duplication, to 15% of amounts we distribute in excess of $0.450 per limited partner unit, 25% of amounts we distribute in excess of $0.495 per limited partner unit and 50% of amounts we distribute in excess of $0.675 per limited partner unit.

In 2003, we paid $4.9 million in incentive distributions to our general partner. Thus far in 2004 (through November 12, 2004), we have paid $8.3 million in incentive distributions to our general partner. See "Certain Relationships and Related Transactions—Our General Partner."

Off-Balance Sheet Arrangements

We have no off-balance sheet arrangements as defined by Item 307 of Regulation S-K.

Quantitative and Qualitative Disclosures About Market Risks

We are exposed to various market risks, including volatility in (i) crude oil and LPG commodity prices, (ii) interest rates and (iii) currency exchange rates. We utilize various derivative instruments to manage such exposure. Our risk management policies and procedures are designed to monitor interest rates, currency exchange rates, NYMEX and over-the-counter positions, and physical volumes, grades, locations and delivery schedules to ensure our hedging activities address our market risks. We have a risk management function that has direct responsibility and authority for our risk policies and our trading controls and procedures and certain aspects of corporate risk management. To hedge the risks discussed above we engage in price risk management activities that we categorize by the risks we are hedging. The following discussion addresses each category of risk.

Commodity Price Risk

In order to hedge margins involving our physical assets and manage risks associated with our crude oil purchase and sale obligations, we use derivative instruments, including regulated futures and options transactions, as well as over-the-counter instruments. In analyzing our risk management activities, we draw a distinction between enterprise level risks and trading related risks. Enterprise level risks are those that underlie our core businesses and may be managed based on whether there is value in doing so. Conversely, trading related risks (the risks involved in trading in the hopes of generating an increased return) are not inherent in the core business; rather, those risks arise as a result of engaging in the trading activity. We have a Risk Management Committee that approves all new risk management strategies through a formal process. With the partial exception of the controlled trading program, our

approved strategies are intended to mitigate enterprise level risks that are inherent in our core businesses of gathering and marketing and storage.

Although the intent of our risk-management strategies is to hedge our margin, not all of our derivatives qualify for hedge accounting. In such instances, changes in the fair values of these derivatives will receive mark-to-market treatment in current earnings, and result in greater potential for earnings volatility than in the past. This accounting treatment is discussed further under Note 2 "Summary of Significant Accounting Policies" of our December 31, 2003 Consolidated Financial Statements.

All of our open commodity price risk derivatives at September 30, 2004 were categorized as non-trading. The fair value of these instruments and the change in fair value that would be expected from a 10 percent price decrease are shown in the table below (in millions):

	Fair Value			Effect of 10% Price Decrease
Crude oil:
Futures contracts	$	29.2		$	(15.5	)
Swaps and options contracts		(16.0	)		(1.2	)
LPG:
Futures contracts		—			—
Swaps and option contracts		(2.6	)		3.6

The fair values of the futures contracts are based on quoted market prices obtained from the NYMEX. The fair value of the swaps and option contracts are estimated based on quoted prices from various sources such as independent reporting services, industry publications and brokers. These quotes are compared to the contract price of the swap, which approximates the gain or loss that would have been realized if the contracts had been closed out at year end. For positions where independent quotations are not available, an estimate is provided, or the prevailing market price at which the positions could be liquidated is used. The assumptions in these estimates as well as the source is maintained by the independent risk control function. All hedge positions offset physical exposures to the cash market; none of these offsetting physical exposures are included in the above table. Price-risk sensitivities were calculated by assuming an across-the-board 10 percent decrease in price regardless of term or historical relationships between the contractual price of the instruments and the underlying commodity price. In the event of an actual 10 percent change in prompt month crude prices, the fair value of our derivative portfolio would typically change less than that shown in the table due to lower volatility in out-month prices.

Interest Rate Risk

We utilize both fixed and variable rate debt, and are exposed to market risk due to the floating interest rates on our credit facilities. Therefore, from time to time we utilize interest rate swaps and collars to hedge interest obligations on specific debt issuances, including anticipated debt issuances. The table below presents principal payments and the related weighted average interest rates by expected maturity dates for variable rate debt outstanding at September 30, 2004. The 7.75% senior notes issued during 2002 and the 5.625% senior notes issued during 2003 and the outstanding Notes issued in 2004 are fixed rate notes and their interest rates are not subject to market risk. Our variable rate debt bears interest at LIBOR, prime or the bankers acceptance plus the applicable margin. The average interest rates presented below are based upon rates in effect at September 30, 2004. The carrying values of the

variable rate instruments in our credit facilities approximate fair value primarily because interest rates fluctuate with prevailing market rates.

	Expected Year of Maturity
	2004			2005		2006			2007			2008		Thereafter			Total
						(in millions)
Liabilities:
Short-term debt—variable rate	$	122.9		$	—	$	—		$	—		$	—	$	—		$	122.9
Average interest rate		2.7	%		—		—			—			—		—			2.7	%
Long-term debt—variable rate	$	—		$	—	$	0.4		$	30.0		$	—	$	10.0		$	40.4
Average interest rate		—			—		6.5	%		4.7	%		—		2.8	%		4.3	%

Currency Exchange Rate Risk Hedging

Our cash flow stream relating to our Canadian operations is based on the U.S. dollar equivalent of such amounts measured in Canadian dollars. Assets and liabilities of our Canadian subsidiaries are translated to U.S. dollars using the applicable exchange rate as of the end of a reporting period. Revenues, expenses and cash flow are translated using the average exchange rate during the reporting period.

Because a significant portion of our Canadian business is conducted in Canadian dollars, we use certain financial instruments to minimize the risks of changes in the exchange rate. These instruments include forward exchange contracts and cross currency swaps. The forward exchange contracts qualify for hedge accounting as cash flow hedges and the cross currency swaps qualify for hedge accounting as fair value hedges, both in accordance with SFAS 133.

At September 30, 2004, we had forward exchange contracts that allow us to exchange Canadian dollars for U.S. dollars, quarterly, at set exchange rates as detailed below:

	Canadian Dollars		US Dollars		Rate
	($ in millions)
2004	$	5.0	$	3.8	1.32 to 1
2005	$	3.0	$	2.3	1.33 to 1
2006	$	2.0	$	1.5	1.32 to 1

In addition, at September 30, 2004, we also had cross currency swap contracts for an aggregate notional principal amount of $21.0 million effectively converting this amount of our U.S. dollar denominated debt to $32.5 million of Canadian dollar debt (based on Canadian dollar to U.S. dollar exchange rate of 1.55 to 1). The notional principal amount reduces by $2.0 million U.S. in May 2005 and has a final maturity in May 2006 ($19.0 million U.S.). At September 30, 2004, $6.2 million of our long-term debt was denominated in Canadian dollars ($7.8 million Canadian based on a Canadian dollar to U.S. dollar exchange rate of 1.26 to 1). All of these financial instruments are placed with what we believe to be large, creditworthy financial institutions.

We estimate the fair value of these instruments based on current termination values. The table shown below summarizes the fair value of our foreign currency hedges by year of maturity (in millions):

	Year of Maturity
	2004			2005			2006			2007		Total
Forward exchange contracts	$	(0.1	)	$	(0.4	)	$	(0.2	)	$	—	$	(0.7	)
Cross currency swaps		(0.1	)		(0.8	)		(4.1	)		—		(5.0	)

Total	$	(0.2	)	$	(1.2	)	$	(4.3	)	$	—	$	(5.7	)

BUSINESS

General

We are a publicly traded Delaware limited partnership, formed in 1998 and 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 natural gas related petroleum products. We refer to liquefied petroleum gas and other petroleum products collectively as "LPG." We have an extensive network of pipeline transportation, storage and gathering assets in key oil producing basins and at major market hubs in the United States and Canada. Our operations can be categorized into two primary business activities:

•

Crude Oil Pipeline Transportation Operations. As of September 30, 2004, we owned approximately 15,000 miles of gathering and mainline crude oil pipelines located throughout the United States and Canada; of which approximately 13,100 miles are included in our pipeline segment. Our activities from pipeline operations generally consist of transporting crude oil for a fee, third party leases of pipeline capacity, barrel exchanges and buy/sell arrangements.

•

Gathering, Marketing, Terminalling and Storage Operations. As of September 30, 2004, we owned approximately 37 million barrels of above ground crude oil terminalling and storage facilities, including approximately 23.4 million barrels of tankage that are associated with pipeline operations within our pipeline segment. These facilities include a crude oil terminalling and storage facility at Cushing, Oklahoma. Cushing, which we refer to in this report as the Cushing Interchange, is one of the largest crude oil market hubs in the United States and the designated delivery point for NYMEX crude oil futures contracts. We utilize our storage tanks to counter cyclically balance our gathering and marketing operations and to execute various hedging strategies to stabilize profits and reduce the negative impact of crude oil market volatility. Our terminalling and storage operations also generate revenue at the Cushing Interchange and our other locations through a combination of storage and throughput charges to third parties. We also own approximately 72 million gallons of LPG storage. Our gathering and marketing operations include:

•: the purchase of crude oil at the wellhead and the bulk purchase of crude oil at pipeline and terminal facilities;
•: the transportation of crude oil on trucks, barges and pipelines;
•: the subsequent resale or exchange of crude oil at various points along the crude oil distribution chain; and
•: the purchase of liquified petroleum gas and other petroleum products from producers, refiners and other marketers, and the sale of LPG to wholesalers, retailers and industrial end users.

Business Strategy

We intend to execute our business strategy by:

•: increasing and optimizing throughput on our existing pipeline and gathering assets and realizing cost efficiencies through operational improvements;

•: utilizing and expanding our Cushing Terminal and our other assets to service the needs of refiners and to profit from merchant activities that take advantage of crude oil pricing and quality differentials;
•: selectively pursuing strategic and accretive acquisitions of crude oil transportation assets, including pipelines, gathering systems, terminalling and storage facilities and other assets that complement our existing asset base and distribution capabilities;
•: optimizing and expanding our Canadian operations and our presence in the Gulf Coast and Gulf of Mexico to take advantage of anticipated increases in the volume and qualities of crude oil produced in these areas; and
•: prudently and economically leveraging our asset base, knowledge base and skill sets to participate in energy businesses that are closely related to, or significantly intertwined with the crude oil business.

To a lesser degree, we also engage in a similar business strategy with respect to the wholesale marketing and storage of LPG. Since commencing LPG activities in mid-2001, the portion of our Gathering, Marketing, Terminalling and Storage Operations segment profit associated with those activities has increased from $4.2 million in 2001 to $10.0 million in 2002 and $11.6 million in 2003. The segment profit for 2001 reflects results from July 1 through December 31.

Financial Strategy

Targeted Credit Profile

We believe that a major factor in our continued success will be our ability to maintain a competitive cost of capital and access to the capital markets. Since our initial public offering in 1998, we have consistently communicated to the financial community our intention to maintain a strong credit profile that we believe is consistent with an investment grade credit rating. We have targeted a general credit profile with the following attributes:

•: an average long-term debt-to-total capitalization ratio of approximately 55% or less;
•: an average long-term debt-to-EBITDA ratio of approximately 3.5x or less (EBITDA is earnings before interest, taxes, depreciation and amortization); and
•: an average EBITDA-to-interest coverage ratio of approximately 3.3x or better.

Based on our third quarter 2004 results, we were within our targeted credit profile. In order for us to maintain our targeted credit profile and achieve growth through acquisitions, we intend to fund acquisitions using approximately equal proportions of equity and debt. In certain cases, acquisitions will initially be financed using debt since it is difficult to predict the actual timing of accessing the market to raise equity. Accordingly, from time to time we may be outside the parameters of our targeted credit profile.

Credit Rating

As of November 30, 2004, our senior unsecured rating with Standard & Poors and Moody's Investment Services was BBB-stable and Baa3 stable, both of which are considered investment grade. We cannot assure you that these ratings will remain in effect for any given period of time or that one or both of these ratings will not be lowered or withdrawn entirely by a rating agency. You should note that a credit rating is not a recommendation to buy, sell or hold securities, and may be revised or withdrawn at any time.

Competitive Strengths

We believe that the following competitive strengths position us to successfully execute our principal business strategy:

•: Our pipeline assets are strategically located and have additional capacity. Our primary crude oil pipeline transportation and gathering assets are located in well-established oil producing regions and are connected, directly or indirectly, with our terminalling and storage assets that service major North American refinery and distribution markets where we have strong business relationships. In many instances, these assets are strategically positioned to maximize the value of our crude oil by transporting it to major trading locations and premium markets. Certain of our pipeline networks currently possess additional capacity that can accommodate increased demand without significant additional capital investment.
•: Our Cushing Terminal is strategically located, operationally flexible and readily expandable. Our Cushing Terminal interconnects with the Cushing Interchange's major inbound and outbound pipelines, providing access to both foreign and domestic crude oil. Our Cushing Terminal is the most modern large scale terminalling and storage facility at the Cushing Interchange, incorporating operational enhancements designed to safely and efficiently terminal, store, blend and segregate large volumes and multiple varieties of crude oil as well as extensive environmental safeguards. Since becoming operational in late 1993, we have completed four separate expansion phases, increasing the Cushing terminal's tankage to 6.3 million barrels. We believe that the facility can be further expanded to meet additional demand should market conditions warrant. In addition, we own approximately 31 million barrels of above ground crude oil terminalling and storage assets elsewhere in the United States and Canada that complement our Cushing Terminal and enable us to serve the needs of our customers.
•: We possess specialized crude oil market knowledge. We believe our business relationships with participants in all phases of the crude oil distribution chain, from crude oil producers to refiners, as well as our own industry expertise, provide us with an extensive understanding of the North American physical crude oil markets.
•: Our business activities are counter cyclically balanced. We believe that our terminalling and storage activities and our gathering and marketing activities are counter cyclical. We believe that this balance of activities, combined with our pipeline transportation operations, has a stabilizing effect on our cash flow from operations.
•: We have the financial flexibility to continue to pursue expansion and acquisition opportunities. We believe we have significant resources to finance strategic expansion and acquisition opportunities, including our ability to issue additional partnership units, to borrow under our credit facilities and to issue additional notes in the long-term debt capital markets. As of November 30, 2004, we had approximately $495.8 million available under our committed credit facilities. Our usage is subject to covenant compliance.
•: We have an experienced management team whose interests are aligned with those of our unitholders. Our executive management team has an average of more than 20 years industry experience, with an average of over 15 years with us or our predecessors and affiliates. Members of our senior management team own a 4% interest in our general partner, and through phantom unit grants and options, own significant contingent equity incentives that generally vest only if we achieve specified performance objectives. A significant portion of the restricted unit grants under our Long Term Incentive Plan ("LTIP") have vested in 2004. In addition, our senior management team collectively owns approximately 650,000 common units.

Recent Developments

Unitholder Meeting

On December 7, 2004, we filed a proxy statement to call a special meeting of our unitholders. At the meeting, our unitholders will consider and vote on the following matters:

•: A proposal to approve (a) a change in the terms of our Class B common units to provide that each Class B common unit is convertible into one of our common units and (b) the issuance of additional common units upon such conversion (the "Class B Listing Proposal");
•: A proposal to approve (a) a change in the terms of our Class C common units to provide that each Class C common unit is convertible into one of our common units and (b) the issuance of additional common units upon such conversion (the "Class C Listing Proposal");
•: A proposal to approve the terms of our 2005 Long-Term Incentive Plan (the "2005 LTIP"), which provides for awards of common units, options to purchase common units and other rights to our employees, officers and directors (the "2005 LTIP Proposal"); and
•: Any proposal to adjourn the special meeting to a later date, if necessary, to solicit additional proxies if there are not sufficient votes in favor of the foregoing proposals.

Our board of directors unanimously recommended that the common unitholders approve the Class B Listing Proposal, the Class C Listing Proposal and the 2005 LTIP Proposal. Pursuant to our partnership agreement, if the approval of our common unitholders is not obtained within 120 days of the request, the holders of the Class B common units and the Class C common units (unless and until converted into common units) will be entitled to receive distributions, on a per unit basis, equal to 110% of the amount of distributions paid on a common unit. If the approval of our common unitholders is not secured within 90 days after the end of the 120-day period, the distribution right increases to 115%. If the approval of our common unitholders is not obtained for the 2005 LTIP Proposal, we will not be able to award any grants under the 2005 LTIP. See "Certain Relationships and Related Transactions—Transactions with Related Parties—Class B Common Units" and "Certain Relationships and Related Transactions—Transactions with Related Parties—Class C Common Units" for a discussion of the Class B and Class C common units.

Board of Directors

On July 23, 2004, in connection with the acquisition of Plains Resources Inc. by Vulcan Energy Corporation, Plains All American GP LLC (the general partner of our general partner Plains AAP, L.P.), amended its limited liability company agreement to expand its board of directors from seven members to eight. As amended, the limited liability company agreement provides that the mechanism for determining the constituency of the board remains the same except that three independent directors, rather than two, are elected by majority vote of the owners of Plains All American GP LLC. Mr. J. Taft Symonds, the previous designee of Plains Holdings Inc., was elected as an independent director by majority vote of the members of Plains All American GP LLC to fill the vacancy created by the expansion of the board.

On July 26, 2004, Plains Holdings Inc. (a wholly owned subsidiary of Plains Resources Inc.) designated Mr. David N. Capobianco as one of our directors. Mr. Capobianco is a member of the board of Vulcan Energy Corporation and a managing director of Vulcan Capital, an affiliate of Vulcan Inc.

Distribution Payment

On November 12, 2004, we paid a cash distribution of $0.60 per unit on our outstanding common units, Class B common units and Class C common units. The total distribution paid was approximately

$43.9 million, with approximately $40.4 million paid to our common unitholders and approximately $3.5 million paid to our general partner for its general partner ($0.8 million) and incentive distribution interests ($2.7 million).

Common Unit Offering

During the third quarter of 2004, we completed a public offering of 4,968,000 common units. The net proceeds from the offering, including our general partner's proportionate capital contribution and expenses associated with the offering, were approximately $160.9 million. We used the net proceeds to pay down outstanding indebtedness and reduce the commitment level under our $200 million, 364-day credit facility.

Debt Offering

Credit Facility

LTIP Vesting

From January 1, 2004 through September 30, 2004, we have issued approximately 363,000 common units in satisfaction of the vesting of phantom units under our Long-Term Incentive Plan.

Other Acquisition Activities

Since 1998, including our recent Schaefferstown acquisition, we have completed numerous acquisitions for an aggregate purchase price of approximately $1.9 billion. Consistent with our business strategy, we are continuously engaged in discussions with potential sellers regarding the possible purchase by us of assets and operations that are strategic and complementary to our existing operations. Such assets and operations include crude oil related assets and LPG assets, as well as energy assets that are closely related to, or intertwined with, these business lines, and enable us to leverage our asset base, knowledge base and skill sets. Such acquisition efforts involve participation by us in processes that have been made public, involve a number of potential buyers and are commonly referred to as "auction" processes, as well as situations in which we believe we are the only party or one of a very limited number of potential buyers in negotiations with the potential seller. These acquisition efforts often involve assets which, if acquired, would have a material effect on our financial condition and results of operations.

Organizational History

We were formed in September 1998 as a separate, publicly traded master limited partnership, to acquire and operate the midstream crude oil business and assets of Plains Resources Inc. and its wholly

owned subsidiaries. We completed our initial public offering in November 1998. Unless the context otherwise requires, we refer to Plains Resources Inc. and its wholly owned subsidiaries as Plains Resources. As a result of subsequent equity offerings and the purchase in 2001 by senior management and a group of financial investors of majority control of our general partner and a portion of the limited partner units held by Plains Resources, Plains Resources' overall effective ownership in us was reduced to approximately 18.9% as of September 30, 2004. See "Security Ownership of Certain Beneficial Owners and Management and Related Unitholders' Matters."

Since June 2001, our 2% general partner interest has been held by Plains AAP, L.P., a Delaware limited partnership. Plains All American GP LLC, a Delaware limited liability company, is Plains AAP, L.P.'s general partner. Unless the context otherwise requires, we use the term "general partner" to refer to both Plains AAP, L.P. and Plains All American GP LLC. Plains AAP, L.P. and Plains All American GP LLC are essentially held by seven owners with the largest interest, 44%, held by Plains Resources. We use the phrase "former general partner" to refer to the subsidiary of Plains Resources that formerly held the general partner interest.

Partnership Structure and Management

Our operations are conducted through, and our operating assets are owned by, our subsidiaries. We own our interests in our subsidiaries through two operating partnerships, Plains Marketing, L.P. and Plains Pipeline, L.P. Our Canadian operations are conducted through Plains Marketing Canada, L.P.

Our general partner, Plains AAP, L.P., is a limited partnership. Our general partner is managed by its general partner, Plains All American GP LLC, which has ultimate responsibility for conducting our business and managing our operations. References to our general partner, unless the context otherwise requires, include Plains All American GP LLC. Our general partner does not receive any management fee or other compensation in connection with its management of our business, but it is reimbursed for all direct and indirect expenses incurred on our behalf.

The chart on the next page depicts the current structure and ownership of Plains All American Pipeline, L.P. and certain subsidiaries.

Acquisitions and Dispositions

An integral component of our business strategy and growth objective is to acquire assets and operations that are strategic and complementary to our existing operations. Such assets and operations include crude oil related assets and LPG assets, as well as energy assets that are closely related to, or intertwined with, these business lines, and enable us to leverage our asset base, knowledge base and skill sets. We have established a target to complete, on average, $200 million to $300 million in acquisitions per year, subject to availability of attractive assets on acceptable terms. Since 1998, we have completed numerous acquisitions for an aggregate purchase price of approximately $1.9 billion. In addition, from time to time we have sold assets that are no longer considered essential to our operations.

Following is a brief description of selected acquisitions completed to date in 2004 and in 2003, and major acquisitions and dispositions that have occurred since our initial public offering in November 1998.

Link Energy LLC

On April 1, 2004, we completed the acquisition of all of the North American crude oil and pipeline operations of Link for approximately $332 million, including $268 million of cash (net of approximately $5.5 million subsequently returned to PAA from an indemnity escrow account) and approximately $64 million of net liabilities assumed and acquisition related costs. The Link crude oil business consists of approximately 7,000 miles of active crude oil pipeline and gathering systems, over 10 million barrels of crude oil storage capacity, a fleet of approximately 200 owned or leased trucks and approximately 2 million barrels of crude oil linefill and working inventory. The Link assets complement our assets in West Texas and along the Gulf Coast and allow us to expand our presence in the Rocky Mountain and Oklahoma/Kansas regions. The results of operations and assets from this acquisition (the "Link acquisition") have been included in our consolidated financial statements and both our pipeline operations and gathering, marketing, terminalling and storage operations segments since April 1, 2004.

Cal Ven Pipeline System

On May 7, 2004 we completed the acquisition of the Cal Ven Pipeline System from Cal Ven Limited, a subsidiary of Unocal Canada Limited. The total purchase price was approximately $19 million, including transaction costs. The Cal Ven Pipeline System includes approximately 195 miles of 8-inch and 10-inch gathering and mainline crude oil pipelines. The system is located in northern Alberta and delivers crude oil into the Rainbow Pipeline System. The Rainbow Pipeline System then transports the crude south to the Edmonton market, where it can be used in local refineries or shipped on connecting pipelines to the U.S. market. The results of operations and assets from this acquisition have been included in our consolidated financial statements and our pipeline operations segment since May 1, 2004.

Capline and Capwood Pipeline System

In March 2004, we completed the acquisition of all of Shell Pipeline Company LP's ("SPLC") interests in two entities for approximately $158.0 million in cash (including a $15.8 million deposit paid in December 2003) and approximately $0.5 million of transaction and other costs. The principal assets of the entities are: (i) an approximate 22% undivided joint interest in the Capline Pipe Line System, and (ii) an approximate 76% undivided joint interest in the Capwood Pipeline System. The Capline Pipeline System is a 633-mile, 40-inch mainline crude oil pipeline originating in St. James, Louisiana, and terminating in Patoka, Illinois. The Capline system is one of the primary transportation routes for crude oil shipped into the Midwestern U.S., accessing over 2.7 million barrels of refining capacity in PADD II, including refineries owned by ConocoPhillips, ExxonMobil, BP, MarathonAshland, CITGO and Premcor. Capline has direct connections to a significant amount of sweet and light sour crude production in the Gulf of Mexico. In addition, with its two active docks capable of handling 600,000-barrel tankers as well as access to LOOP, the Louisiana Offshore Oil Port, the Capline System is a key transporter of sweet and light sour foreign crude to PADD II. With a total system operating capacity of 1.14 million barrels per day, approximately 248,000 barrels per day are subject to the interest acquired. During 2003, throughput on the interest we acquired averaged approximately 125,000 barrels per day.

The Capwood Pipeline System is a 57-mile, 20-inch mainline crude oil pipeline originating in Patoka, Illinois, and terminating in Wood River, Illinois. The Capwood system has an operating capacity of 277,000 barrels per day of crude oil. Of that capacity, approximately 211,000 barrels per day are subject to the interest acquired. The Capwood System has the ability to deliver crude at Wood

River to several other PADD II refineries and pipelines, including those owned by Koch and ConocoPhillips. Movements on the Capwood system are driven by the volumes shipped on Capline as well as Canadian crude that can be delivered to Patoka via the Mustang Pipeline. Since closing, we have assumed the operatorship of the Capwood system from SPLC.

South Saskatchewan Pipeline System

In November 2003, we completed the acquisition of the South Saskatchewan Pipeline System from South Saskatchewan Pipe Line Company. The South Saskatchewan Pipeline System originates approximately 75 miles southwest of Swift Current, Saskatchewan, and traverses north and east until it reaches its terminus at Regina, Saskatchewan. The system consists of a 158-mile, 16-inch mainline and 203 miles of gathering lines ranging in diameter from three to twelve inches. In 2002, the system transported approximately 52,000 barrels of crude oil per day. During the period of 2003 that we owned the system, it transported approximately 52,000 barrels of crude oil per day. For the nine months ended September 30, 2004, the system transported approximately 48,000 barrels of crude oil per day. At Regina, the system can deliver crude oil to the Enbridge Pipeline System, as well as to local markets, and through the Enbridge connection crude can be delivered into our Wascana Pipeline System. Total purchase price for these assets was approximately $48 million, including transaction costs.

ArkLaTex Pipeline System

In October 2003, we completed the acquisition of the ArkLaTex Pipeline System from Link Energy (formerly EOTT Energy). The ArkLaTex Pipeline System consists of 240 miles of active crude oil gathering and mainline pipelines and connects to our Red River Pipeline System near Sabine, Texas. Also included in the transaction were 470,000 barrels of active crude oil storage capacity, the assignment of certain of Link Energy's crude oil supply contracts and crude oil linefill and working inventory comprising approximately 108,000 barrels. The total purchase price for these assets of approximately $21.3 million included approximately $14.0 million of cash paid to Link Energy for the pipeline system, approximately $2.9 million of cash paid to Link Energy to purchase crude oil linefill and working inventory, approximately $3.6 million for estimated near-term capital costs and transaction costs and approximately $0.8 million associated with the satisfaction of outstanding claims for accounts receivable and inventory balances.

Iraan to Midland Pipeline System

In June 2003, we acquired the Iraan to Midland Pipeline System from a unit of Marathon Ashland Petroleum LLC ("MAP") for aggregate consideration of approximately $17.6 million. The Iraan to Midland Pipeline System is a 16-inch, 98-mile mainline crude oil pipeline that originates in Iraan, Texas and terminates in Midland, Texas. At Midland, the system has the ability to deliver crude oil to our Basin Pipeline System and to the Mesa Pipeline System. The Iraan to Midland Pipeline System transported approximately 22,000 barrels per day of crude oil in the first nine months of 2004. The results of operations and assets of the Iraan to Midland Pipeline System have been included in our consolidated financial statements and our pipeline operations since June 30, 2003. The aggregate purchase price included $13.6 million in cash, approximately $3.6 million associated with the satisfaction of outstanding claims for accounts receivable and inventory balances, and approximately $0.4 million of estimated transaction costs.

South Louisiana Assets

In June 2003, we completed the acquisition of terminalling and gathering assets from El Paso Corporation for approximately $13.4 million, including transaction costs. These assets are located in southern Louisiana and include various interests in five pipelines and gathering systems and two terminal facilities. These assets complement our existing activities in south Louisiana and we believe

will help leverage our exposure to the growing volume of crude oil and condensate production from the Gulf of Mexico. The results of operations and assets from this acquisition have been included in our consolidated financial statements and in our pipeline operations segment since June 1, 2003. The assets acquired in this acquisition include a 33¹/3% interest in Atchafalaya Pipeline, L.L.C. In December 2003, we acquired the remaining 66²/3% interests in two separate transactions totaling $4.4 million.

Iatan Gathering System

In March 2003, we completed the acquisition of a West Texas crude oil gathering system from Navajo Refining Company, L.P. for approximately $24.3 million, including transaction costs. The assets are located in the Permian Basin in West Texas and consist of approximately 360 miles of active crude oil gathering lines. The results of operations and assets from this acquisition have been included in our consolidated financial statements and in our pipeline operations segment since March 1, 2003.

Red River Pipeline System

In February 2003, we completed the acquisition of a 334-mile crude oil pipeline from BP Pipelines (North America) Inc. for approximately $19.4 million, including transaction costs. The system originates at Sabine in East Texas and terminates near Cushing, Oklahoma. Subsequent to the acquisition, we connected the pipeline system to our Cushing Terminal. The system also includes approximately 645,000 barrels of crude oil storage capacity. The results of operations and assets from this acquisition have been included in our consolidated financial statements and in our pipeline operations segment since February 1, 2003. This pipeline complements our existing assets in East Texas.

Shell West Texas Assets

On August 1, 2002, we acquired interests in approximately 2,000 miles of gathering and mainline crude oil pipelines and approximately 9.0 million barrels (net to our interest) of above ground crude oil terminalling and storage assets in West Texas from Shell Pipeline Company LP and Equilon Enterprises LLC (the "Shell acquisition"). The primary assets included in the transaction are interests in the Basin Pipeline System ("Basin System"), the Permian Basin Gathering System ("Permian Basin System") and the Rancho Pipeline System ("Rancho System"). The total purchase price of $324.4 million consisted of (i) $304.0 million in cash, (ii) approximately $9.1 million related to the settlement of pre-existing accounts receivable and inventory balances and (iii) approximately $11.3 million of estimated transaction and closing costs.

The acquired assets are primarily fee-based mainline crude oil pipeline transportation assets that gather crude oil in the Permian Basin and transport that crude oil to major market locations in the Mid-Continent and Gulf Coast regions. The acquired assets complement our existing asset infrastructure in West Texas and represent a transportation link to Cushing, Oklahoma, where we provide storage and terminalling services. In addition, we believe that the Basin system is poised to benefit from potential shut-downs of refineries and other pipelines due to the shifting market dynamics in the West Texas area. As was contemplated at the time of the acquisition, the Rancho system was taken out of service in March 2003, pursuant to the terms of its operating agreement. See "—Shutdown and Sale of Rancho Pipeline System."

Canadian Expansion

In 2001, we consummated the two transactions that enabled us to establish a presence in Canada to complement our operations in the United States. The combination of these assets, an established fee-based pipeline transportation business and a rapidly growing, entrepreneurial gathering and marketing business, allowed us to optimize both businesses and establish a solid foundation for future growth in Canada.

CANPET Energy Group, Inc. In July 2001, we purchased substantially all of the assets of CANPET Energy Group Inc., a Calgary based Canadian crude oil and LPG marketing company, for approximately $24.6 million plus $25.0 million for additional inventory owned by CANPET. In December 2003 we recorded an additional $24.3 million related to a portion of the purchase price that had previously been deferred subject to various performance standards of the business acquired. See Note 7 "Partners' Capital and Distributions" in the December 31, 2003 "Notes to the Consolidated Financial Statements." The principal assets acquired included a crude oil handling facility, a 130,000-barrel tank facility, LPG facilities, existing business relationships and operating inventory.

Murphy Oil Company Ltd. Midstream Operations. In May 2001, we completed the acquisition of substantially all of the Canadian crude oil pipeline, gathering, storage and terminalling assets of Murphy Oil Company Ltd. for approximately $158.4 million in cash (after post-closing adjustments), including financing and transaction costs. The purchase price included $6.5 million for excess inventory in the systems. The principal assets acquired include (i) approximately 560 miles of crude oil and condensate mainlines (including dual lines on which condensate is shipped for blending purposes and blended crude is shipped in the opposite direction) and associated gathering and lateral lines, (ii) approximately 1.1 million barrels of crude oil storage and terminalling capacity located primarily in Kerrobert, Saskatchewan, (iii) approximately 254,000 barrels of pipeline linefill and tank inventories, and (iv) 121 trailers used primarily for crude oil transportation.

West Texas Gathering System

In July 1999, we completed the acquisition of the West Texas Gathering System from Chevron Pipe Line Company for approximately $36.0 million, including transaction costs. The assets acquired include approximately 420 miles of crude oil mainlines, approximately 295 miles of associated gathering and lateral lines, and approximately 2.7 million barrels of tankage located along the system.

Scurlock Permian

In May 1999, we completed the acquisition of Scurlock Permian LLC ("Scurlock") and certain other pipeline assets from Marathon Ashland Petroleum LLC. Including working capital adjustments and closing and financing costs, the cash purchase price was approximately $141.7 million.

Scurlock, previously a wholly owned subsidiary of Marathon Ashland Petroleum, was engaged in crude oil transportation, gathering and marketing. The assets acquired included approximately 2,300 miles of active pipelines, numerous storage terminals and a fleet of trucks. The largest asset consists of an approximately 954-mile pipeline and gathering system located in the Spraberry Trend in West Texas that extends into Andrews, Glasscock, Martin, Midland, Regan and Upton Counties, Texas. The assets we acquired also included approximately one million barrels of crude oil linefill.

Ongoing Acquisition Activities

Consistent with our business strategy, we are continuously engaged in discussions with potential sellers regarding the possible purchase by us of assets and operations that are strategic and complimentary to our existing operations. Such assets and operations include crude oil related assets and LPG assets, as well as energy assets that are closely related to, or intertwined with, these business lines, and enable us to leverage our asset base, knowledge base and skill sets. Such acquisition efforts involve participation by us in processes that have been made public, involve a number of potential buyers and are commonly referred to as "auction" processes, as well as situations where we believe we are the only party or one of a very limited number of potential buyers in negotiations with the potential seller. These acquisition efforts often involve assets which, if acquired, would have a material effect on our financial condition and results of operations.

In connection with our acquisition activities, we routinely incur third party costs, which are capitalized and deferred pending final outcome of the transaction. Deferred costs associated with successful transactions are capitalized as part of the transaction, while deferred costs associated with unsuccessful transactions are expensed at the time of such final determination. We had a total of approximately $0.2 million in deferred costs at September 30, 2004. We can give no assurance that our current or future acquisition efforts will be successful or that any such acquisition will be completed on terms considered favorable to us.

Shutdown and Sale of Rancho Pipeline System

We acquired an interest in the Rancho Pipeline System from Shell in August 2002. The Rancho Pipeline System Agreement dated November 1, 1951, pursuant to which the system was constructed and operated, would terminate in March 2003. Upon termination, the agreement required the owners to take the pipeline system, in which we owned an approximate 50% interest, out of service. Accordingly, we notified our shippers and did not accept nominations for movements after February 28, 2003. This shutdown was contemplated at the time of the acquisition and was accounted for under purchase accounting in accordance with SFAS No. 141 "Business Combinations." The pipeline was shut down on March 1, 2003 and a purge of the crude oil linefill was completed in April 2003. In June 2003, we completed transactions whereby we transferred our ownership interest in approximately 241 miles of the total 458 miles of the pipeline in exchange for $4.0 million and approximately 500,000 barrels of crude oil tankage in West Texas. In August 2004, we sold our interest in the remaining portion of the system to Kinder Morgan Texas Pipeline, L.P. for approximately $0.9 million, including the assumption of all liabilities typically associated with pipelines of this type. We recognized a gain of approximately $0.6 million on this transaction.

All American Pipeline Linefill Sale and Asset Disposition

In March 2000, we sold the segment of the All American Pipeline that extends from Emidio, California to McCamey, Texas to a unit of El Paso Corporation for $129.0 million. Except for minor third party volumes, one of our subsidiaries, Plains Marketing, L.P., was the sole shipper on this segment of the pipeline since its predecessor acquired the line from the Goodyear Tire & Rubber Company in July 1998. We realized net proceeds of approximately $124.0 million after the associated transaction costs and estimated costs to remove equipment. We used the proceeds from the sale to reduce outstanding debt. We recognized a gain of approximately $20.1 million in connection with the sale.

We had suspended shipments of crude oil on this segment of the pipeline in November 1999. At that time, we owned approximately 5.2 million barrels of crude oil in the segment of the pipeline. We sold this crude oil from November 1999 to February 2000 for net proceeds of approximately $100.0 million, which were used for working capital purposes. We recognized an aggregate gain of approximately $44.6 million, of which approximately $28.1 million was recognized in 2000 in connection with the sale of the linefill.

Description of Segments and Associated Assets

Our business activities are conducted through two primary segments, Pipeline Operations and Gathering, Marketing, Terminalling and Storage Operations. Our operations are conducted in approximately 40 states in the United States and six provinces in Canada. The majority of our operations are conducted in Texas, Oklahoma, California, Kansas and Louisiana and in the Canadian provinces of Alberta and Saskatchewan.

Following is a description of the activities and assets for each of our business segments:

Pipeline Operations

As of September 30, 2004, we owned approximately 15,000 miles of gathering and mainline crude oil pipelines located throughout the United States and Canada, of which approximately 13,100 miles are included in our pipeline segment. Our activities from pipeline operations generally consist of transporting crude oil for a fee and third party leases of pipeline capacity, as well as barrel exchanges and buy/sell arrangements.

Substantially all of our pipeline systems are controlled or monitored from one of two central control rooms with computer systems designed to continuously monitor real-time operational data, including measurement of crude oil quantities injected into and delivered through the pipelines, product flow rates, and pressure and temperature variations. The systems are designed to enhance leak detection capabilities, sound automatic alarms in the event of operational conditions outside of pre-established parameters and provide for remote controlled shut-down of pump stations on the pipeline systems. Pump stations, storage facilities and meter measurement points along the pipeline systems are linked by telephone, satellite, radio or a combination thereof to provide communications for remote monitoring and in some instances control, which reduces our requirement for full-time site personnel at most of these locations.

We perform scheduled maintenance on all of our pipeline systems and make repairs and replacements when necessary or appropriate. We attempt to control corrosion of the mainlines through the use of cathodic protection, corrosion inhibiting chemicals injected into the crude stream and other protection systems typically used in the industry. Maintenance facilities containing equipment for pipe repairs, spare parts and trained response personnel are strategically located along the pipelines and in concentrated operating areas. We believe that all of our pipelines have been constructed and are maintained in all material respects in accordance with applicable federal, state, provincial and local laws and regulations, standards prescribed by the American Petroleum Institute, Canadian Standards Association and accepted industry practice. See "—Regulation—Pipeline and Storage Regulation."

Following is a description of our major pipeline assets in the United States and Canada, grouped by geographic location:

Southwest U.S.

Basin Pipeline System. We acquired an approximate 87% undivided joint interest in the Basin System in the Shell acquisition. The Basin System is a 515-mile mainline, telescoping crude oil system with a capacity ranging from approximately 144,000 barrels per day to 394,000 barrels per day depending on the segment. System throughput (as measured by system deliveries) was approximately 275,000 barrels per day (net to our interest) during the first nine months of 2004. The Basin System consists of three primary movements of crude oil: (i) barrels are shipped from Jal, New Mexico to the West Texas markets of Wink and Midland, where they are exchanged and/or further shipped to refining centers; (ii) barrels are shipped to the Mid-Continent region on the Midland to Wichita Falls segment and the Wichita Falls to Cushing segment; and (iii) foreign and Gulf of Mexico barrels are delivered into Basin at Wichita Falls and delivered to a connecting carrier or shipped to Cushing for further distribution to Mid-Continent or Midwest refineries. The size of the pipe ranges from 20 to 24 inches in diameter. The Basin system also includes approximately 5.8 million barrels (5.0 million barrels, net to our interest) of crude oil storage capacity located along the system. TEPPCO Partners, L.P. owns the remaining approximately 13% interest in the system. In 2004, we expanded a 424-mile section of the system extending from Midland, Texas to Cushing, Oklahoma. With the completion of this expansion, the capacity of this section has increased approximately 15%, from 350,000 barrels per day to approximately 400,000 barrels per day. The Basin system is subject to tariff rates regulated by the

Federal Energy Regulatory Commission (the "FERC"). See "—Regulation—Transportation Regulation."

West Texas Gathering System. The West Texas Gathering System is a common carrier crude oil pipeline system located in the heart of the Permian Basin producing area, and includes approximately 420 miles of crude oil mainlines and approximately 295 miles of associated gathering and lateral lines. The West Texas Gathering System has the capability to transport approximately 190,000 barrels per day. Total system volumes were approximately 81,000 barrels per day in the first nine months of 2004. Chevron USA has agreed to transport its equity crude oil production from fields connected to the West Texas Gathering System on the system through July 2011 (representing approximately 18,000 barrels per day, or 21% of the total system volumes during 2003). The system also includes approximately 2.7 million barrels of crude oil storage capacity, located primarily in Monahans, Midland, Wink and Crane, Texas.

Permian Basin Gathering System. The Permian Basin System, acquired in the Shell acquisition, includes several gathering systems and trunk lines with connecting injection stations and storage facilities. In total, the system consists of 919 miles of pipe and primarily transports crude oil from wells in the Permian Basin to the Basin System. The Permian Basin System gathered approximately 49,000 barrels per day in the first nine months of 2004. The Permian Basin System includes approximately 3.9 million barrels of crude oil storage capacity.

Spraberry Pipeline System. The Spraberry Pipeline System, acquired in the Scurlock acquisition, gathers crude oil from the Spraberry Trend of West Texas and transports it to Midland, Texas, where it interconnects with the West Texas Gathering System and other pipelines. The Spraberry Pipeline System consists of approximately 954 miles of pipe of varying diameter, and has a throughput capacity of approximately 50,000 barrels of crude oil per day. The Spraberry Trend is one of the largest producing areas in West Texas, and we are one of the largest gatherers in the Spraberry Trend. For the first nine months of 2004, the Spraberry Pipeline System gathered approximately 38,000 barrels per day of crude oil. The Spraberry Pipeline System also includes approximately 659,000 barrels of tank capacity located along the pipeline, including the recent expansion.

Dollarhide Pipeline System. The Dollarhide Pipeline System, acquired from Unocal Pipeline Company in October 2001, is a common carrier pipeline system that is located in West Texas. In the first nine months of 2004, the Dollarhide Pipeline System delivered approximately 6,000 barrels of crude oil per day into the West Texas Gathering System. The system also includes approximately 55,000 barrels of crude oil storage capacity along the system.

Mesa Pipeline System. The Mesa Pipeline System, in which we acquired an 8.8% undivided interest from Unocal Corporation in May 2003, is located in the Permian Basin in West Texas, originating at Midland and terminating at Colorado City, and serves to complement our Basin Pipeline System. We have access to a net capacity of approximately 28,000 barrels of crude oil per day on the system. This system is operated by an affiliate of ChevronTexaco.

Iraan to Midland Pipeline System. The Iraan to Midland Pipeline System, acquired from a unit of Marathon Ashland Petroleum LLC in June 2003, is a 16-inch, 98-mile mainline crude oil pipeline that originates in Iraan, Texas and terminates in Midland, Texas. At Midland, the system has the ability to deliver crude oil to our Basin Pipeline System and to the Mesa Pipeline System. In the first nine months of 2004, deliveries averaged approximately 22,000 barrels per day.

Iatan Gathering System. The Iatan gathering system, acquired from Navajo Refining Company, L.P. in March 2003, is located in the Permian Basin in West Texas and consists of approximately 360 miles of active crude oil gathering lines. During the first nine months of 2004, volumes on this system averaged 22,000 barrels per day.

New Mexico Pipeline System. The New Mexico Pipeline System, included in the April 2004 Link transaction, is an extensive crude oil mainline and gathering system primarily located in Lea and Eddy Counties, New Mexico. The system consists of approximately 1,200 miles of active pipe and approximately 1.3 million barrels of associated storage. The system delivers primarily to the Basin Pipeline System, an Amoco Pipeline System, and the Kaston Pipeline system. For the third quarter of 2004, volumes averaged approximately 66,000 barrels per day.

Texas Pipeline System. The Texas Pipeline System, included in the April 2004 Link transaction, is an extensive crude oil mainline and gathering system delivering crude oil produced in the Permian Basin primarily to Midland, McCamey, and Colorado City, Texas. Also, included in the system is a 10-inch mainline from McCamey, Texas to Healdton, Oklahoma and approximately 2.0 million barrels of storage. For the third quarter of 2004, volumes averaged approximately 109,000 barrels per day.

Western U.S.

All American Pipeline System. The segment of the All American Pipeline that we retained following the sale of the line segment to El Paso is a common carrier crude oil pipeline system that transports crude oil produced from certain outer continental shelf, or OCS, fields offshore California to locations in California. This segment is subject to tariff rates regulated by the FERC.

We own and operate the segment of the system that extends approximately 10 miles along the California coast from Las Flores to Gaviota (24-inch diameter pipe) and continues from Gaviota approximately 126 miles to our station in Emidio, California (30-inch diameter pipe). Between Gaviota and our Emidio Station, the All American Pipeline interconnects with our San Joaquin Valley, or SJV, Gathering System as well as various third party intrastate pipelines, including the Unocap Pipeline System, the Shell Pipeline Company, L.P. and the Pacific Pipeline.

The All American Pipeline currently transports OCS crude oil received at the onshore facilities of the Santa Ynez field at Las Flores and the onshore facilities of the Point Arguello field located at Gaviota. ExxonMobil, which owns all of the Santa Ynez production, and PXP and other producers, which together own approximately 75% of the Point Arguello production, have entered into transportation agreements committing to transport all of their production from these fields on the All American Pipeline. These agreements, which expire in August 2007, provide for a minimum tariff with annual escalations based on specific composite indices. The producers from the Point Arguello field who do not have contracts with us have no other means of transporting their production and, therefore, ship their volumes on the All American Pipeline at the posted tariffs. Volumes attributable to PXP are purchased and sold to a third party under our marketing agreement with PXP before such volumes enter the All American Pipeline. See "Certain Relationships and Related Transactions—Transactions with Related Parties—General." The third party pays the same tariff as required in the transportation agreements. At December 31, 2003, the tariffs averaged $1.71 per barrel. Effective January 1, 2004, based on the contractual escalator, the average tariff increased to $1.81 per barrel. The agreements do not require these owners to transport a minimum volume.

A significant portion of our revenues less direct field operating costs is derived from the pipeline transportation business associated with these two fields. The relative contribution to our revenues less direct field operating costs from these fields has decreased from approximately 23% in 1999 to 17% in 2003, as we have grown and diversified through acquisitions and organic expansions and as a result of declines in volumes produced and transported from these fields, offset somewhat by an increase in pipeline tariffs. Over the last several years, transportation volumes received from the Santa Ynez and Point Arguello fields have declined from 92,000 and 60,000 average daily barrels, respectively, in 1995 to 45,000 and 10,000 average daily barrels, respectively, for the first nine months of 2004. We expect that there will continue to be natural production declines from each of these fields as the underlying reservoirs are depleted. A 5,000 barrel per day decline in volumes shipped from these fields would

result in a decrease in annual pipeline tariff revenues of approximately $3.1 million, based on a tariff of $1.81 per barrel.

In October 2004, PXP announced that it had successfully completed an initial development well into the Rocky Point field which is accessible from the Point Arguello platforms and that drilling operations are underway on a second development well. Such activities are not expected to have a significant impact on pipeline shipments on our All American Pipeline system in 2004. If successful, such incremental drilling activity could lead to increased volumes on our All American Pipeline System in future periods. However, we can give no assurance that our volumes transported would increase as a result of this drilling activity.

The table below sets forth the historical volumes received from both of these fields for the past five years and the nine months ended September 30, 2004:

			Nine Months Ended September 30, 2004	Year Ended December 31,
			Nine Months Ended September 30, 2004	2003	2002	2001	2000	1999
			(barrels in thousands)
Average daily volumes received from:
	Point Arguello (at Gaviota)		10	13	16	18	18	20
	Santa Ynez (at Las Flores)		45	46	50	51	56	59

		Total	55	59	66	69	74	79

SJV Gathering System. The SJV Gathering System is connected to most of the major fields in the San Joaquin Valley. The SJV Gathering System was constructed in 1987 with a design capacity of approximately 140,000 barrels per day. The system consists of a 16-inch pipeline that originates at the Belridge station and extends 45 miles south to a connection with the All American Pipeline at the Pentland station. The SJV Gathering System also includes approximately 730,000 barrels of tank capacity, which can be used to facilitate movements along the system as well as to support our other activities.

The table below sets forth the historical volumes received into the SJV Gathering System for the past five years and the nine months ended September 30, 2004:

	Nine Months Ended September 30, 2004	Year Ended December 31,
	Nine Months Ended September 30, 2004	2003	2002	2001	2000	1999
	(barrels in thousands)
Total average daily volumes	72	78	73	61	60	84

Butte Pipeline System. We own an approximate 22% equity interest in Butte Pipe Line Company, which in turn owns the Butte Pipeline System, a 370-mile mainline system that runs from Baker, Montana to Guernsey, Wyoming. The Butte Pipeline System is connected to the Poplar Pipeline System, which in turn is connected to the Wascana Pipeline System, which is located in our Canadian Region and is wholly owned by us. The total system volumes for the Butte Pipeline System during the first nine months of 2004 were approximately 69,000 barrels of crude oil per day (approximately 15,000 barrels per day, net to our 22% interest). The operator of the system is Bridger Pipeline.

North Dakota Systems. The North Dakota Systems, included in the April 2004 Link acquisition, consist of the Bowman Baker Pipeline System, the Trenton Pipeline System and the North Dakota Gathering System. Aggregate volumes on the systems averaged approximately 52,000 barrels per day for the third quarter of 2004. The Bowman Baker System is a 283 mile, FERC regulated common carrier pipeline system from Harding County, South Dakota to the Butte Pipeline System at Baker, Montana.

The Trenton Pipeline System consists of 116 miles of active pipeline from Richland County, Montana to Williston County, North Dakota delivering crude to Enbridge's Portal Pipeline System. The North Dakota Gathering System consists of approximately 220 miles of active pipeline located in the Williston Basin region of North Dakota. The system delivers primarily to Tesoro pipeline for consumption at Tesoro's Mandan Refinery or to the Little Missouri Pipeline, a feeder of the Butte Pipeline System.

U.S. Gulf Coast

Capline/Capwood Pipeline System. The Capline Pipeline System, in which we acquired a 22% undivided joint interest from Shell in March 2004, is a 633-mile, 40-inch mainline crude oil pipeline originating in St. James, Louisiana, and terminating in Patoka, Illinois. The Capline Pipeline System is one of the primary transportation routes for crude oil shipped into the Midwestern U.S., accessing over 2.7 million barrels of refining capacity in PADD II, including refineries owned by ConocoPhillips, ExxonMobil, BP, MarathonAshland, CITGO and Premcor. Capline has direct connections to a significant amount of sweet and light sour crude production in the Gulf of Mexico. In addition, with its two active docks capable of handling 600,000-barrel tankers as well as access to LOOP, the Louisiana Offshore Oil Port, it is a key transporter of sweet and light sour foreign crude to PADD II. With a total system operating capacity of 1.14 million barrels per day of crude oil, approximately 248,000 barrels per day are subject to the interest acquired by us. Since acquisition, throughput on the interest acquired has averaged approximately 148,000 barrels per day. The Capwood Pipeline System, in which we acquired a 76% undivided joint interest from Shell in March 2004, is a 57-mile, 20-inch mainline crude oil pipeline originating in Patoka, Illinois, and terminating in Wood River, Illinois. The Capwood Pipeline System has an operating capacity of 277,000 barrels per day of crude oil. Of that capacity, approximately 211,000 barrels per day are subject to the interest acquired by us. The system has the ability to deliver crude at Wood River to several other PADD II refineries and pipelines, including those owned by Koch and ConocoPhillips. Movements on the Capwood system are driven by the volumes shipped on Capline as well as Canadian crude that can be delivered to Patoka via the Mustang Pipeline. Since closing, we have assumed the operatorship of the Capwood system from SPLC. Since acquisition, throughput on the interest acquired has averaged approximately 117,000 barrels per day.

Mississippi/Alabama Pipeline System. The Mississippi/Alabama Pipeline System, included in the April 2004 Link transaction, consists of a 331 mile proprietary gathering system and a 355 mile common carrier trunk system delivering crude oil primarily to three local refineries and to the Capline Pipeline System at Liberty, Mississippi. Also included in this system is approximately 4.5 million barrels of storage. Approximately 2.8 million barrels of this storage capacity is located at a deep water terminal in Mobile, Alabama capable of handling tankers with a draft of approximately 37 feet. For the third quarter of 2004, volumes averaged approximately 35,000 barrels per day.

La Gloria Pipeline System. The La Gloria Pipeline System, acquired in the Scurlock acquisition, is a proprietary crude oil pipeline system that during the first nine months of 2004, transported approximately 23,000 barrels of crude oil per day to Crown Central's refinery in Longview, Texas. Crown Central's deliveries are subject to a throughput and deficiency agreement, which extends through 2004.

Atchafalaya Pipeline System. The Atchafalaya Pipeline System, which we own 100% through three separate transactions in 2003, originates near Garden City, Louisiana and traverses east to its terminus near Gibson, Louisiana. The system consists of 35 miles of active 8-inch crude oil and condensate pipelines. During the first nine months of 2004, the system transported approximately 15,000 barrels per day of crude oil and condensate.

Sabine Pass Pipeline System. The Sabine Pass Pipeline System, acquired in the Scurlock acquisition, is a common carrier crude oil pipeline system. The Sabine Pass Pipeline System primarily gathers crude oil from onshore facilities of offshore production near Johnson's Bayou, Louisiana, and

delivers it to tankage and barge loading facilities in Sabine Pass, Texas. The Sabine Pass Pipeline System consists of approximately 51 miles of pipe ranging from 4 to 10 inches in diameter and has a throughput capacity of approximately 26,000 barrels of crude oil per day. During the first nine months of 2004, the system transported approximately 15,000 barrels of crude oil per day. The Sabine Pass Pipeline System also includes 245,000 barrels of tank capacity located along the pipeline.

Eugene Island Flowline System. The Eugene Island Flowline System ("EIFS") is a 57-mile offshore gathering pipeline located in the Eugene Island federal lease block area of the Gulf of Mexico. The system delivers crude oil gathered offshore to the Burns Terminal and to the Burns dock barge loading facility in south Louisiana. The total system volumes for the EIFS during the first nine months of 2004 were approximately 12,000 barrels per day of crude oil.

Red River Pipeline System. The Red River Pipeline System, acquired in 2003, is a 334-mile crude oil pipeline system that originates at Sabine in East Texas, and terminates near Cushing, Oklahoma. The Red River system has a capacity of up to 22,000 barrels of crude oil per day, depending upon the type of crude oil being transported. During the first nine months of 2004, the system transported approximately 11,000 barrels of crude oil per day. The system also includes approximately 645,000 barrels of crude oil storage capacity. In 2003, we completed a connection of the pipeline system to our Cushing Terminal.

ArkLaTex Pipeline System. The ArkLaTex Pipeline System, acquired from Link Energy in September 2003, consists of 240 miles of active crude oil gathering and mainline pipelines and connects to our Red River Pipeline System near Sabine, Texas. Also included in the transaction were 470,000 barrels of active crude oil storage capacity. During the first nine months of 2004, volumes transported averaged 8,000 barrels per day.

Ferriday Pipeline System. The Ferriday Pipeline System, acquired in the Scurlock acquisition, is a common carrier crude oil pipeline system located in eastern Louisiana and western Mississippi. The Ferriday Pipeline System consists of approximately 570 miles of pipe ranging from 2 inches to 12 inches in diameter. During the first nine months of 2004, the Ferriday Pipeline System delivered approximately 7,000 barrels of crude oil per day to third party pipelines that supplied refiners in the Midwest. The Ferriday Pipeline System also includes approximately 332,000 barrels of tank capacity located along the pipeline.

Southwest Louisiana Pipeline System. The Southwest Louisiana Pipeline System, included in the April 2004 Link transaction, consists of approximately 254 miles of primarily 6 to 10-inch pipe. The system originates in Rapides Parish, Louisiana and delivers to the Citgo refinery in Lake Charles, LA and to Nederland, Texas. For the third quarter of 2004, volumes averaged approximately 6,000 barrels per day.

Central U.S.

Oklahoma Pipeline System. The Oklahoma Pipeline System, included in the April 2004 Link transaction, consists of approximately 1,354 miles of active pipe, originating at various points in Oklahoma and terminating at Cushing, Oklahoma. In addition to the pipeline, there are approximately 1.7 million barrels of storage included in the system. For the third quarter of 2004, volumes averaged approximately 74,000 barrels per day.

Midcontinent Pipeline System. The Midcontinent Pipeline System, included in the April 2004 Link transaction, consists of approximately 1,200 miles of pipe, originating at various points in Nebraska, Kansas, and Colorado. Deliveries are primarily to Jayhawk pipeline and our Oklahoma Pipeline System. Also included in the system are approximately 0.4 million barrels of storage. For the third quarter of 2004, volumes averaged approximately 29,000 barrels per day.

Canada

Milk River Pipeline System. The Milk River Pipeline System, acquired in the Murphy acquisition, is a National Energy Board ("NEB") regulated system located in Alberta, Canada. The Milk River Pipeline System consists of three parallel 11-mile crude oil pipelines that connect the Bow River Pipeline in Alberta to the Cenex Pipeline at the United States border. The Milk River Pipeline System transported approximately 104,000 barrels of crude oil per day during the first nine months of 2004.

Manito Pipeline System. The Manito Pipeline System, acquired in the Murphy acquisition, is a provincially regulated system located in Saskatchewan, Canada. The Manito Pipeline System is a 101-mile crude oil pipeline and a parallel 101-mile condensate pipeline that connects our North Saskatchewan Pipeline System and multiple gathering lines to the Enbridge system at Kerrobert. The Manito Pipeline System volumes were approximately 70,000 barrels of crude oil and condensate per day in the first nine months of 2004.

South Saskatchewan Pipeline System. The South Saskatchewan Pipeline System, which was acquired in November 2003, originates approximately 75 miles southwest of Swift Current, Saskatchewan, and traverses north and east until it reaches its terminus at Regina. The system consists of a 158-mile, 16-inch mainline and 203 miles of gathering lines ranging in diameter from three to twelve inches. During the first nine months of 2004, the system transported approximately 48,000 barrels of crude oil per day. At Regina, the system can deliver crude oil to the Enbridge Pipeline System and to local markets. In addition, the system can indirectly deliver crude oil into our Wascana Pipeline System.

Cactus Lake/Bodo Pipeline System. The Cactus Lake/Bodo Pipeline System, acquired in the Murphy acquisition, is located in Alberta and Saskatchewan, Canada. The Bodo portion of the system is NEB-regulated, and the remainder is provincially regulated. We operate the Cactus Lake/Bodo Pipeline System, which is a 55-mile crude oil pipeline and a parallel 55-mile condensate pipeline that connects to our storage and terminalling facility at Kerrobert. During the first nine months of 2004, the Cactus Lake/Bodo Pipeline System transported approximately 24,000 barrels per day (approximately 3,200 barrels per day, net to our interest) of crude oil and condensate. Our ownership interest in the Cactus Lake segment is 15% and our ownership interest in the Bodo Pipeline is 100%. We also own various interests in the lateral lines in these systems.

Cal Ven Pipeline System. The Cal Ven Pipeline System, acquired in the Cal Ven acquisition in May 2004, is a provincially regulated crude oil pipeline that is located in Northern Alberta, Canada. The Cal Ven Pipeline System is comprised of approximately 195 miles of 8-inch and 10-inch gathering and mainline crude oil pipelines. The Cal Ven Pipeline System delivers crude oil into the Rainbow Pipeline System at Utikuma. The Cal Ven Pipeline System transported approximately 16,000 barrels per day in the third quarter of 2004.

Wapella Pipeline System. The Wapella Pipeline System is a 79-mile, NEB-regulated system located in southeastern Saskatchewan and southwestern Manitoba. During the first nine months of 2004, the Wapella Pipeline System delivered approximately 13,000 barrels of crude oil per day to the Enbridge Pipeline at Cromer, Manitoba. The system also includes approximately 18,500 barrels of crude oil storage capacity.

Wascana Pipeline System. The Wascana Pipeline System, acquired in the Murphy acquisition, is an NEB-regulated system located in Saskatchewan, Canada. The Wascana Pipeline System is a 107-mile crude oil pipeline that connects to the Bridger Pipeline system at the United States border near Raymond, Montana. During the first nine months of 2004, the Wascana Pipeline System transported approximately 9,000 barrels of crude oil per day.

North Saskatchewan Pipeline System. The North Saskatchewan Pipeline System, acquired in the Murphy acquisition, is a provincially regulated system located in Saskatchewan, Canada. We operate the North Saskatchewan Pipeline System, which is a 34-mile crude oil pipeline and a parallel 34-mile condensate pipeline that connects to our Manito Pipeline at Dulwich. During the first nine months of 2004, the North Saskatchewan Pipeline System delivered approximately 4,400 barrels of crude oil per day into the Manito Pipeline. Our ownership interest in the North Saskatchewan Pipeline System is approximately 69%.

Gathering, Marketing, Terminalling and Storage Operations

The combination of our gathering and marketing operations and our terminalling and storage operations provides a counter cyclical balance that has a stabilizing effect on our operations and cash flow. The strategic use of our terminalling and storage assets in conjunction with our gathering and marketing operations provides us with the flexibility to optimize margins irrespective of whether a strong or weak market exists. Following is a description of our activities with respect to this segment.

Gathering and Marketing Operations

Crude Oil. The majority of our gathering and marketing activities are in the geographic locations previously discussed. These activities include:

•: purchasing crude oil from producers at the wellhead and in bulk from aggregators at major pipeline interconnects and trading locations;
•: transporting this crude oil on our own proprietary gathering assets and our common carrier pipelines or, when necessary or cost effective, assets owned and operated by third parties;
•: exchanging this crude oil for another grade of crude oil or at a different geographic location, as appropriate, in order to maximize margins or meet contract delivery requirements; and
•: marketing crude oil to refiners or other resellers.

We purchase crude oil from many independent producers and believe that we have established broad based relationships with crude oil producers in our areas of operations. Gathering and marketing activities involve relatively large volumes of transactions with lower margins compared to pipeline and terminalling and storage operations.

The following table shows the average daily volume of our lease gathering and bulk purchases for the past five years and the nine months ended September 30, 2004:

		Nine Months Ended September 30, 2004	Year Ended December 31,
		Nine Months Ended September 30, 2004	2003	2002	2001	2000	1999
		(barrels in thousands)
Lease gathering		576	437	410	348	262	265
Bulk purchases⁽¹⁾		143	90	68	46	28	138

	Total volumes	719	527	478	394	290	403

⁽¹⁾: We have decreased the number of barrels previously disclosed in the "Bulk purchases" line for the 2002 period by approximately 12,000. The adjustment reflects an elimination of crude oil volumes improperly classified as bulk purchases.

Crude Oil Purchases. We purchase crude oil from producers under contracts, the majority of which range in term from a thirty-day evergreen to three years. In a typical producer's operation, crude oil flows from the wellhead to a separator where the petroleum gases are removed. After separation, the crude oil is treated to remove water, sand and other contaminants and is then moved into the

producer's on-site storage tanks. When the tank is approaching capacity, the producer contacts our field personnel to purchase and transport the crude oil to market. We utilize our truck fleet and gathering pipelines as well as third party pipelines, trucks and barges to transport the crude oil to market. We own or lease approximately 400 trucks used for gathering crude oil.

Since 1998, we have had a marketing arrangement with Plains Resources, under which we have been the exclusive marketer and purchaser for all of Plains Resources' equity crude oil production (including its subsidiaries that conduct exploration and production activities). In connection with the separation of Plains Resources and one of its subsidiaries discussed below, Plains Resources divested the bulk of its producing properties. As a result, we do not anticipate the marketing arrangement with Plains Resources to be material to our operating results in the future.

In December 2002, Plains Resources completed a spin-off to its stockholders of PXP. We currently have a marketing agreement with PXP for certain of its equity crude oil production and that of its subsidiaries. The marketing agreement provides that we will purchase PXP's equity crude oil production for resale at market prices, for which we charge a fee of $0.20 per barrel. For any new contracts for the sale of the crude oil entered into after January 1, 2005, the marketing fee will be adjusted to $0.15 per barrel, subject to further adjustment in November 2007 based upon then existing market conditions. See "Certain Relationships and Related Transactions—Transactions with Related Parties—General."

Bulk Purchases. In addition to purchasing crude oil at the wellhead from producers, we purchase crude oil in bulk at major pipeline terminal locations. This oil is transported from the wellhead to the pipeline by major oil companies, large independent producers or other gathering and marketing companies. We purchase crude oil in bulk when we believe additional opportunities exist to realize margins further downstream in the crude oil distribution chain. The opportunities to earn additional margins vary over time with changing market conditions. Accordingly, the margins associated with our bulk purchases will fluctuate from period to period.

Crude Oil Sales. The marketing of crude oil is complex and requires current detailed knowledge of crude oil sources and end markets and a familiarity with a number of factors including grades of crude oil, individual refinery demand for specific grades of crude oil, area market price structures for the different grades of crude oil, location of customers, availability of transportation facilities and timing and costs (including storage) involved in delivering crude oil to the appropriate customer. We sell our crude oil to major integrated oil companies, independent refiners and other resellers in various types of sale and exchange transactions, at market prices for terms ranging from one month to three years.

We establish a margin for crude oil we purchase by selling crude oil for physical delivery to third party users, such as independent refiners or major oil companies, or by entering into a future delivery obligation with respect to futures contracts on the NYMEX or over-the-counter. Through these transactions, we seek to maintain a position that is substantially balanced between crude oil purchases and sales and future delivery obligations. From time to time, we enter into various types of sale and exchange transactions including fixed price delivery contracts, floating price collar arrangements, financial swaps and crude oil futures contracts as hedging devices. Except for pre-defined inventory positions, our policy is generally to purchase only crude oil for which we have a market, to structure our sales contracts so that crude oil price fluctuations do not materially affect the segment profit we receive, and to not acquire and hold crude oil, futures contracts or other derivative products for the purpose of speculating on crude oil price changes that might expose us to indeterminable losses. In November 1999, we discovered a significant violation of this policy. As a result, we incurred an aggregate loss of approximately $181 million in unauthorized trading losses, including associated costs and legal expenses.

Crude Oil Exchanges. We pursue exchange opportunities to enhance margins throughout the gathering and marketing process. When opportunities arise to increase our margin or to acquire a grade of crude oil that more closely matches our physical delivery requirement or the preferences of our refinery customers, we exchange physical crude oil with third parties. These exchanges are effected through contracts called exchange or buy-sell agreements. Through an exchange agreement, we agree to buy crude oil that differs in terms of geographic location, grade of crude oil or physical delivery schedule from crude oil we have available for sale. Generally, we enter into exchanges to acquire crude oil at locations that are closer to our end markets, thereby reducing transportation costs and increasing our margin. We also exchange our crude oil to be physically delivered at a later date, if the exchange is expected to result in a higher margin net of storage costs, and enter into exchanges based on the grade of crude oil, which includes such factors as sulfur content and specific gravity, in order to meet the quality specifications of our physical delivery contracts.

Producer Services. Crude oil purchasers who buy from producers compete on the basis of competitive prices and highly responsive services. Through our team of crude oil purchasing representatives, we maintain ongoing relationships with producers in the United States and Canada. We believe that our ability to offer high-quality field and administrative services to producers is a key factor in our ability to maintain volumes of purchased crude oil and to obtain new volumes. Field services include efficient gathering capabilities, availability of trucks, willingness to construct gathering pipelines where economically justified, timely pickup of crude oil from tank batteries at the lease or production point, accurate measurement of crude oil volumes received, avoidance of spills and effective management of pipeline deliveries. Accounting and other administrative services include securing division orders (statements from interest owners affirming the division of ownership in crude oil purchased by us), providing statements of the crude oil purchased each month, disbursing production proceeds to interest owners, and calculation and payment of ad valorem and production taxes on behalf of interest owners. In order to compete effectively, we must maintain records of title and division order interests in an accurate and timely manner for purposes of making prompt and correct payment of crude oil production proceeds, together with the correct payment of all severance and production taxes associated with such proceeds.

Liquefied Petroleum Gas and Other Petroleum Products. We also market and store LPG and other petroleum products throughout the United States and Canada, concentrated primarily in Washington, California, Kansas, Michigan, Pennsylvania, Texas, Montana, Nebraska and the Canadian provinces of Alberta and Ontario. These activities include:

•: purchasing LPG (primarily propane and butane) from producers at gas plants and in bulk at major pipeline terminal points and storage locations;
•: transporting the LPG via common carrier pipelines, railcars and trucks to our own terminals and third party facilities for subsequent resale by them to retailers and other wholesale customers; and
•: exchanging product to other locations to maximize margins and /or to meet contract delivery requirements.

We purchase LPG from numerous producers and have established long-term, broad based relationships with LPG producers in our areas of operation. We purchase LPG directly from gas plants, major pipeline terminals and storage locations. Marketing activities for LPG typically consist of smaller volumes and generally higher margin per barrel transactions relative to crude oil.

LPG Purchases. We purchase LPG from producers, refiners, and other LPG marketing companies under contracts that range from immediate delivery to one year in term. In a typical producer's or refiner's operation, LPG that is produced at the gas plant or refinery is fractionated into various

components including propane and butane and then purchased by us for movement via tank truck, railcar or pipeline.

In addition to purchasing LPG at gas plants or refineries, we also purchase LPG in bulk at major pipeline terminal points and storage facilities from major oil companies, large independent producers or other LPG marketing companies. We purchase LPG in bulk when we believe additional opportunities exist to realize margins further downstream in our LPG distribution chain. The opportunities to earn additional margins vary over time with changing market conditions. Accordingly, the margins associated with our bulk purchases will fluctuate from period to period.

LPG Sales. The marketing of LPG is complex and requires current detailed knowledge of LPG sources and end markets and a familiarity with a number of factors including the various modes and availability of transportation, area market prices and timing and costs of delivering LPG to customers.

We sell LPG primarily to industrial end users and retailers, and limited volumes to other marketers. Propane is sold to small independent retailers who then transport the product via bobtail truck to residential consumers for home heating and to some light industrial users such as forklift operators. Butane is used by refiners for gasoline blending and as a diluent for the movement of conventional heavy oil production. Butane demand for use as heavy oil diluent has increased as supplies of Canadian condensate have declined.

We establish a margin for propane by transporting it in bulk, via various transportation modes, to our controlled terminals where we deliver the propane to our retailer customers for subsequent delivery to their individual heating customers. We also create margin by selling propane for future physical delivery to third party users, such as retailers and industrial users. Through these transactions, we seek to maintain a position that is substantially balanced between propane purchases and sales and future delivery obligations. From time to time, we enter into various types of sale and exchange transactions including floating price collar arrangements, financial swaps and crude oil and LPG-related futures contracts as hedging devices. Except for pre-defined inventory positions, our policy is generally to purchase only LPG for which we have a market, and to structure our sales contracts so that LPG spot price fluctuations do not materially affect the segment profit we receive. Margin is created on the butane purchased by delivering large volumes during the short refinery blending season through the use of our extensive leased railcar fleet and the use of our own storage facilities and third party storage facilities. We also create margin on butane by capturing the difference in price between condensate and butane when butane is used to replace condensate as a diluent for the movement of Canadian heavy oil production. While we seek to maintain a position that is substantially balanced within our LPG activities, as a result of production, transportation and delivery variances as well as logistical issues associated with inclement weather conditions, from time to time we experience net unbalanced positions for short periods of time. In connection with managing these positions and maintaining a constant presence in the marketplace, both necessary for our core business, our policies provide that any net imbalance may not exceed 250,000 barrels. These activities are monitored independently by our risk management function and must take place within predefined limits and authorizations.

LPG Exchanges. We pursue exchange opportunities to enhance margins throughout the marketing process. When opportunities arise to increase our margin or to acquire a volume of LPG that more closely matches our physical delivery requirement or the preferences of our customers, we exchange physical LPG with third parties. These exchanges are effected through contracts called exchange or buy-sell agreements. Through an exchange agreement, we agree to buy LPG that differs in terms of geographic location, type of LPG or physical delivery schedule from LPG we have available for sale. Generally, we enter into exchanges to acquire LPG at locations that are closer to our end markets in order to meet the delivery specifications of our physical delivery contracts.

Credit. Our merchant activities involve the purchase of crude oil and LPG for resale and require significant extensions of credit by our suppliers of crude oil and LPG. In order to assure our ability to perform our obligations under crude oil purchase agreements, various credit arrangements are negotiated with our suppliers. These arrangements include open lines of credit directly with us, and standby letters of credit issued under our senior unsecured revolving credit facility.

When we market crude oil, we must determine the amount, if any, of the line of credit to be extended to any given customer. We manage our exposure to credit risk through credit analysis, credit approvals, credit limits and monitoring procedures. If we determine that a customer should receive a credit line, we must then decide on the amount of credit that should be extended. Because our typical sales transactions can involve tens of thousands of barrels of crude oil, the risk of nonpayment and nonperformance by customers is a major consideration in our business. We believe our sales are made to creditworthy entities or entities with adequate credit support. Generally, sales of crude oil are settled within 30 days of the month of delivery, and pipeline, transportation and terminalling services also settle within 30 days from invoice for the provision of services.

We also have credit risk with respect to our sales of LPG; however, because our sales are typically in relatively small amounts to individual customers, we do not believe that we have material concentration of credit risk. Typically, we enter into annual contracts to sell LPG on a forward basis, as well as sell LPG on a current basis to local distributors and retailers. In certain cases our customers prepay for their purchases, in amounts ranging from $0.05 per gallon to 100% of their contracted amounts. Generally, sales of LPG are settled within 30 days of the date of invoice.

Terminalling and Storage Operations

We own approximately 37 million barrels of terminalling and storage assets. Approximately 13.6 million barrels of capacity are used in our Gathering, Marketing, Terminalling and Storage segment, and the remaining 23.4 million barrels are used in our Pipeline Operating segment. Our storage and terminalling operations increase our margins in our business of purchasing and selling crude oil and also generate revenue through a combination of storage and throughput charges to third parties. Storage fees are generated when we lease tank capacity to third parties. Terminalling fees, also referred to as throughput fees, are generated when we receive crude oil from one connecting pipeline and redeliver crude oil to another connecting carrier in volumes that allow the refinery to receive its crude oil on a ratable basis throughout a delivery period. Both terminalling and storage fees are generally earned from:

•: refiners and gatherers that segregate or custom blend crudes for refining feedstocks;
•: pipeline operators, refiners or traders that need segregated tankage for foreign cargoes;
•: traders who make or take delivery under NYMEX contracts; and
•: producers and resellers that seek to increase their marketing alternatives.

The tankage that is used to support our arbitrage activities positions us to capture margins in a contango market (when the oil prices for future deliveries are higher than the current prices) or when the market switches from contango to backwardation (when the oil prices for future deliveries are lower than the current prices).

Our most significant terminalling and storage asset is our Cushing Terminal located at the Cushing Interchange. The Cushing Interchange is one of the largest wet-barrel trading hubs in the U.S. and the delivery point for crude oil futures contracts traded on the NYMEX. The Cushing Terminal has been designated by the NYMEX as an approved delivery location for crude oil delivered under the NYMEX light sweet crude oil futures contract. As the NYMEX delivery point and a cash market hub, the Cushing Interchange serves as a primary source of refinery feedstock for the Midwest refiners and plays an integral role in establishing and maintaining markets for many varieties of foreign and domestic crude oil. Our Cushing Terminal was constructed in 1993, with an initial tankage capacity of 2 million

barrels, to capitalize on the crude oil supply and demand imbalance in the Midwest. The Cushing Terminal is also used to support and enhance the margins associated with our merchant activities relating to our lease gathering and bulk purchasing activities. See "—Gathering and Marketing Operations—Bulk Purchases." Since 1999, we have completed four separate expansion phases, which increased the capacity of the Cushing Terminal to a total of approximately 6.3 million barrels. The Cushing Terminal now consists of fourteen 100,000-barrel tanks, four 150,000-barrel tanks and sixteen 270,000-barrel tanks, all of which are used to store and terminal crude oil. We believe that the facility can be further expanded to meet additional demand should market conditions warrant. The Cushing Terminal also includes a pipeline manifold and pumping system that has an estimated throughput capacity of approximately 800,000 barrels per day. The Cushing Terminal is connected to the major pipelines and other terminals in the Cushing Interchange through pipelines that range in size from 10 inches to 24 inches in diameter.

The Cushing Terminal is designed to serve the needs of refiners in the Midwest. In order to service an expected increase in the volumes as well as the varieties of foreign and domestic crude oil projected to be transported through the Cushing Interchange, we incorporated certain attributes into the design of the Cushing Terminal including:

•: multiple, smaller tanks to facilitate simultaneous handling of multiple crude varieties in accordance with normal pipeline batch sizes;
•: dual header systems connecting most tanks to the main manifold system to facilitate efficient switching between crude grades with minimal contamination;
•: bottom drawn sumps that enable each tank to be efficiently drained down to minimal remaining volumes to minimize crude oil contamination and maintain crude oil integrity during changes of service;
•: mixer(s) on each tank to facilitate blending crude oil grades to refinery specifications; and
•: a manifold and pump system that allows for receipts and deliveries with connecting carriers at their maximum operating capacity.

As a result of incorporating these attributes into the design of the Cushing Terminal, we believe we are favorably positioned to serve the needs of Midwest refiners to handle an increase in the number of varieties of crude oil transported through the Cushing Interchange. The pipeline manifold and pumping system of our Cushing Terminal is designed to support more than 10 million barrels of tank capacity and we have sufficient land holdings in and around the Cushing Interchange on which to construct additional tankage. Our tankage in Cushing ranges in age from less than a year old to approximately 11 years old and the average age is approximately 5.1 years old. In contrast, we estimate that of the approximately 21 million barrels of remaining tanks in Cushing owned by third parties, the average age is approximately 50 years and of that, approximately 9 million barrels has an average age of over 70 years. We believe that provides us with a competitive advantage over our competitors. In addition, we believe that we are well positioned to accommodate construction of replacement tankage that may be required as a result of the imposition of stricter regulatory standards and related attrition among our competitors' tanks in connection with the requirements of API 653 and similar Canadian regulations. See "—Regulation—Pipeline and Storage Regulation."

Our Cushing Terminal also incorporates numerous environmental and operational safeguards. We believe that our terminal is the only one at the Cushing Interchange in which each tank has a secondary liner (the equivalent of double bottoms), leak detection devices and secondary seals. The Cushing Terminal is the only terminal at the Cushing Interchange equipped with aboveground pipelines. Like the pipeline systems we operate, the Cushing Terminal is operated by a computer system designed to monitor real-time operational data and each tank is cathodically protected. In addition, each tank is equipped with a high-level alarm system to prevent overflows; a double seal floating roof designed to minimize air emissions and prevent the possible accumulation of potentially flammable gases between

fluid levels and the roof of the tank; and a foam dispersal system that, in the event of a fire, is fed by a fully automated fire water distribution network.

We also own LPG storage facilities located in Alto, Michigan and Schaefferstown, Pennsylvania. The Alto facility is approximately 20 miles southeast of Grand Rapids. The Alto facility was acquired from Ohio-Northwest Development Inc. in 2003 and is capable of storing over 50 million gallons of LPG. The Schaefferstown facility is approximately 65 miles northwest of Philadelphia and is capable of storing over 20 million gallons of propane. We believe these facilities will further support the expansion of our LPG business in Canada and the northern tier of the U.S. as we combine the facilities' existing fee-based storage business with our wholesale propane marketing expertise. In addition, there may be opportunities to expand these facilities as LPG markets continue to develop in the region.

Crude Oil Volatility; Counter Cyclical Balance; Risk Management

Crude oil prices have historically been very volatile and cyclical, with NYMEX benchmark prices ranging from a high of over $55 per barrel in October, 2004 to as low as $10.00 per barrel over the last 14 years. Segment profit from terminalling and storage activities is dependent on the crude oil throughput volume, capacity leased to third parties, capacity that we use for our own activities, and the level of other fees generated at our terminalling and storage facilities. Segment profit from our gathering and marketing activities is dependent on our ability to sell crude oil at a price in excess of our aggregate cost. Although margins may be affected during transitional periods, these operations are not directly affected by the absolute level of crude oil prices, but are affected by overall levels of supply and demand for crude oil and relative fluctuations in market related indices.

During periods when supply exceeds the demand for crude oil, the market for crude oil is often in contango, meaning that the price of crude oil for future deliveries is higher than current prices. A contango market has a generally negative impact on marketing margins, but is favorable to the storage business, because storage owners at major trading locations (such as the Cushing Interchange) can simultaneously purchase production at current prices for storage and sell at higher prices for future delivery.

When there is a higher demand than supply of crude oil in the near term, the market is backwardated, meaning that the price of crude oil for future deliveries is lower than current prices. A backwardated market has a positive impact on marketing margins because crude oil gatherers can capture a premium for prompt deliveries. In this environment, there is little incentive to store crude oil as current prices are above future delivery prices.

The periods between a backwardated market and a contango market are referred to as transition periods. Depending on the overall duration of these transition periods, how we have allocated our assets to particular strategies and the time length of our crude oil purchase and sale contracts and storage lease agreements, these transition periods may have either an adverse or beneficial affect on our aggregate segment profit. A prolonged transition from a backwardated market to a contango market, or vice versa (essentially a market that is neither in pronounced backwardation nor contango), represents the most difficult environment for our gathering, marketing, terminalling and storage activities. When the market is in contango, we will use our tankage to improve our gathering margins by storing crude oil we have purchased for delivery in future months that are selling at a higher price. In a backwardated market, we use and lease less storage capacity but increased marketing margins provide an offset to this reduced cash flow. We believe that the combination of our terminalling and storage activities and gathering and marketing activities provides a counter cyclical balance that has a stabilizing effect on our operations and cash flow. References to counter cyclical balance elsewhere in this report are referring to this relationship between our terminalling and storage activities and our gathering and marketing activities in transitioning crude oil markets.

As use of the financial markets for crude oil has increased by producers, refiners, utilities and trading entities, risk management strategies, including those involving price hedges using NYMEX

futures contracts and derivatives, have become increasingly important in creating and maintaining margins. Such hedging techniques require significant resources dedicated to managing these positions. Our risk management policies and procedures are designed to monitor both NYMEX and over-the-counter positions and physical volumes, grades, locations and delivery schedules to ensure that our hedging activities are implemented in accordance with such policies. We have a risk management function that has direct responsibility and authority for our risk policies, our trading controls and procedures and certain other aspects of corporate risk management.

Our policy is to purchase only crude oil for which we have a market, and to structure our sales contracts so that crude oil price fluctuations do not materially affect the segment profit we receive. Except for the controlled trading program discussed below, we do not acquire and hold crude oil futures contracts or other derivative products for the purpose of speculating on crude oil price changes that might expose us to indeterminable losses.

Customers

Marathon Ashland Petroleum accounted for 12%, 10% and 11% of our revenues for each of the three years in the period ended December 31, 2003. For the nine months ended September 30, 2004, Marathon Ashland Petroleum and BP Oil Supply Company each accounted for approximately 10% of our revenues. No other customers accounted for 10% or more of our revenues during the three years ended December 31, 2003 or the nine months ended September 30, 2004. The majority of the revenues from Marathon Ashland Petroleum and BP Oil Supply Company pertain to our gathering, marketing, terminalling and storage operations. We believe that the loss of these customers would have only a short-term impact on our operating results. There can be no assurance, however, that we would be able to identify and access a replacement market at comparable margins.

Competition

Competition among pipelines is based primarily on transportation charges, access to producing areas and demand for the crude oil by end users. We believe that high capital requirements, environmental considerations and the difficulty in acquiring rights-of-way and related permits make it unlikely that competing pipeline systems comparable in size and scope to our pipeline systems will be built in the foreseeable future. However, to the extent there are already third party owned pipelines or owners with joint venture pipelines with excess capacity in the vicinity of our operations, we will be exposed to significant competition based on the incremental cost of moving an incremental barrel of crude oil.

We face intense competition in our gathering, marketing, terminalling and storage operations. Our competitors include other crude oil pipeline companies, the major integrated oil companies, their marketing affiliates and independent gatherers, brokers and marketers of widely varying sizes, financial resources and experience. Some of these competitors have capital resources many times greater than ours, and control greater supplies of crude oil.

Regulation

Our operations are subject to extensive regulations. We estimate that we are subject to regulatory oversight by over 70 federal, state, provincial and local departments and agencies, many of which are authorized by statute to issue and have issued laws and regulations binding on the oil pipeline industry, related businesses and individual participants. The failure to comply with such rules and regulations can result in substantial penalties. The regulatory burden on our operations increases our cost of doing business and, consequently, affects our profitability. However, except for certain exemptions that apply to smaller companies, we do not believe that we are affected in a significantly different manner by these laws and regulations than are our competitors. Due to the myriad of complex federal, state, provincial and local regulations that may affect us, directly or indirectly, you should not rely on the following discussion of certain laws and regulations as an exhaustive review of all regulatory considerations affecting our operations.

Pipeline and Storage Regulation

A substantial portion of our petroleum pipelines and storage tanks in the United States are subject to regulation by the U.S. Department of Transportation ("DOT") with respect to the design, installation, testing, construction, operation, replacement and management of pipeline and tank facilities. In addition, we must permit access to and copying of records, and must make certain reports available and provide information as required by the Secretary of Transportation. Comparable regulation exists in some states in which we conduct intrastate common carrier or private pipeline operations, as well as in Canada under the National Energy Board ("NEB") and provincial agencies.

Federal pipeline safety rules require pipeline operators to develop and maintain a written qualification program for individuals performing covered tasks on pipeline facilities, and establish pipeline integrity management programs. In particular, since 2000, the DOT has adopted a series of rules requiring operators of interstate pipelines transporting hazardous liquids or natural gas to develop and follow an integrity management program that provides for continual assessment of the integrity of all pipeline segments that could affect so-called "high consequence areas," including high population areas, areas that are sources of drinking water, ecological resource areas that are unusually sensitive to environmental damage from a pipeline release, and commercially navigable waterways. Segments of our pipelines transporting hazardous liquids in high consequence areas are subject to these DOT rules and therefore obligate us to evaluate pipeline conditions by means of periodic internal inspection, pressure testing, or other equally effective assessment means, and to correct identified anomalies. If, as a result of our evaluation process, we determine that there is a need to provide further protection to high consequence areas, then we will be required to implement additional spill prevention, mitigation and risk control measures for our pipelines. The DOT rules also require us to evaluate and, as necessary,

improve our management and analysis processes for integrating available integrity related data relating to our pipeline segments and to remediate potential problems found as a result of the required assessment and evaluation process. Costs associated with this program were approximately $1.0 million in 2003. Based on currently available information, we estimate that the costs to implement and carry out this program will be approximately $6.0 million in 2004. Our preliminary estimate for 2005 is $7.9 million. The relative increase in program cost for 2004 is primarily attributable to pipeline segments acquired in 2003 and 2004 (including the Link assets), which are subject to the new rules and which were scheduled for assessment in 2004. These costs are recurring in nature and thus will impact future periods. We will continue to refine our estimates as information from our assessments is collected. Our estimates do not include the potential costs associated with assets acquired in the future. Although we believe that our pipeline operations are in substantial compliance with currently applicable regulatory requirements, we cannot predict the potential costs associated with additional, future regulation.

The DOT is currently considering expanding the scope of its pipeline regulation to include certain gathering pipeline systems that are not currently subject to regulation. This expanded scope would likely include the establishment of additional pipeline integrity management programs for these newly regulated pipelines. The DOT is in the initial stages of evaluating this initiative and we do not currently know what, if any, impact this will have on our operating expenses. However, we cannot assure you that future costs related to the potential programs will not be material. However, even if the DOT does not expand the scope of its pipeline regulation to include pipeline systems not currently regulated, we may still need to implement pipeline integrity management programs to remain in compliance with the Federal Water Pollution Control Act and other environmental laws. We could be required to spend substantial sums to ensure the integrity of and upgrade our pipeline systems to maintain environmental compliance, and in some cases, we may take pipelines out of service if we believe the cost of upgrades will exceed the value of the pipelines. We cannot provide any assurance as to the ultimate amount or timing of future pipeline integrity expenditures for environmental compliance.

States are largely preempted by federal law from regulating pipeline safety but may assume responsibility for enforcing federal intrastate pipeline regulations and inspection of intrastate pipelines. In practice, states vary considerably in their authority and capacity to address pipeline safety. We do not anticipate any significant problems in complying with applicable state laws and regulations in those states in which we operate.

The DOT has adopted API 653 as the standard for the inspection, repair, alteration and reconstruction of existing crude oil storage tanks subject to DOT jurisdiction (approximately 83% of our 37 million barrels). API 653 requires regularly scheduled inspection and repair of tanks remaining in service. Full compliance is required by 2009. We have commenced our compliance activities and, based on currently available information, we estimate that we will spend approximately $3 million in 2004 and an approximate average of $6.2 million per year from 2005 through 2009 in connection with API 653 compliance activities. Such amounts incorporate the costs associated with the assets acquired in 2003 and 2004. Our estimates do not include the potential costs associated with assets acquired in the future. We will continue to refine our estimates as information from our assessments is collected.

We have instituted security measures and procedures, in accordance with DOT guidelines, to enhance the protection of certain of our facilities from terrorist attack. We cannot assure you that these security measures would fully protect our facilities from a concentrated attack. See "—Operational Hazards and Insurance."

In Canada, the NEB and provincial agencies such as the Alberta Energy and Utilities Board and the Saskatchewan Industry and Resources have promulgated regulations similar to the domestic pipeline integrity management rules and API 653 standards. We estimate that the costs associated with compliance will be approximately $5.0 million in 2004. Our preliminary estimate for 2005 is $5.0 million. In addition, we expect to incur compliance costs under other regulations related to

pipeline and storage tank integrity, such as operator competency programs, regulatory upgrades to our operating and maintenance systems and environmental upgrades of buried sump tanks. Our preliminary estimate for such costs for 2005 is approximately $1.0 million. These costs are recurring in nature and thus will impact future periods. We will continue to refine our estimates as information from our assessments is collected. Our estimates do not include the potential costs associated with assets acquired in the future. Although we believe that our pipeline operations are in substantial compliance with currently applicable regulatory requirements, we cannot predict the potential costs associated with additional, future regulation.

Asset acquisitions are an integral part of our business strategy. As we acquire additional assets, we may be required to incur additional costs in order to ensure that the acquired assets comply with the regulatory standards in the U.S. and Canada. The timing of such additional costs is uncertain and could vary materially from our current projections.

Transportation Regulation

General Interstate Regulation. Our interstate common carrier pipeline operations are subject to rate regulation by the FERC under the Interstate Commerce Act. The Interstate Commerce Act requires that tariff rates for petroleum pipelines, which includes both crude oil pipelines and refined product pipelines, be just and reasonable and non-discriminatory.

State Regulation. Our intrastate pipeline transportation activities are subject to various state laws and regulations, as well as orders of state regulatory bodies.

Canadian Regulation. Our Canadian pipeline assets are subject to regulation by the NEB and by provincial agencies. With respect to a pipeline over which it has jurisdiction, each of these agencies has the power, upon application by a third party, to determine the rates we are allowed to charge for transportation on, and set other terms of access to, such pipeline. In such circumstances, if the relevant regulatory agency determines that the applicable terms and conditions of service are not just and reasonable, the agency can amend the offending provisions of an existing transportation contract.

Energy Policy Act of 1992 and Subsequent Developments. In October 1992, Congress passed the Energy Policy Act of 1992 ("EPAct"), which among other things, required the FERC to issue rules establishing a simplified and generally applicable ratemaking methodology for petroleum pipelines and to streamline procedures in petroleum pipeline proceedings. The FERC responded to this mandate by issuing several orders, including Order No. 561. Beginning January 1, 1995, Order No. 561 enables petroleum pipelines to change their rates within prescribed ceiling levels that are tied to an inflation index. Rate increases made pursuant to the indexing methodology are subject to protest, but such protests must show that the portion of the rate increase resulting from application of the index is substantially in excess of the pipeline's increase in costs. If the indexing methodology results in a reduced ceiling level that is lower than a pipeline's filed rate, Order No. 561 requires the pipeline to reduce its rate to comply with the lower ceiling unless doing so would reduce a rate "grandfathered" by EPAct (see below) below the grandfathered level. A pipeline must, as a general rule, utilize the indexing methodology to change its rates. The FERC, however, retained cost-of-service ratemaking, market based rates, and settlement as alternatives to the indexing approach, which alternatives may be used in certain specified circumstances. The EPAct deemed petroleum pipeline rates in effect for the 365-day period ending on the date of enactment of EPAct that had not been subject to complaint, protest or investigation during that 365-day period to be just and reasonable under the Interstate Commerce Act. Generally, complaints against such "grandfathered" rates may only be pursued if the complainant can show that a substantial change has occurred since the enactment of EPAct in either the economic circumstances of the oil pipeline, or in the nature of the services provided, that were a basis for the rate. EPAct places no such limit on challenges to a provision of an oil pipeline tariff as unduly discriminatory or preferential.

On July 20, 2004, the United States Court of Appeals for the District of Columbia Circuit ("D.C. Circuit") issued its opinion in BP West Coast Products, LLC v. FERC, which upheld FERC's determination that the rates of an interstate petroleum products pipeline, SFPP, L.P. ("SFPP"), were grandfathered rates under EPAct and that SFPP's shippers had not demonstrated substantially changed circumstances that would justify modification of those rates. The court also vacated the portion of the FERC's decision applying the Lakehead policy, under which the FERC allowed a regulated entity organized as a master limited partnership to include in its cost-of-service an income tax allowance to the extent that entity's unitholders were corporations subject to income tax. We are uncertain what action, if any, FERC will take in response to the court's disapproval of the FERC's Lakehead policy and what effect, if any, such action might have on our rates should they be challenged.

Additionally, in BP West Coast, the court remanded to the FERC the issue of whether SFPP's revised cost-of-service without a tax allowance would qualify as a substantially changed circumstance that would justify modification of SFPP's rates. Because the court remanded to the FERC and because the FERC's ruling on the substantially changed circumstances issue will focus on the facts and record presented to it, it is not clear what impact, if any, the opinion will have on our rates or on the rates of other FERC-jurisdictional pipelines organized as tax pass-through entities. Moreover, it is not clear to what extent FERC's actions taken in response to BP West Coast will be challenged and, if so, whether they will withstand further FERC or judicial review.

In a subsequent FERC proceeding involving SFPP, certain shippers again challenged SFPP's grandfathered rates on the basis of substantially changed circumstances since the passage of EPAct. On March 26, 2004, the FERC issued an order in that case, finding that some of SFPP's rates were no longer grandfathered. Several of the participants in the proceeding have requested rehearing of the FERC's order, and several participants have filed petitions with the D.C. Circuit for review of the order. FERC and court action on those petitions is pending. We are uncertain whether FERC's order will remain intact and, if it does, what effect, if any, that order might have on our grandfathered rates should they be challenged.

Our Pipelines. The FERC generally has not investigated rates on its own initiative when those rates have not been the subject of a protest or complaint by a shipper. Substantially all of our segment profit on transportation is produced by rates that are either grandfathered or set by agreement with one or more shippers.

Trucking Regulation

We operate a fleet of trucks to transport crude oil and oilfield materials as a private, contract and common carrier. We are licensed to perform both intrastate and interstate motor carrier services. As a motor carrier, we are subject to certain safety regulations issued by the Department of Transportation. The trucking regulations cover, among other things, driver operations, maintaining log books, truck manifest preparations, the placement of safety placards on the trucks and trailer vehicles, drug and alcohol testing, safety of operation and equipment, and many other aspects of truck operations. We are also subject to the Occupational Safety and Health Act, as amended ("OSHA"), with respect to our trucking operations.

Our trucking assets in Canada are subject to regulation by both federal and provincial transportation agencies in the provinces in which they are operated. These regulatory agencies do not set freight rates, but do establish and administer rules and regulations relating to other matters including equipment and driver licensing, equipment inspection, hazardous materials and safety.

Cross Border Regulation

As a result of our Canadian acquisitions and cross border activities, we are subject to regulatory matters including export licenses, tariffs, Canadian and U.S. customs and tax issues and toxic substance certifications. Regulations include the Short Supply Controls of the Export Administration Act, the

North American Free Trade Agreement and the Toxic Substances Control Act. Violations of these license, tariff and tax reporting requirements could result in the imposition of significant administrative, civil and criminal penalties. Furthermore, the failure to comply with U.S., Canadian, state, provincial and local tax requirements could lead to the imposition of additional taxes, interest and penalties.

Environmental, Health and Safety Regulation

General

Our operations involving the storage, treatment, processing, and transportation of liquid hydrocarbons including crude oil are subject to stringent federal, state, provincial and local laws and regulations governing the discharge of materials into the environment or otherwise relating to protection of the environment. As with the industry generally, compliance with these laws and regulations increases our overall cost of business, including our capital costs to construct, maintain and upgrade equipment and facilities. Failure to comply with these laws and regulations may result in the assessment of administrative, civil, and criminal penalties, the imposition of investigatory and remedial liabilities, and even the issuance of injunctions that may restrict or prohibit our operations. Environmental laws and regulations are subject to change, and we cannot provide any assurance that compliance with current and future laws and regulations will not have a material affect on our results of operations or earnings. A discharge of hazardous liquids into the environment could, to the extent such event is not insured, subject us to substantial expense, including both the cost to comply with applicable laws and regulations and any claims made by neighboring landowners and other third parties for personal injury and property damage.

Water

The Oil Pollution Act, as amended ("OPA"), was enacted in 1990 and amends provisions of the Federal Water Pollution Control Act of 1972, as amended ("Clean Water Act"), and other statutes as they pertain to prevention and response to oil spills. The OPA and analogous state and Canadian federal and provincial laws subject owners of facilities to strict, joint and potentially unlimited liability for containment and removal costs, natural resource damages, and certain other consequences of an oil spill, where such spill is into navigable waters, along shorelines or in the exclusive economic zone of the U.S. The OPA establishes a liability limit of $350 million for onshore facilities. However, a party cannot take advantage of this liability limit if the spill is caused by gross negligence or willful misconduct, resulted from a violation of a federal safety, construction, or operating regulation, or if there is a failure to report a spill or cooperate in the cleanup. We believe that we are in substantial compliance with applicable OPA requirements.

The Clean Water Act and analogous state and Canadian federal and provincial laws impose restrictions and strict controls regarding the discharge of pollutants into navigable waters of the United States and Canada, as well as state and provincial waters. Permits must be obtained to discharge pollutants into these waters. The Clean Water Act imposes substantial potential liability for the removal and remediation of pollutants. Although we can give no assurances, we believe that compliance with existing permits and compliance with foreseeable new permit requirements will not have a material adverse effect on our financial condition or results of operations.

Some states and all provinces maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. We believe that we are in substantial compliance with any such applicable state requirements.

In addition to the costs described above we could also be required to spend substantial sums to ensure the integrity of and upgrade our pipeline systems as a result of oil spills, and in some cases, we may take pipelines out of service if we believe the cost of upgrades will exceed the value of the pipelines. We cannot provide any assurance as to the ultimate amount or timing of future pipeline integrity expenditures for environmental compliance.

Air Emissions

Our operations are subject to the Federal Clean Air Act, as amended, and comparable state and provincial laws. We believe that our operations are in substantial compliance with these laws in those areas in which we operate.

Amendments to the Federal Clean Air Act enacted in 1990 (the "1990 Federal Clean Air Act Amendments") as well as changes to state implementation plans for controlling air emissions in regional non-attainment areas may require most industrial operations in the U.S. to incur capital expenditures in order to meet air emission control standards developed by the U.S. Environmental Protection Agency (the "EPA") and state environmental agencies. The 1990 Federal Clean Air Act Amendments also imposed an operating permit requirement for major sources of air emissions ("Title V permits"), which applies to some of our facilities. We may be required to incur certain capital expenditures in the next several years for air pollution control equipment in connection with obtaining or maintaining permits and approvals addressing air emission related issues. Although we can provide no assurance, we believe future compliance with the 1990 Federal Clean Air Act Amendments will not have a material adverse effect on our financial condition or results of operations.

The federal government of Canada recently ratified the Kyoto Protocol. As a result, the already stringent air emissions regulations will be replaced, by 2010, with even stricter guidelines. We are currently assessing the impact the Protocol will have on our operations.

Solid Waste

We generate wastes, including hazardous wastes, that are subject to the requirements of the federal Resource Conservation and Recovery Act ("RCRA") and comparable state and provincial laws. We are not required to comply with a substantial portion of the RCRA requirements because our operations generate primarily oil and gas wastes, which currently are excluded from consideration as RCRA hazardous wastes. However, it is possible that in the future the exclusion of oil and gas wastes from regulation as RCRA hazardous wastes may be eliminated, in which event, our wastes as well as the wastes of our competitors in the oil and gas industry will be subject to more rigorous and costly disposal requirements, resulting in additional capital expenditures or operating expenses for us and the industry in general.

Hazardous Substances

The Comprehensive Environmental Response, Compensation and Liability Act, as amended ("CERCLA"), also known as "Superfund," and comparable state and provincial laws impose liability, without regard to fault or the legality of the original act, on certain classes of persons that contributed to the release of a "hazardous substance" into the environment. These persons include the owner or operator of the site or sites where the release occurred and companies that disposed of, or arranged for the disposal of, the hazardous substances found at the site. Under CERCLA, such persons may be subject to strict joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain health studies. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. In the course of our ordinary operations, we may generate waste that falls within CERCLA's definition of a "hazardous substance," in which event, we may be held jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which such hazardous substances have been released into the environment.

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OSHA

We are subject to the requirements of OSHA, and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that certain information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities and citizens. We believe that our operations are in substantial compliance with OSHA requirements, including general industry standards, record keeping requirements and monitoring of occupational exposure to regulated substances. OSHA has also been given jurisdiction over enforcement of legislation designed to protect employees who provide evidence in fraud cases from retaliation by their employer.

Similar regulatory requirements exist in Canada under the federal and provincial Occupational Health and Safety Acts and related regulations. The agencies with jurisdiction under these regulationsare empowered to enforce them through inspection, audit, incident investigation or public or employee complaint. Additionally, recent legislation directly ties corporate accountability to the Criminal Code of Canada. This legislation will enable OH&S regulators to prosecute organizations and individuals criminally for violations of the regulations. We believe that our operations are in substantial compliance with applicable OH&S requirements.

Endangered Species Act

The federal Endangered Species Act, as amended ("ESA"), restricts activities that may affect endangered species or their habitats. Although certain of our facilities are in areas that may be designated as habitat for endangered species, we believe that we are in substantial compliance with the ESA. However, the discovery of previously unidentified endangered species could cause us to incur additional costs or operation restrictions or bans in the affected area, which costs, restrictions, or bans could have a material adverse effect on our financial condition or results of operations. Similar regulation (the Species Risk Act) applies to our Canadian operations.

Hazardous Materials Transportation Requirements

The DOT regulations affecting pipeline safety require pipeline operators to implement measures designed to reduce the environmental impact of oil discharge from onshore oil pipelines. These regulations require operators to maintain comprehensive spill response plans, including extensive spill response training for pipeline personnel. In addition, DOT regulations contain detailed specifications for pipeline operation and maintenance. We believe our operations are in substantial compliance with such regulations. See "—Regulation—Pipeline and Storage Regulation."

Environmental Remediation

We currently own or lease, and have in the past owned or leased, properties where hazardous liquids, including hydrocarbons, are being or have been handled. Although we have utilized operating and disposal practices that were standard in the industry at the time, hazardous liquids or associated generated wastes may have been disposed of or released on or under the properties owned or leased by us or on or under other locations where these wastes have been taken for disposal. In addition, many of these properties have been operated by third parties whose treatment and disposal or release of hazardous liquids or associated generated wastes was not under our control. These properties and the hazardous liquids or associated generated wastes disposed thereon may be subject to CERCLA, RCRA and analogous state and Canadian federal and provincial laws. Under such laws, we could be required to remove or remediate previously spilled hazardous liquids or associated generated wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated groundwater) or to perform remedial plugging operations to prevent future

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contamination. We are currently involved in remediation activities at a number of sites, which involve potentially significant expense.

Contamination resulting from spills of liquid hydrocarbons, including crude oil and associated generated wastes, is not unusual within the petroleum pipeline industry. Historic spills along our pipelines as well as at our terminalling and storage facilities as a result of past operations have resulted in contamination of the environment, including soils and groundwater. Properties acquired by us through acquisitions from predecessor operators, such as the properties recently acquired in the Link acquisition, oftentimes have similar impacts to soils and groundwater arising from historical operations on those properties. We are currently addressing site conditions, including soils and groundwater, at a number of our properties, including recently acquired properties, where historical or more recent operations by predecessor operators or us may have resulted in releases of hydrocarbons and other wastes. In addition, we have received contractual protections in the form of environmental indemnifications from several predecessor operators for properties acquired by us that are contaminated as a result of historical operations. These contractual indemnifications typically are subject to specific monetary and term limits that must be satisfied before indemnification will apply.

We may experience future releases of crude oil into the environment from our pipeline and storage operations, or discover past releases that were previously unidentified. Although we maintain an inspection program designed to prevent and, as applicable, to detect and address such releases promptly, damages and liabilities incurred due to any such environmental releases from our assets may substantially affect our business. At September 30, 2004, our reserve for environmental liabilities totaled approximately $21.4 million. Approximately $13.8 million of the reserve is related to liabilities assumed as part of the Link acquisition. Although we believe our reserve is adequate, no assurance can be given that any costs incurred in excess of this reserve would not have a material adverse effect on our financial condition, results of operations or cash flows.

For instance, in connection with the Link acquisition, we identified a number of known environmental claims and estimated an amount for potential claims that are currently unknown, for which we received a purchase price reduction from Link. A substantial portion of the known environmental liabilities are associated with the former Texas New Mexico ("TNM") pipeline assets. On the effective date of the acquisition, we and TNM entered into a cost-sharing agreement whereby, on a tiered basis, we will bear $11 million of the first $20 million of pre-May 1999 known environmental issues. We will also bear the first $25,000 per site for unknown sites (capped at 100 sites). TNM will pay all costs in excess of $20 million (excluding the deductible for unknown sites). TNM's obligations are guaranteed by Shell Oil Products.

In connection with the acquisition of certain Shell crude oil transmission and gathering assets in 2002, Shell purchased an environmental insurance policy covering known and unknown environmental matters associated with operations prior to closing. We are a named beneficiary under the policy, which has a $100,000 deductible per site, an aggregate coverage limit of $70 million, and expires in 2012. Shell has recently made a claim against the policy; however, we do not believe that the claim will substantially reduce our coverage under the policy.

Allocation of environmental liability is an issue negotiated in connection with each of our acquisition transactions. In each case, we make an assessment of potential environmental exposure based on available information. Based on that assessment and relevant economic and risk factors, we determine whether to negotiate an indemnity, what the terms of any indemnity should be (for example, minimum thresholds or caps on exposure) and whether to obtain insurance, if available. The acquisitions we completed in 2003 and 2004 include a variety of provisions dealing with the allocation of responsibility for environmental costs that range from no or limited indemnities from the sellers to indemnification from sellers with defined limitations on their maximum exposure. We have not obtained insurance for any of the conditions related to our 2003 acquisitions, and only limited

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circumstances for our 2004 acquisitions. We believe our exposure with respect to the acquired properties is reasonable in light of all the information available to us, but can give no assurance in that regard.

We believe that the environmental reserve described above is adequate, and in conjunction with our indemnification arrangements, should prevent remediation costs from having a material adverse effect on our financial condition, results of operations, or cash flows. Nevertheless, no assurances can be made that any costs incurred in excess of this reserve or outside of the indemnifications would not have a material adverse effect on our financial condition, results of operations, or cash flows.

Other assets we have acquired or will acquire in the future may have environmental remediation liabilities for which we are not indemnified. We have in the past experienced and in the future will likely experience releases of crude oil into the environment from our pipeline and storage operations, or discover releases that were previously unidentified. Although we maintain a program designed to prevent and, as applicable, to detect and address such releases promptly, damages and liabilities incurred due to environmental releases from our assets may substantially affect our business.

Operational Hazards and Insurance

Pipelines, terminals, trucks or other facilities or equipment may experience damage as a result of an accident or natural disaster. These hazards can cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage and suspension of operations. Since we and our predecessors commenced midstream crude oil activities in the early 1990s, we have maintained insurance of various types and varying levels of coverage that we consider adequate under the circumstances to cover our operations and properties. The insurance policies are subject to deductibles and retention levels that we consider reasonable and not excessive. However, such insurance does not cover every potential risk associated with operating pipelines, terminals and other facilities, including the potential loss of significant revenues. Consistent with insurance coverage generally available to the industry, our insurance policies provide limited coverage for losses or liabilities relating to pollution, with broader coverage for sudden and accidental occurrences. Over the last several years, our operations have expanded significantly, with total assets increasing over 300% since the end of 1998. At the same time that the scale and scope of our business activities have expanded, the breadth and depth of the available insurance markets have contracted. Notwithstanding what we believe is a favorable claims history, the overall cost of such insurance as well as the deductibles and overall retention levels that we maintain have increased. As a result, it is anticipated that we will elect to self insure more activities against certain of these operating hazards. Certain aspects of these conditions were exacerbated by the events of September 11, 2001, and their overall effect on the insurance industry have adversely impacted the availability and cost of certain coverages. Due to these events, insurers have excluded acts of terrorism and sabotage from our insurance policies and on certain of our key assets, we have elected to purchase a separate insurance policy for acts of terrorism and sabotage.

Since the terrorist attacks, the United States Government has issued numerous warnings that energy assets, including our nation's pipeline infrastructure, may be future targets of terrorist organizations. These developments expose our operations and assets to increased risks. We have instituted security measures and procedures in conformity with DOT guidance. We will institute, as appropriate, additional security measures or procedures indicated by the DOT or the Transportation Safety Administration. However, we cannot assure you that these or any other security measures would protect our facilities from a concentrated attack. Any future terrorist attacks on our facilities, those of our customers and, in some cases, those of our competitors, could have a material adverse effect on our business, whether insured or not.

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The occurrence of a significant event not fully insured, indemnified or reserved against, or the failure of a party to meet its indemnification obligations, could materially and adversely affect our operations and financial condition. We believe we are adequately insured for public liability and property damage to others with respect to our operations. We believe that our levels of coverage and retention are generally consistent with those of similarly situated companies in our industry. With respect to all of our coverage, no assurance can be given that we will be able to maintain adequate insurance in the future at rates we consider reasonable, or that we have established adequate reserves to the extent that such risks are not insured.

Title to Properties and Rights-of-Way

We believe that we have satisfactory title to all of our assets. Although title to such properties are subject to encumbrances in certain cases, such as customary interests generally retained in connection with acquisition of real property, liens related to environmental liabilities associated with historical operations, liens for current taxes and other burdens and minor easements, restrictions and other encumbrances to which the underlying properties were subject at the time of acquisition by our predecessor or us, we believe that none of these burdens will materially detract from the value of such properties or from our interest therein or will materially interfere with their use in the operation of our business.

Substantially all of our pipelines are constructed on rights-of-way granted by the apparent record owners of such property and, in some instances, such rights-of-way are revocable at the election of the grantor. In many instances, lands over which rights-of-way have been obtained are subject to prior liens that have not been subordinated to the right-of-way grants. In some cases, not all of the apparent record owners have joined in the right-of-way grants, but in substantially all such cases, signatures of the owners of majority interests have been obtained. We have obtained permits from public authorities to cross over or under, or to lay facilities in or along water courses, county roads, municipal streets and state highways, and in some instances, such permits are revocable at the election of the grantor. We have also obtained permits from railroad companies to cross over or under lands or rights-of-way, many of which are also revocable at the grantor's election. In some cases, property for pipeline purposes was purchased in fee. All of the pump stations are located on property owned in fee or property under long-term leases. In certain states and under certain circumstances, we have the right of eminent domain to acquire rights-of-way and lands necessary for our common carrier pipelines.

Some of the leases, easements, rights-of-way, permits and licenses transferred to us, upon our formation in 1998 and in connection with acquisitions we have made since that time, required the consent of the grantor to transfer such rights, which in certain instances is a governmental entity. We believe that we have obtained such third party consents, permits and authorizations as are sufficient for the transfer to us of the assets necessary for us to operate our business in all material respects as described in this report. With respect to any consents, permits or authorizations that have not yet been obtained, we believe that such consents, permits or authorizations will be obtained within a reasonable period, or that the failure to obtain such consents, permits or authorizations will have no material adverse effect on the operation of our business.

Employees

To carry out our operations, our general partner or its affiliates employed approximately 1,950 employees at September 30, 2004. None of the employees of our general partner were represented by labor unions, and our general partner considers its employee relations to be good.

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Litigation

Alfons Sperber v. Plains Resources Inc., et al. On December 18, 2003, a putative class action lawsuit was filed in the Delaware Chancery Court, New Castle County, entitled Alfons Sperber v. Plains Resources Inc., et al. This suit, brought on behalf of a putative class of Plains All American Pipeline, L.P. common unitholders, asserts breach of fiduciary duty and breach of contract claims against us, Plains AAP, L.P., and Plains All American GP LLC and its directors, as well as breach of fiduciary duty claims against Plains Resources Inc. and its directors. The complaint seeks to enjoin or rescind a proposed acquisition of all of the outstanding stock of Plains Resources Inc., as well as declaratory relief, an accounting, disgorgement and the imposition of a constructive trust, and an award of damages, fees, expenses and costs, among other things. This lawsuit has been settled in principle, subject to the preparation and execution of appropriate settlement documentation and court approval.

Environmental. We may experience future releases of crude oil into the environment from our pipeline and storage operations, or discover past releases that were previously unidentified. Although we maintain an inspection program designed to prevent and, as applicable, to detect and address such releases promptly, damages and liabilities incurred due to any such environmental releases from our assets may substantially affect our business. At September 30, 2004, our reserve for environmental liabilities totaled approximately $21.4 million. Approximately $13.8 million of the reserve is related to liabilities assumed as part of the Link acquisition. Although we believe our reserve is adequate, no assurance can be given that any costs incurred in excess of this reserve would not have a material adverse effect on our financial condition, results of operations or cash flows.

Other. We, in the ordinary course of business, are a claimant and /or a defendant in various other legal proceedings. We do not believe that the outcome of these other legal proceedings, individually and in the aggregate, will have a materially adverse effect on our financial condition, results of operations or cash flows.

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Unauthorized Trading Loss

In November 1999, we discovered that a former employee had engaged in unauthorized trading activity that resulted in significant losses and litigation and had a temporary, but material adverse impact on our liquidity and our relationship with our customers. A full investigation into the unauthorized trading activities by outside legal counsel and independent accountants and consultants determined that the vast majority of the losses occurred in 1999, but also extended into 1998 and required restatements of our financial statements for the applicable periods. Including litigation settlement costs, the aggregate losses associated with this event totaled approximately $181 million. All of the cases were settled and paid. Additionally, based on recommendations from experts involved in the investigation, we made significant enhancements to our systems, policies and procedures and developed and adopted a written policy document and manual of procedures designed to enhance our processes and procedures and improve our ability to detect any activity that might occur at an early stage. We can give no assurance that the above steps will serve to detect and prevent all violations of our trading policy; however, we believe that such steps substantially reduce the possibility of a recurrence of unauthorized trading activities, and that any unauthorized trading that does occur would be detected at an early stage.

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MANAGEMENT

Partnership Management and Governance

As is the case with many publicly traded partnerships, we do not directly have officers, directors or employees. Our operations and activities are managed by the general partner of our general partner, Plains All American GP LLC, which employs our management and operational personnel. References to our general partner, unless the context otherwise requires, include Plains All American GP LLC. References to our officers, directors and employees are references to the officers, directors and employees of Plains All American GP LLC (or, in the case of our Canadian operations, PMC (Nova Scotia) Company).

Our general partner manages our operations and activities. Unitholders do not directly or indirectly participate in our management or operation. Our general partner owes a fiduciary duty to the unitholders, as limited by our partnership agreement. As a general partner, our general partner is liable for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made specifically non-recourse to it. Whenever possible, our general partner intends to incur indebtedness or other obligations on a non-recourse basis.

Our partnership agreement provides that the general partner will manage and operate us and that, unlike holders of common stock in a corporation, unitholders will have only limited voting rights on matters affecting our business or governance. Specifically, our partnership agreement defines "Board of Directors" to mean the board of directors of Plains All American GP LLC, which is elected by the members of Plains All American GP LLC, and not by the unitholders. Thus, the corporate governance of Plains All American GP LLC is, in effect, the corporate governance of our partnership, subject in all cases to any specific unitholder rights contained in our partnership agreement. Because we are a limited partnership, the new listing standards of the New York Stock Exchange do not require that we or our general partner have a majority of independent directors or a nominating or compensation committee of the board of directors.

We have an audit committee that reviews our external financial reporting, engages our independent auditors and reviews the adequacy of our internal accounting controls. The Board of Directors has determined that (i) each member of our audit committee is "independent" under applicable New York Stock Exchange Rules and (ii) that each member of our audit committee is an "Audit Committee Financial Expert," as that term is defined in Item 401 of Regulation S-K. The members of our audit committee and other committees are indicated in the table below.

In determining the independence of the members of our audit committee, the Board of Directors considered the relationships described below:

Mr. Everardo Goyanes, the Chairman of our Audit Committee, is the Chief Executive Officer of Liberty Energy Corporation ("LEC"), a subsidiary of Liberty Mutual Insurance Company. Mr. Goyanes is an employee of Liberty Mutual Insurance Company. LEC makes investments in producing properties, from some of which Plains Marketing, L.P. buys the production. LEC does not operate the properties in which it invests. Plains Marketing pays the same amount per barrel to LEC that it pays to other interest owners in the properties. In 2003, the amount paid to LEC by Plains Marketing was approximately $1,085,000 ($974,000 net of severance taxes),

Mr. J. Taft Symonds, a member of our Audit Committee, is a director and the non-executive Chairman of the Board of Tetra Technologies, Inc. ("Tetra"). A subsidiary of Tetra owns crude oil producing properties, from some of which Plains Marketing buys the production. We paid approximately $7.9 million to the Tetra subsidiary in 2003. Until July 2004, Mr. Symonds was also a director of Plains Resources Inc., with whom Plains Marketing has a marketing arrangement. We paid approximately $25.7 million to Plains Resources in 2003, and recognized segment profit of approximately $0.2 million. Mr. Symonds was not and is not an officer of Tetra or Plains Resources,

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and does not participate in operational decision making, including decisions concerning selection of crude oil purchasers or entering into sales or marketing arrangements.

We have a compensation committee, which reviews and makes recommendations regarding the compensation for the executive officers and administers our equity compensation plans for officers and key employees. We also have a governance committee that periodically reviews our governance guidelines. In addition, our partnership agreement provides for the establishment/activation of a conflicts committee as circumstances warrant to review conflicts of interest between us and our general partner or the owners of our general partner. Such a committee would consist of a minimum of two members, none of whom are officers or employees of our general partner or directors, officers or employees of its affiliates. Any matters approved by the conflicts committee will be conclusively deemed to be fair and reasonable to us, approved by all of our partners, and not a breach by our general partner of any duties owed to us or our unitholders.

Our committee charters and governance guidelines are available on our website at www.paalp.com.

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Directors and Executive Officers

The following table sets forth certain information with respect to the executive officers and members of the Board of Directors of our general partner. Directors are elected annually thereafter. Certain owners of our general partner each have the right to separately designate a member of our board. Such designees are indicated in the footnote to the following table.

Name	Age (as of 11/30/04)	Position with Our General Partner
Greg L. Armstrong⁽¹⁾	46	Chairman of the Board, Chief Executive Officer and Director
Harry N. Pefanis	47	President and Chief Operating Officer
Phillip D. Kramer	48	Executive Vice President and Chief Financial Officer
George R. Coiner	54	Senior Group Vice President
W. David Duckett	49	President—PMC (Nova Scotia) Company
Mark F. Shires	47	Senior Vice President—Operations
Alfred A. Lindseth	35	Senior Vice President—Technology, Process & Risk Management
Lawrence J. Dreyfuss	50	Vice President, Associate General Counsel and Assistant Secretary; Vice President, General Counsel and Secretary of PMC (Nova Scotia) Company (the general partner of Plains Marketing Canada, L.P.)
James B. Fryfogle	53	Vice President—Lease Operations
Jim G. Hester	45	Vice President—Acquisitions
Tim Moore	47	Vice President, General Counsel and Secretary
John F. Russell	55	Vice President—Pipeline Operations
Al Swanson	40	Vice President and Treasurer
Tina L. Val	35	Vice President—Accounting and Chief Accounting Officer
Troy E. Valenzuela	43	Vice President—Environmental, Health and Safety
John P. vonBerg	50	Vice President—Trading
David N. Capobianco⁽¹⁾	35	Director and Member of Compensation Committee
Everardo Goyanes	60	Director and Member of Audit* Committee
Gary R. Petersen⁽¹⁾	58	Director and Member of Compensation* Committee
John T. Raymond⁽¹⁾	34	Director
Robert V. Sinnott⁽¹⁾	55	Director and Member of Compensation Committee
Arthur L. Smith	52	Director and Member of Audit and Governance* Committees
J. Taft Symonds	65	Director and Member of Governance and Audit Committees

*: Indicates chairman of committee
⁽¹⁾: The Amended and Restated Limited Liability Company Agreement of Plains All American GP LLC (as amended, the "LLC Agreement") specifies that the Chief Executive Officer of the general partner will be a member of the board of directors. The LLC Agreement also provides that certain of the owners of our general partner have the right to designate a member of our board of directors. Mr. Capobianco has been designated by Plains Holdings Inc. Mr. Petersen has been designated by E-Holdings III, L.P., an affiliate of EnCap Investments L.P., of which he is a Managing Director. Mr. Raymond has been

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designated by Sable Investments, L.P. Sable Investments, L.P. is controlled by James M. Flores, a director of Vulcan Energy Corporation and also the Chairman, President and Chief Executive Officer of PXP. Mr. Sinnott has been designated by KAFU Holdings, L.P., which is affiliated with Kayne Anderson Investment Management, Inc., of which he is a Vice President. See "Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters—Beneficial Ownership of General Partner Interest."

Greg L. Armstrong has served as Chairman of the Board and Chief Executive Officer since our formation. He has also served as a director of our general partner or former general partner since our formation. In addition, he was President, Chief Executive Officer and director of Plains Resources from 1992 to May 2001. He previously served Plains Resources as: President and Chief Operating Officer from October to December 1992; Executive Vice President and Chief Financial Officer from June to October 1992; Senior Vice President and Chief Financial Officer from 1991 to 1992; Vice President and Chief Financial Officer from 1984 to 1991; Corporate Secretary from 1981 to 1988; and Treasurer from 1984 to 1987. Mr. Armstrong is also a director of Varco International, Inc.

Harry N. Pefanis has served as President and Chief Operating Officer since our formation. He was also a director of our former general partner. In addition, he was Executive Vice President—Midstream of Plains Resources from May 1998 to May 2001. He previously served Plains Resources as: Senior Vice President from February 1996 until May 1998; Vice President—Products Marketing from 1988 to February 1996; Manager of Products Marketing from 1987 to 1988; and Special Assistant for Corporate Planning from 1983 to 1987. Mr. Pefanis was also President of several former midstream subsidiaries of Plains Resources until our formation in 1998.

Phillip D. Kramer has served as Executive Vice President and Chief Financial Officer since our formation. In addition, he was Executive Vice President and Chief Financial Officer of Plains Resources from May 1998 to May 2001. He previously served Plains Resources as: Senior Vice President and Chief Financial Officer from May 1997 until May 1998; Vice President and Chief Financial Officer from 1992 to 1997; Vice President from 1988 to 1992; Treasurer from 1987 to March 2001; and Controller from 1983 to 1987.

George R. Coiner has served as Senior Group Vice President since February 2004 and as Senior Vice President from our formation to February 2004. In addition, he was Vice President of Plains Marketing & Transportation Inc., a former midstream subsidiary of Plains Resources from November 1995 until our formation in 1998. Prior to joining Plains Marketing & Transportation Inc., he was Senior Vice President, Marketing with Scurlock Permian Corp.

W. David Duckett has been President of PMC (Nova Scotia) Company since June 2003, and Executive Vice President of PMC (Nova Scotia) Company from July 2001 to June 2003. Mr. Duckett was previously with CANPET Energy Group Inc. since 1985, where he served in various capacities, including most recently as President, Chief Executive Officer and Chairman of the Board.

Mark F. Shires has served as Senior Vice President—Operations since June 2003 and as Vice President—Operations from August 1999 to June 2003. He served as Manager of Operations from April 1999 to August 1999. In addition, he was a business consultant from 1996 until April 1999. He served as a consultant to Plains Marketing & Transportation Inc. and Plains All American Pipeline, LP from May 1998 until April 1999. He previously served as President of Plains Terminal & Transfer Corporation, a former midstream subsidiary of Plains Resources, from 1993 to 1996.

Alfred A. Lindseth has served as Senior Vice President—Technology, Process & Risk Management since June 2003 and as Vice President—Administration from March 2001 to June 2003. He served as Risk Manager from March 2000 to March 2001. He previously served PricewaterhouseCoopers LLP in its Financial Risk Management Practice section as a Consultant from 1997 to 1999 and as Principal Consultant from 1999 to March 2000. He also served GSC Energy, an energy risk management brokerage and consulting firm, as Manager of its Oil & Gas Hedging Program from 1995 to 1996 and as Director of Research and Trading from 1996 to 1997.

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Lawrence J. Dreyfuss has served as Vice President, Associate General Counsel and Assistant Secretary of our general partner since February 2004 and as Associate General Counsel and Assistant Secretary of our general partner from June 2001 to February 2004 and held a senior management position in the Law Department since May 1999. In addition, he was a Vice President of Scurlock Permian LLC from 1987 to 1999.

James B. Fryfogle has served as Vice President—Lease Operations since July 2004. Prior to joining PAA in January 2004, Mr. Fryfogle served as Manager of Crude Supply and Trading for Marathon Ashland Petroleum. Mr. Fryfogle had held numerous positions of increasing responsibility with Marathon Ashland Petroleum or its affiliates or predecessors since 1975.

Jim G. Hester has served as Vice President—Acquisitions since March 2002. Prior to joining us, Mr. Hester was Senior Vice President—Special Projects of Plains Resources. From May 2001 to December 2001, he was Senior Vice President—Operations for Plains Resources. From May 1999 to May 2001, he was Vice President—Business Development and Acquisitions of Plains Resources. He was Manager of Business Development and Acquisitions of Plains Resources from 1997 to May 1999, Manager of Corporate Development from 1995 to 1997 and Manager of Special Projects from 1993 to 1995. He was Assistant Controller from 1991 to 1993, Accounting Manager from 1990 to 1991 and Revenue Accounting Supervisor from 1988 to 1990.

Tim Moore has served as Vice President, General Counsel and Secretary since May 2000. In addition, he was Vice President, General Counsel and Secretary of Plains Resources from May 2000 to May 2001. Prior to joining Plains Resources, he served in various positions, including General Counsel—Corporate, with TransTexas Gas Corporation from 1994 to 2000. He previously was a corporate attorney with the Houston office of Weil, Gotshal & Manges LLP. Mr. Moore also has seven years of energy industry experience as a petroleum geologist.

John F. Russell has served as Vice President—Pipeline Operations since July 2004. Prior to joining PAA, Mr. Russell served as Vice President of Business Development & Joint Interest for ExxonMobil Pipeline Company. Mr. Russell had held numerous positions of increasing responsibility with ExxonMobil Pipeline Company or its affiliates or predecessors since 1974.

Al Swanson has served as Vice President and Treasurer since February 2004 and as Treasurer from May 2001 to February 2004. In addition, he held several finance related positions at Plains Resources including Treasurer from February 2001 to May 2001 and Director of Treasury from November 2000 to February 2001. Prior to joining Plains Resources, he served as Treasurer of Santa Fe Snyder Corporation from 1999 to October 2000 and in various capacities at Snyder Oil Corporation including Director of Corporate Finance from 1998, Controller—SOCO Offshore, Inc. from 1997, and Accounting Manager from 1992. Mr. Swanson began his career with Apache Corporation in 1986 serving in internal audit and accounting.

Tina L. Val has served as Vice President—Accounting and Chief Accounting Officer since June 2003. She served as Controller from April 2000 until she was elected to her current position. From January 1998 to January 2000, Ms. Val served as a consultant to Conoco de Venezuela S.A. She previously served as Senior Financial Analyst for Plains Resources from October 1994 to July 1997.

Troy E. Valenzuela has served as Vice President—Environmental, Health and Safety, or EH&S, since July 2002, and has had oversight responsibility for the environmental, safety and regulatory compliance efforts of us and our predecessors for the last 12 years. He was Director of EH&S with Plains Resources from January 1996 to June 2002, and Manager of EH&S from July 1992 to December 1995. Prior to his time with Plains Resources, Mr. Valenzuela spent seven years with Chevron USA Production Company in various EH&S roles.

John P. vonBerg has served as Vice President of Trading since May 2003 and Director of these activities since joining us in January of 2002. He was with Genesis Energy in differing capacities as a

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Director, Vice Chairman, President and CEO from 1996 through 2001, and from 1993 to 1996 he served as a Vice President and a Crude Oil Manager for Phibro Energy USA. Mr. VonBerg began his career with Marathon Oil Company, spending 13 years in various disciplines.

David N. Capobianco has served as a director of our general partner since July 2004. Mr. Capobianco is a member of the board of directors of Vulcan Energy Corporation and a Managing Director of Vulcan Capital, an affiliate of Vulcan Inc., where he has been employed since April 2003. Previously, he served as a Vice President of Greenhill Capital from July 2001 to April 2003 and a Vice President of Harvest Partners from July 1995 to January 2001. Mr. Capobianco holds a BA in economics from Duke University and an MBA from Harvard Business School.

Everardo Goyanes has served as a director of our general partner or former general partner since May 1999. Mr. Goyanes has been President and Chief Executive Officer of Liberty Energy Holdings LLC (an energy investment firm) since May 2000. From 1999 to May 2000, he was a financial consultant specializing in natural resources. From 1989 to 1999, he was Managing Director of the Natural Resources Group of ING Barings Furman Selz (a banking firm). He was a financial consultant from 1987 to 1989 and was Vice President—Finance of Forest Oil Corporation from 1983 to 1987. Mr. Goyanes received a BA in Economics from Cornell University and a Masters degree in Finance (honors) from Babson Institute.

Gary R. Petersen has served as a director since June 2001. Mr. Petersen co-founded EnCap Investments L.P. (an investment management firm) and has been a Managing Director and principal of the firm since 1988. He had previously served as Senior Vice President and Manager of the Corporate Finance Division of the Energy Banking Group for RepublicBank Corporation. Prior to his position at RepublicBank, he was Executive Vice President and a member of the Board of Directors of Nicklos Oil & Gas Company in Houston, Texas from 1979 to 1984. He served from 1970 to 1971 in the U.S. Army as a First Lieutenant in the Finance Corps and as an Army Officer in the National Security Agency. He is also a director of Equus II Incorporated.

John T. Raymond has served as a director since June 2001. He has been a director and the Chief Executive Officer of Vulcan Energy Corporation since July 2004. Mr. Raymond has served as President and Chief Executive Officer of Plains Resources since December 2002. Prior thereto, Mr. Raymond served as Executive Vice President and Chief Operating Officer of Plains Resources from May 2001 to November 2001 and President and Chief Operating Officer since November 2001. Mr. Raymond also served as President and Chief Operating Officer of Plains Exploration and Production from December 2002 to March 2004. He was Director of Corporate Development of Kinder Morgan, Inc. from January 2000 to May 2001. He served as Vice President of Corporate Development of Ocean Energy, Inc. from April 1998 to January 2000. He was Vice President of Howard Weil Labouisse Friedrichs, Inc. from 1992 to April 1998.

Robert V. Sinnott has served as a director of our general partner or former general partner since September 1998. Mr. Sinnott has been a Senior Managing Director of Kayne Anderson Capital Advisors, L.P. (an investment management firm) since 1996, and was a Managing Director from 1992 to 1996. He is also a vice president of Kayne Anderson Investment Management Inc., the general partner of Kayne Anderson Capital Advisors, L.P. He was Vice President and Senior Securities Officer of the Investment Banking Division of Citibank from 1986 to 1992. He is also a director of Glacier Water Services, Inc. (a vended water company). Mr. Sinnott was previously a director of Plains Resources.

Arthur L. Smith has served as a director of our general partner or former general partner since February 1999. Mr. Smith is Chairman and CEO of John S. Herold, Inc. (a petroleum research and consulting firm), a position he has held since 1984. From 1976 to 1984 Mr. Smith was a securities analyst with Argus Research Corp., The First Boston Corporation and Oppenheimer & Co., Inc. Mr. Smith has prior public board experience with Pioneer Natural Resources, Cabot Oil & Gas Corporation and Evergreen Resources, Inc. Mr. Smith holds the CFA designation. He serves on the

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board of non-profit Dress for Success Houston and the Board of Visitors for the Duke Nicholas School of the Environment and Earth Sciences. Mr. Smith received a BA from Duke University and an MBA from NYU's Stern School of Business.

J. Taft Symonds has served as a director since June 2001. Mr. Symonds is Chairman of the Board of Symonds Trust Co. Ltd. (an investment firm) and Chairman of the Board of Tetra Technologies, Inc. (an oilfield services firm). From 1978 to 2004 he was Chairman of the Board and Chief Financial Officer of Maurice Pincoffs Company, Inc. (an international marketing firm). Mr. Symonds was previously a director of Plains Resources. Mr. Symonds has a background in both investment and commercial banking, including merchant banking in New York, London and Hong Kong with Paine Webber Jackson & Curtis, Robert Fleming Group and Banque de la Societe Financiere Europeenne. He is a director of Intercorr International and President of the Houston Arboretum and Nature Center. Mr. Symonds received a BA from Stanford University and an MBA from Harvard.

The following table sets forth certain information with respect to other members of our management team and officers of the general partner of our Canadian operating partnership:

Name		Age (as of 11/30/04)	Position with Our General Partner/Canadian General Partner
Management Team/Other Officers:
	A. Patrick Diamond	31	Manager—Special Projects
Canadian Officers:
	D. Mark Alenius	45	Vice President and Chief Financial Officer of PMC (Nova Scotia) Company
	Ralph R. Cross	49	Vice President—Business Development of PMC (Nova Scotia) Company
	Ronald H. Gagnon	46	Vice President—Operations of PMC (Nova Scotia) Company
	M.D. (Mike) Hallahan	44	Vice President—Crude Oil of PMC (Nova Scotia) Company
	Richard (Rick) Henson	50	Vice President—Corporate Services of PMC (Nova Scotia) Company
	Ron F. Wunder	36	Vice President—LPG of PMC (Nova Scotia) Company

A. Patrick Diamond has served as Manager—Special Projects since June 2001. In addition, he was Manager—Special Projects of Plains Resources from August 1999 to June 2001. Prior to joining Plains Resources, Mr. Diamond served Salomon Smith Barney Inc. in its Global Energy Investment Banking Group as an Associate from July 1997 to May 1999 and as a Financial Analyst from July 1994 to June 1997.

D. Mark Alenius has served as Vice President and Chief Financial Officer of PMC (Nova Scotia) Company since November 2002. In addition, Mr. Alenius was Managing Director, Finance of PMC (Nova Scotia) Company from July 2001 to November 2002. Mr. Alenius was previously with CANPET Energy Group Inc. where he served as Vice President, Finance, Secretary and Treasurer, and was a member of the Board of Directors. Mr. Alenius joined CANPET in February 2000. Prior to joining CANPET Energy, Mr. Alenius briefly served as Chief Financial Officer of Bromley-Marr ECOS Inc., a manufacturing and processing company, from January to July 1999. Mr. Alenius was previously with Koch Industries, Inc.'s Canadian group of businesses, where he served in various capacities, including most recently as Vice-President, Finance and Chief Financial Officer of Koch Pipelines Canada, Ltd.

Ralph R. Cross has been Vice President of Business Development of PMC (Nova Scotia) Company since July 2001. Mr. Cross was previously with CANPET Energy Group Inc. since 1992, where he served in various capacities, including most recently as Vice President of Business Development.

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Ronald H. Gagnon has been Vice President, Operations of PMC (Nova Scotia) Company since January 2004, Managing Director, Information and Transportation Services from June 2003 to January 2004 and Director, Information Services from July 2001 to May 2003. Mr. Gagnon was previously with CANPET Energy Group Inc. since 1987, where he served in various capacities, including Vice President, Producer Services.

M.D. (Mike) Hallahan has served as Vice President, Crude Oil of PMC (Nova Scotia) Company since February 2004 and Managing Director, Facilities from July, 2001 to February, 2004. He was previously with CANPET Energy Group inc. where he served in various capacities since 1996, most recently General Manager, Facilities.

Richard (Rick) Henson joined PMC (Nova Scotia) Company in December 2004 as Vice President of Corporate Services. Mr. Henson was previously with Nova Chemicals Corporation, serving in various executive positions from 1999 through 2004, including Vice President, Petrochemicals and Feedstocks, and Vice President, Ethylene and Petrochemicals Business.

Ron F. Wunder has served as Vice President, LPG of PMC (Nova Scotia) Company since February 2004 and as Managing Director, Crude Oil from July 2001 to February 2004. He was previously with CANPET Energy Group Inc. since 1992, where he served in various capacities, including most recently as General Manager, Crude Oil.

Executive Compensation

The following table sets forth certain compensation information for our Chief Executive Officer and the four other most highly compensated executive officers in 2003 (the "Named Executive Officers"). Messrs. Armstrong, Pefanis and Kramer were compensated by Plains Resources prior to July 2001. However, we reimburse our general partner and its affiliates (and, for a portion of 2001, we reimbursed our former general partner and its affiliates, which included Plains Resources) for expenses incurred on our behalf, including the costs of officer compensation allocable to us. The Named Executive Officers have also received certain equity-based awards from our general partner and from our former general partner and its affiliates, which awards (other than awards under the Long-Term

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Incentive Plan) are not subject to reimbursement by us. See "—Long-Term Incentive Plan" and "Certain Relationships and Related Transactions—Transactions with Related Parties."

		Annual Compensation									Long-Term Compensation
Name and Principal Position								Other Compensation			Long-Term Compensation
Name and Principal Position	Year	Salary			Bonus			Other Compensation			LTIP Payout
Greg L. Armstrong Chairman and CEO	2003 2002 2001	$	330,000 330,000 165,000	⁽¹⁾	$	1,000,000 600,000 450,000		$	12,000 11,000 —	⁽²⁾ ⁽²⁾ ⁽¹⁾⁽²⁾	$	— — —
Harry N. Pefanis President and COO	2003 2002 2001	$	235,000 235,000 117,500	⁽¹⁾	$	800,000 475,000 350,000		$	12,000 11,000 —	⁽²⁾ ⁽²⁾ ⁽¹⁾⁽²⁾	$	452,400 — —
Phillip D. Kramer Executive V.P. and CFO	2003 2002 2001	$	200,000 200,000 100,000	⁽¹⁾	$	500,000 275,000 100,000		$	12,000 11,000 —	⁽²⁾ ⁽²⁾ ⁽¹⁾⁽²⁾	$	— — —
George R. Coiner Senior Group Vice President	2003 2002 2001	$	200,000 200,000 175,000		$	719,600 451,000 430,100	⁽³⁾ ⁽⁴⁾ ⁽⁵⁾	$	12,000 11,000 10,500	⁽²⁾ ⁽²⁾ ⁽²⁾	$	226,200 — —
W. David Duckett⁽⁶⁾ President—PMC (Nova Scotia Company)	2003 2002 2001	$	190,658 163,891 80,020		$	724,883 270,070 15,182		$	— — —		$	— — —

⁽¹⁾: Salary amounts shown for the year 2001 reflect compensation paid by our general partner and reimbursed by us for the last six months of 2001. Until July 2001, Messrs. Armstrong, Pefanis and Kramer were employed and compensated by Plains Resources, which owned our former general partner. We reimbursed Plains Resources for the portion of their compensation allocable to us. In 2001, approximately $218,000, $655,000 and $127,000 was reimbursed to our former general partner and its affiliates for salary and bonus (for the year 2000) for the services of Messrs. Armstrong, Pefanis and Kramer, respectively. See "Certain Relationships and Related Transactions—Transactions with Related Parties."
⁽²⁾: Prior to the transfer of a majority of our general partner interest in 2001 (the "General Partner Transition"), Plains Resources matched 100% of employees' contribution to its 401(k) Plan (subject to certain limitations in the plan), with such matching contribution being made 50% in cash and 50% in common stock of Plains Resources (the number of shares for the stock match being based on the market value of the Common Stock at the time the shares were granted). After the General Partner Transition, our general partner matches 100% of employees' contributions to its 401(k) Plan in cash, subject to certain limitations in the plan.
⁽³⁾: Includes quarterly bonuses aggregating $469,600 and an annual bonus of $250,000. The annual bonus is payable 60% in 2004, 20% in 2005 and 20% in 2006.
⁽⁴⁾: Includes quarterly bonuses aggregating $361,000 and an annual bonus of $90,000. The annual bonus was paid 60% in 2003, and will be paid 20% in 2004 and 20% in 2005.
⁽⁵⁾: Includes quarterly bonuses aggregating $310,100 and an annual bonus of $120,000. The annual bonus was paid 60% in 2002, and 20% in 2003, and 20% will be paid in 2004.
⁽⁶⁾: Salary and bonus for Mr. Duckett are presented in U.S. dollar equivalent, based on the exchange rates in effect on the dates payments were made. Mr. Duckett commenced employment on July 1, 2001.

Employment Contracts and Termination of Employment and Change-in-Control Arrangements

Messrs. Armstrong and Pefanis have employment agreements with our general partner. Mr. Armstrong is employed as Chairman and Chief Executive Officer. The initial three-year term of Mr. Armstrong's employment agreement commenced on June 30, 2001, and is automatically extended for one year on June 30 of each year (such that the term is reset to three years) unless Mr. Armstrong receives notice from the Chairman of the Compensation Committee that the Board of Directors has elected not to extend the agreement. Mr. Armstrong has agreed, during the term of the agreement and

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for five years thereafter, not to disclose (subject to typical exceptions) any confidential information obtained by him while employed under the agreement. The agreement provides for a current base salary of $330,000 per year, subject to annual review. If Mr. Armstrong's employment is terminated without cause, he will be entitled to receive an amount equal to his annual base salary plus his highest annual bonus, multiplied by the lesser of (i) the number of years (including fractional years) remaining on the agreement and (ii) two. If Mr. Armstrong terminates his employment as a result of a change in control he will be entitled to receive an amount equal to three times the aggregate of his annual base salary and bonus. Under Mr. Armstrong's agreement, a "change of control" is defined to include (i) the acquisition by an entity or group (other than Plains Resources and its wholly owned subsidiaries) of 50% or more of our general partner or (ii) the existing owners of our general partner ceasing to own more than 50% of our general partner. If Mr. Armstrong's employment is terminated because of his death, a lump sum payment will be paid to his designee equal to his annual salary plus his highest annual bonus, multiplied by the lesser of (i) the number of years (including fractional years) remaining on the agreement and (ii) two. Under the agreement, Mr. Armstrong will be reimbursed for any excise tax due as a result of compensation (parachute) payments.

Mr. Pefanis is employed as President and Chief Operating Officer. The initial three-year term of Mr. Pefanis' employment agreement commenced on June 30, 2001, and is automatically extended for one year on June 30 of each year (such that the term is reset to three years) unless Mr. Pefanis receives notice from the Chairman of the Board of Directors that the Board has elected not to extend the agreement. Mr. Pefanis has agreed, during the term of the agreement and for one year thereafter, not to disclose (subject to typical exceptions) any confidential information obtained by him while employed under the agreement. The agreement provides for a current base salary of $235,000 per year, subject to annual review. The provisions in Mr. Pefanis' agreement with respect to termination, change in control and related payment obligations are substantially similar to the parallel provisions in Mr. Armstrong's agreement.

1998 Long-Term Incentive Plan

Our general partner has adopted the Plains All American GP LLC 1998 Long-Term Incentive Plan (the "LTIP") for employees and directors of our general partner and its affiliates who perform services for us. The LTIP consists of two components, a restricted ("phantom") unit plan and a unit option plan. The LTIP currently permits the grant of phantom units and unit options covering an aggregate of 1,425,000 common units delivered upon vesting of such phantom units or unit options. No options have been granted under the unit option plan. The plan is administered by the Compensation Committee of our general partner's board of directors. Our general partner's board of directors in its discretion may terminate the LTIP at any time with respect to any common units for which a grant has not yet been made. Our general partner's board of directors also has the right to alter or amend the LTIP or any part of the plan from time to time, including, subject to any applicable NYSE listing requirements, increasing the number of common units with respect to which awards may be granted; provided, however, that no change in any outstanding grant may be made that would materially impair the rights of the participant without the consent of such participant.

Restricted Unit Plan. A restricted unit is a "phantom" unit that entitles the grantee to receive, upon the vesting of the phantom unit, a common unit (or cash equivalent, depending on the terms of the grant). A substantial number of phantom units have vested in 2003 and 2004. As of September 30, 2004, giving effect to vested grants, grants of approximately 134,000 unvested phantom units remain outstanding to employees, officers and directors of our general partner. The Compensation Committee may, in the future, make additional grants under the plan to employees and directors containing such terms as the Compensation Committee shall determine.

If a grantee terminates employment or membership on the board for any reason, the grantee's phantom units will be automatically forfeited unless, and to the extent, the Compensation Committee

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provides otherwise. Vested phantom units may be satisfied in common units or cash equivalents. Common units to be delivered upon the vesting of rights may be common units acquired by our general partner in the open market or in private transactions, common units already owned by our general partner, or any combination of the foregoing. Our general partner will be entitled to reimbursement by us for the cost incurred in acquiring common units. In addition, over the term of the plan we may issue up to 975,000 new common units to satisfy delivery obligations under the grants, less any common units issued upon exercise of unit options under the plan (see below). When we issue new common units upon vesting of the phantom units, the total number of common units outstanding increases. The compensation committee, in its discretion, may grant tandem distribution equivalent rights with respect to phantom units.

Other than grants to directors (discussed below), none of the phantom units vested until November 2003. Since that time, approximately 927,000 phantom units have vested. Including grants to directors, approximately 418,000 units have been purchased and delivered or issued in satisfaction of vesting, after payment of cash-equivalents and netting for taxes. As a result of the vesting of these awards, we recognized an expense of approximately $28.8 million as of December 31, 2003 and an expense of approximately $4.2 million as of September 30, 2004.

New tax rules concerning deferred compensation will become effective January 1, 2005. Until Treasury Regulations are issued, the application of this new law to the LTIP is unclear. We intend to operate the LTIP, and make any amendments to it that may be necessary, for the LTIP and awards granted thereunder to comply with this new law.

The issuance of the common units pursuant to the restricted unit plan is primarily intended to serve as a means of incentive compensation for performance. Therefore, no consideration is paid to us by the plan participants upon receipt of the common units.

In 2000, the three non-employee directors of our former general partner (Messrs. Goyanes, Sinnott and Smith) were each granted 5,000 phantom units. These units vested and were paid in connection with the transfer of the general partner interest in 2001. Additional grants of 5,000 phantom units were made in 2002 to each non-employee director of our general partner. These units vest and are payable in 25% increments on each anniversary of June 8, 2001. The first three vestings took place on June 8 of 2002, 2003 and 2004. See "—Compensation of Directors."

The following table shows the vesting of phantom units granted to the Named Executive Officers.

		November 2003 Vesting			February 2004 Vesting			May 2004 Vesting			August 2004 Vesting			Remaining Unvested Grants(2)
Name	Total Units	November 2003 Vesting			February 2004 Vesting			May 2004 Vesting			August 2004 Vesting			Remaining Unvested Grants(2)
Name	Total Units	Units	Value⁽¹⁾		Units	Value⁽¹⁾		Units	Value⁽¹⁾		Units	Value⁽¹⁾		Units	Value⁽³⁾
Greg L. Armstrong	70,000	—		—	17,500	$	551,250	17,500	$	580,650	17,500	$	560,700	17,500	$	629,650
Harry N. Pefanis	70,000	15,000	$	452,400	47,500	$	1,511,550	2,500	$	82,950	2,500	$	80,100	2,500	$	89,950
Phillip D. Kramer	50,000	—		—	12,500	$	393,750	12,500	$	414,750	12,500	$	400,500	12,500	$	449,750
George R. Coiner	67,500	7,500	$	226,200	31,875	$	1,028,869	9,375	$	311,063	9,375	$	300,375	9,375	$	337,313
W. David Duckett	—	—		—	—		—	—		—	—		—	—		—

⁽¹⁾: As of vesting dates.
⁽²⁾: With respect to remaining grants, vesting is contingent upon our achieving a specified distribution threshold of $2.50 annualized.
⁽³⁾: As if vested on September 30, 2004.

Unit Option Plan. The unit option plan under our LTIP currently permits the grant of options covering common units. No grants have been made under the unit option plan to date. However, the Compensation Committee may, in the future, make grants under the plan to employees and directors

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containing such terms as the committee shall determine, provided that unit options have an exercise price equal to the fair market value of the units on the date of grant.

Upon exercise of a unit option, our general partner may deliver common units acquired by it in the open market or in private transactions or use common units already owned by our general partner, or any combination of the foregoing. In addition, we may issue up to 975,000 new common units to satisfy delivery obligations under the grants, less any common units issued upon vesting of restricted units under the plan. Our general partner will be entitled to reimbursement by us for the difference between the cost incurred by our general partner in acquiring such common units and the proceeds received by our general partner from an optionee at the time of exercise. Thus, the cost of the unit options will be borne by us. If we issue new common units upon exercise of the unit options, the total number of common units outstanding will increase, and our general partner will remit to us the proceeds received by it from the optionee upon exercise of the unit option.

2005 Long-Term Incentive Plan

Our board of directors has unanimously approved, subject to the approval of our unitholders, our 2005 Long-Term Incentive Plan (the "2005 LTIP"). The 2005 LTIP would provide awards to our employees and directors. Awards contemplated under the 2005 LTIP include phantom units, restricted units, unit appreciation rights and unit options, as determined by the Compensation Committee (each an "Award"). If approved by our unitholders, up to 3,000,000 units may be issued in satisfaction of Awards. Certain Awards may also include, in the discretion of the Compensation Committee, a "distribution equivalent right," or "DER," that entitles the grantee to a cash payment, either while the Award is outstanding or upon vesting, equal to any cash distributions paid on a unit while the Award is outstanding. As of November, 2004, approximately 2,000 individuals (of which we expect that approximately 200 to 250 would be participants) would be eligible for Awards under the 2005 LTIP.

Other Equity Grants

Certain other employees and officers have also received grants of equity not associated with the LTIP described above, and for which we have no cost or reimbursement obligations. For example, in 2001 our general partner established a Performance Option Plan funded by common units owned by the general partner. See "Certain Relationships and Related Transactions—Transactions with Related Parties."

Compensation of Directors

Each director of our general partner who is not an employee of our general partner is currently paid an annual retainer fee of $45,000, plus reimbursement for out-of-pocket expenses related to meeting attendance. In 2001, Messrs. Goyanes and Smith each received $10,000 for their service on a special committee of the Board of Directors of our former general partner. Mr. Armstrong is otherwise compensated for his services as an employee and therefore receives no separate compensation for his services as a director. Each committee chairman (other than the Audit Committee) receives $2,000 annually. The chairman of the Audit Committee receives $30,000 annually, and the other members of the Audit Committee receive $15,000 annually. Mr. Petersen assigns any compensation he receives in his capacity as a director to EnCap Energy Capital Fund III, L.P., which is controlled by EnCap Investments L.P., of which Mr. Petersen is a Managing Director. Mr. Capobianco assigns any compensation he receives in his capacity as a director to Vulcan Capital.

In 2000, Messrs. Goyanes, Sinnott and Smith, as directors of our former general partner, received a grant of 5,000 phantom units each under our LTIP. The phantom units vested and were paid in 2001 in connection with the consummation of the General Partner Transition. Each non-employee director of our general partner at the time received a grant of 5,000 phantom units in 2002. Mr. Peterson's grant was subsequently converted into cash payment of equivalent value to EnCap III. The units vest and are

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payable in 25% increments annually on each anniversary of June 8, 2001. The final vesting will occur in June 2005.

Reimbursement of Expenses of Our General Partner and its Affiliates

We do not pay our general partner a management fee, but we do reimburse our general partner for all expenses incurred on our behalf, including the costs of employee, officer and director compensation and benefits, as well as all other expenses necessary or appropriate to the conduct of our business. Our partnership agreement provides that our general partner will determine the expenses that are allocable to us in any reasonable manner determined by our general partner in its sole discretion. Prior to July 1, 2001, an allocation was made for overhead associated with officers and employees who divided time between us and Plains Resources. As a result of the transfer of the general partner interest (and related transactions) in 2001, all of the employees and officers of the general partner now devote 100% of their efforts to our business and there are no allocated expenses. See "Certain Relationships and Related Transactions."

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CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

Our General Partner

Our operations and activities are managed by, and our officers and personnel are employed by, our general partner (or, in the case of our Canadian operations, PMC (Nova Scotia) Company). Prior to the consummation of the General Partner Transition, some of the senior executives who managed our business also managed and operated the business of Plains Resources. The transition of employment of such executives to our general partner was effected on June 30, 2001. We do not pay our general partner a management fee, but we do reimburse our general partner for all expenses incurred on our behalf.

Our general partner owns the 2% general partner interest and all of the incentive distribution rights. Our general partner is entitled to receive incentive distributions if the amount we distribute with respect to any quarter exceeds levels specified in our partnership agreement. Under the quarterly incentive distribution provisions, generally our general partner is entitled, without duplication, to 15% of amounts we distribute in excess of $0.450 ($1.80 annualized) per unit, 25% of the amounts we distribute in excess of $0.495 ($1.98 annualized) per unit and 50% of amounts we distribute in excess of $0.675 ($2.70 annualized) per unit.

The following table illustrates the allocation of aggregate distributions at different per-unit levels:

Annual Distribution Per Unit	Distribution to Unitholders⁽¹⁾⁽²⁾		Distribution to GP^(1)(2)(3)		Total Distribution⁽¹⁾		GP Percentage of Total Distribution
$1.80	$	126,000	$	2,571	$	128,571	2.0	%
$1.98	$	138,600	$	4,795	$	143,395	3.3	%
$2.31	$	161,700	$	12,495	$	174,195	7.2	%
$2.40	$	168,000	$	14,595	$	182,595	8.0	%
$2.60	$	182,000	$	19,262	$	201,262	9.6	%
$2.80	$	196,000	$	28,595	$	224,595	12.7	%
$3.00	$	210,000	$	42,595	$	252,595	16.9	%

⁽¹⁾: In thousands.
⁽²⁾: Assumes 70,000,000 units outstanding. Actual number of units outstanding as of September 30, 2004 was 67,293,108. An increase in the number of units outstanding would increase both the distribution to unitholders and the distribution to the general partner of any given level of distribution per unit.
⁽³⁾: Includes distributions attributable to the 2% general partner interest and the incentive distribution rights.

Transactions with Related Parties

General

Before the General Partner Transition, Plains Resources indirectly owned and controlled our former general partner interest. In 2001, our former general partner and its affiliates incurred $31.2 million of direct and indirect expenses on our behalf, which we reimbursed. Of this amount, approximately $218,000, $655,000 and $127,000 represented allocated salary and bonus (for the year 2000) reimbursement for the services of Messrs. Armstrong, Pefanis and Kramer, respectively, as officers of our former general partner.

As of September 30, 2004 Vulcan Energy, through its wholly owned subsidiary Plains Resources, owned an effective 44% of our general partner interest, as well as approximately 18.4% of our outstanding limited partner units. Mr. John Raymond, one of our directors, is a director and the Chief Executive Officer of Vulcan Energy. Mr. Raymond was designated as a member of our board by Sable Investments, L.P., which is controlled by Mr. James C. Flores. Mr. Flores is a director of Vulcan

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Energy, the 100% owner of Plains Resources, and is the Chief Executive Officer of Plains Exploration and Production Company ("PXP"). We have ongoing relationships with Plains Resources. These relationships include but are not limited to:

•: a separation agreement entered into in connection with the General Partner Transition pursuant to which (i) Plains Resources has indemnified us for (a) claims relating to securities laws or regulations in connection with the upstream or midstream businesses, based on alleged acts or omissions occurring on or prior to June 8, 2001, or (b) claims related to the upstream business, whenever arising, and (ii) we have indemnified Plains Resources for claims related to the midstream business, whenever arising. Plains Resources also has indemnified, and maintains liability insurance (through June 8, 2007) for the individuals who were, on or before June 8, 2001, directors or officers of Plains Resources or our former general partner.
•: a Pension and Employee Benefits Assumption and Transition Services Agreement that provided for the transfer to our general partner of the employees of our former general partner and certain headquarters employees of Plains Resources.
•: an Omnibus Agreement that provides for the resolution of certain conflicts arising from the fact that we and Plains Resources conduct related businesses, including certain non-compete obligations of Plains Resources.
•: a Marketing Agreement with Plains Resources that provides for the marketing of Plains Resources' equity crude oil production (including its subsidiaries that conduct exploration and production activities.). Under the Marketing Agreement, we purchase for resale at market prices of Plains Resources equity production for a fee of $0.20 per barrel. The fee is subject to adjustment in November 2006 based on then-existing market conditions. For the year ended December 31, 2003, Plains Resources produced approximately 2,000 barrels per day that were subject to the Marketing Agreement. We paid approximately $25.7 million for such production and recognized segment profit of approximately $0.2 million under the terms of that agreement. In our opinion, these purchases were made at prevailing market prices. Because Plains Resources divested itself of most of its producing properties at the end of 2002, we do not expect material amounts of crude oil to be subject to this agreement. As currently in effect, the Marketing Agreement (as well as the Omnibus Agreement described above) will terminate upon a "change of control" of Plains Resources or our general partner. The recent purchase of Plains Resources by Vulcan Energy would have constituted a change of control under both the Marketing Agreement and the Omnibus Agreement. In July 2004, we amended and restated the Marketing Agreement and the Omnibus Agreement to except the Vulcan transaction from the change of control provisions.

On December 18, 2002, Plains Resources completed a spin-off of one of its subsidiaries, PXP, to its shareholders. PXP is a successor participant to the Plains Resources Marketing agreement. For the year ended December 31, 2003, PXP produced approximately 26,000 barrels per day that were subject to the Marketing Agreement. We paid approximately $277.9 million for such production and recognized segment profit of approximately $1.7 million. In our opinion, these purchases were made at prevailing market prices. We are also party to a Letter Agreement with Stocker Resources, L.P. (now PXP) that provides that if the Marketing Agreement terminates before our crude oil sales agreement with Tosco Refining Co. terminates, PXP will continue to sell and we will continue to purchase PXP's equity crude oil production from the Arroyo Grande field (now owned by a subsidiary of PXP) under the same terms as the Marketing Agreement until our Tosco sales agreement terminates. In July 2004, we amended and restated the Marketing Agreement to, among other things, reflect the change in parties as a result of the spin-off. We sell PXP's crude under sales contracts that range from one year to seven years in length. In October, 2004, we further amended the PXP Marketing Agreement to exclude any

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newly acquired properties and to adjust the marketing fee to $0.15 per barrel for any new contracts entered into after January 1, 2005.

Transaction Grant Agreements

In connection with our initial public offering, our former general partner, at no cost to us, agreed to transfer, subject to vesting, approximately 400,000 of its affiliates' common units (including distribution equivalent rights attributable to such units) to certain key officers and employees of our former general partner and its affiliates, including Messrs. Armstrong, Pefanis, Coiner and Kramer. Approximately 70,000 units vested in 2000, and the remainder in 2001. The value of the units and associated distribution equivalent rights that vested under the Transaction Grant Agreements for all grantees in 2001 was $5.7 million. Although we recorded noncash compensation expenses with respect to these vestings, the compensation expense incurred in connection with these grants was funded by our former general partner, without reimbursement by us.

Long-Term Incentive Plan

Our general partner has adopted the Plains All American GP LLC 1998 Long-Term Incentive Plan for employees and directors of our general partner and its affiliates who perform services for us. The LTIP consists of two components, a restricted unit plan and a unit option plan. The LTIP permits the grant of restricted units and unit options covering delivery of an aggregate of 1,425,000 common units. The plan is administered by the compensation committee of our general partner's board of directors.

A restricted unit is a "phantom" unit that entitles the grantee to receive a common unit (or cash equivalent) upon the vesting of the phantom unit. As of September 30, 2004, approximately 418,000 common units have been issued or purchased and delivered upon vesting and grants of approximately 134,000 phantom units remain outstanding to employees, officers and directors of our general partner. See "Management—Executive Compensation."

Performance Option Plan

In connection with the General Partner Transition, 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 391,000 units have been granted. Of this amount, 75,000, 55,000, 45,000 and 42,500 were granted to Messrs. Armstrong, Pefanis, Kramer and Coiner, respectively, and approximately 346,000 to executive officers as a group. These options vest in 25% increments based upon achieving quarterly distribution levels on our units of $0.525, $0.575, $0.625 and $0.675 ($2.10, $2.30, $2.50 and $2.70, annualized). The first such level was reached in 2002, and 25% of the options vested. The second level was reached in 2004, and an incremental 25% of the options vested. The options will vest in their entirety immediately upon a change in control (as defined in the grant agreements). The original purchase price under the options was $22 per subordinated unit, declining over time in an amount equal to 80% of each quarterly distribution per unit. As of September 30, 2004, the purchase price was $16.39 per unit. The terms of future grants may differ from the existing grants. Because the units underlying the plan were contributed to the general partner, we will have no obligation to reimburse the general partner for the cost of the units upon exercise of the options.

Stock Option Replacement

In connection with the General Partner Transition, certain members of the management team that had been employed by Plains Resources, including Messrs. Armstrong, Pefanis and Kramer, were

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transferred to the general partner. At that time, such individuals held in-the-money but unvested stock options in Plains Resources, which were subject to forfeiture because of the transfer of employment. Plains Resources, through its affiliates, agreed to substitute a contingent grant of subordinated units, which are now common units pursuant to conversion, with a value equal to the spread on the unvested options, with distribution equivalent rights from the date of grant. The grant included 8,548, 4,602 and 9,742 units to Messrs. Armstrong, Pefanis and Kramer, respectively. The units vested on the same schedule as the stock options would have vested. The units granted to Messrs. Armstrong, Pefanis and Kramer vested in their entirety in 2002. The general partner administered the vesting and delivery of the units under the grants. Because the units necessary to satisfy the delivery requirements under the grants were provided by Plains Resources, we had no obligation to reimburse the general partner for the cost of such units.

CANPET Energy Group Inc.

In July 2001, we acquired the assets of CANPET Energy Group Inc., a Calgary based Canadian crude oil and LPG marketing company (the "CANPET acquisition"), for approximately $24.6 million plus excess inventory at the closing date of approximately $25.0 million. A portion of the purchase price, payable in common units or cash, at our option, was deferred subject to various performance standards being met. On April 30, 2004, we satisfied the deferred payment with the issuance of approximately 385,000 common units (representing approximately $13.1 million in value as of the date of issuance) and the payment of $6.5 million in cash. In addition, an incremental $3.7 million in cash was paid for the distributions that would have been paid on the common units had they been outstanding since the effective date of the acquisition. Mr. W. David Duckett, the President of PMC (Nova Scotia) Company, the general partner of Plains Marketing Canada, L.P., owns approximately 37.8% of CANPET, and received a proportionate share of the proceeds from the contingent payment of purchase price for the CANPET assets.

Tank Car Lease and CANPET

In connection with the CANPET acquisition, Plains Marketing Canada, L.P. assumed CANPET's rights and obligations under a Master Railcar Leasing Agreement between CANPET and Pivotal Enterprises Corporation ("Pivotal"). The agreement provides for Plains Marketing Canada, L.P. to lease approximately 57 railcars from Pivotal at a lease price of $1,000 (Canadian) per month, per car. The lease extends until June of 2008, with an option for Pivotal to extend the term of the lease for an additional five years. Pivotal is substantially owned by former employees of CANPET, including Mr. W. David Duckett. Mr. Duckett owns a 22% interest in Pivotal.

Class B Common Units

In May 1999, we sold 1,307,190 unregistered Class B common units (the "Class B common units") to our general partner at the time, Plains All American Inc., a wholly owned subsidiary of Plains Resources Inc., pursuant to Rule 4(2) of the Securities Act. We received $19.125 per Class B common unit, a price equal to the then-market value of our common units for total proceeds of approximately $25 million. We used the net proceeds from the offering to defray costs associated with our acquisition of Scurlock Permian LLC and certain other pipeline assets from Marathon Ashland Petroleum LLC.

Class C Common Units

In April 2004, we sold 3,245,700 unregistered Class C common units (the "Class C common units") to a group of investors comprised of affiliates of Kayne Anderson Capital Advisors, Vulcan Capital and Tortoise Capital pursuant to Rule 4(2) under the Securities Act. For more detailed information with respect to our relationship with Kayne Anderson Capital Advisors and Vulcan Capital, see "Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters." We

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received $30.81 per Class C common unit, an amount which represented 94% of the average closing price of our common units for the twenty trading days immediately ending and including March 26, 2004. Net proceeds from the private placement, including the general partner's proportionate capital contribution and expenses associated with the sale, were approximately $101.0 million. We used the net proceeds from the offering to repay indebtedness under our revolving credit facility incurred in connection with the Link acquisition.

Other

An affiliate of KAFU Holdings, L.P., an owner of our general partner interest, participated in our December 2003 and July 2004 equity offerings. In the aggregate for both offerings, it earned approximately $672,000 in commissions for its participation.

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DESCRIPTION OF NOTES

We issued the outstanding Notes, and will issue the new Notes, under an indenture (the "Base Indenture") dated September 25, 2002, among us, the subsidiary guarantors and Wachovia Bank, National Association, as trustee, and two supplemental indentures thereto (each applicable to one of the series of the Notes) dated as of August 12, 2004 (each such supplemental indenture, together with the Base Indenture, the "Indenture"). We refer to both the new Notes and the outstanding Notes in this description as the "Notes."

The Notes constitute two new series of debt securities under the Indenture. The terms of the Notes include those stated in the Indenture and those made part of the Indenture by reference to the Trust Indenture Act of 1939, as amended. We urge you to read the Indenture because it, and not this description, defines your rights as a holder of Notes. A copy of the Indenture is filed as an exhibit to the registration statement of which this prospectus is a part. Capitalized terms that are used in this prospectus have the meanings assigned to them in the Indenture, and we have included some of those definitions at the end of this section. See "—Definitions."

We have summarized some of the material provisions of the Notes and the Indenture below. The following description of the Notes is not complete and is subject to, and is qualified in its entirety by reference to, all the provisions of the Indenture.

General Description of the Notes and the Guarantees

The Notes of each series are:

•: our senior unsecured indebtedness ranking equally in right of payment with the Notes of the other series and with all of our existing and future unsubordinated debt;
•: unconditionally guaranteed by the subsidiary guarantors;
•: a new series of debt securities issued under the Indenture;
•: non-recourse to our general partner;
•: senior in right of payment to any of our future subordinated debt;
•: effectively junior to any of our existing and future secured debt to the extent of the security for that debt; and
•: effectively junior to any existing and future debt of our subsidiaries that do not guarantee the Notes.

Initially our obligations under the Notes are jointly and severally guaranteed by all of the existing subsidiaries of Plains All American Pipeline other than PAA Finance Corp., and those considered minor, which we sometimes refer to collectively as the "non-guarantor subsidiaries." Each guarantee by a subsidiary guarantor of the Notes is:

•: a general unsecured obligation of that subsidiary guarantor;
•: equal in right of payment with all other existing and future unsubordinated debt of that subsidiary guarantor;
•: senior in right of payment to any future subordinated debt of that subsidiary guarantor; and
•: effectively junior to any secured debt of that subsidiary guarantor, to the extent of the security for that debt.

As of September 30, 2004, the Notes and the guarantees would have been effectively subordinated to $59.5 million of short-term secured indebtedness. See "Risk Factors—Risks Related to the Exchange

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Offers and the Notes—Your right to receive payments on the Notes and the guarantees is unsecured and will be effectively subordinated to our existing and future secured indebtedness as well as to any existing and future indebtedness of our subsidiaries that do not guarantee the Notes."

The Indenture does not limit the aggregate principal amount of debt securities that may be issued thereunder and provides that debt securities may be issued thereunder from time to time in one or more additional series. Except to the extent described below, the Indenture does not limit our ability or the ability of our subsidiaries to incur additional indebtedness.

Further Issuances

We may, from time to time, without notice to or the consent of the holders of the Notes, create and issue additional notes ranking equally and ratably with the Notes in all respects (except for the payment of interest accruing prior to the issue date of such additional notes), so that such additional notes form a single series with either series of the Notes and have the same terms as to status, redemption or otherwise as that series of Notes. If we issue such additional notes of either series prior to the completion of the exchange offers, the period of the resale restrictions applicable to any Notes of that series previously offered and sold in reliance on Rule 144A under the Securities Act will be automatically extended to the last day of the period of any resale restrictions imposed on any such additional notes.

Principal, Maturity and Interest

We have issued the outstanding Notes of each series in an initial aggregate principal amount of $175 million, and the new Notes of each series, together with any outstanding Notes of the same series that are not exchanged for new Notes, will aggregate $175 million in principal amount. The 2009 Notes will mature on August 15, 2009, and the 2016 Notes will mature on August 15, 2016. The 2009 Notes and the 2016 Notes bear interest at the annual rate of 4.750% and 5.875%, respectively. Additional interest may also accrue on the Notes of either series in the circumstances described under "Exchange Offers." All references to "interest" in this description of Notes include any such additional interest. Interest on the Notes accrues from August 12, 2004 and is payable semi-annually in arrears on February 15 and August 15 of each year, commencing February 15, 2005. We will make each interest payment to the holders of record at the close of business on the February 1 and August 1 preceding such interest payment dates. Interest will be computed on the basis of a 360-day year consisting of twelve 30-day months. We will issue the Notes in denominations of $2,000 and integral multiples of $2,000.

No Liability of General Partner

Plains All American Pipeline's general partner and its directors, officers, employees and partners (in their capacities as such) will not have any liability for our obligations under the Notes. In addition, the Managing General Partner, and its directors, officers, employees and members, will not have any liability for our obligations under the Notes. By accepting the Notes, each holder waives and releases all such liability. The waiver and release are part of the consideration for the issuance of the Notes. This waiver may not be effective, however, to waive liabilities under the federal securities laws, and it is the view of the SEC that such a waiver is against public policy.

The Guarantees

Initially, our payment obligations under the Notes are jointly and severally guaranteed by all existing Subsidiaries of Plains All American Pipeline other than the non-guarantor subsidiaries. The obligations of each subsidiary guarantor under its guarantee are limited to the maximum amount that will, after giving effect to all other contingent and fixed liabilities of the subsidiary guarantor and to any

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collections from or payments made by or on behalf of any other subsidiary guarantor in respect of the obligations of the other subsidiary guarantor under its guarantee, result in the obligations of the subsidiary guarantor under the guarantee not constituting a fraudulent conveyance or fraudulent transfer under federal or state law.

Provided that no default shall have occurred and shall be continuing under the Indenture, a subsidiary guarantor will be unconditionally released and discharged from its guarantee:

•: upon any sale or other disposition of all or substantially all of the assets of that subsidiary guarantor, including by way of merger, consolidation or otherwise, to any person that is not our affiliate (provided such sale or other disposition is not prohibited by the Indenture);
•: upon any sale or other disposition of all of our direct or indirect equity interests in that subsidiary guarantor to any person that is not our affiliate; or
•: following delivery of a written notice of the release from the guarantee by us to the trustee, upon the release of all guarantees by the subsidiary guarantor of any debt of ours and any Subsidiary of Plains All American Pipeline (other than debt securities issued under the Indenture on or after the Issue Date).

If at any time after the issuance of the Notes, including following any release of a subsidiary guarantor from its guarantee under the Indenture, a Subsidiary of Plains All American Pipeline (including any future Subsidiary) guarantees any of our debt or any debt of Plains All American Pipeline's other Subsidiaries, we will cause such Subsidiary to guarantee the Notes in accordance with the Indenture by simultaneously executing and delivering a supplemental indenture.

Optional Redemption

The 2009 Notes and the 2016 Notes are redeemable, in whole or in part, at our option at any time and from time to time prior to maturity at a redemption price equal to the greater of (a) 100% of the principal amount of the Notes to be redeemed, and (b) as determined by the Quotation Agent, the sum of the present values of the remaining scheduled payments of principal and interest on the Notes to be redeemed (not including any portion of those payments of interest accrued as of the date of redemption) discounted to the date of redemption on a semi-annual basis (assuming 360-day years, each consisting of twelve 30-day months), at the Adjusted Treasury Rate plus 20 basis points, in the case of the 2009 Notes, and 25 basis points, in the case of the 2016 Notes plus, in each case, accrued interest to the date of redemption.

"Adjusted Treasury Rate" means, with respect to any date of redemption, the rate per annum equal to the semi-annual equivalent yield to maturity of the Comparable Treasury Issue, assuming a price for the Comparable Treasury Issue (expressed as a percentage of its principal amount) equal to the Comparable Treasury Price for the date of redemption.

"Comparable Treasury Issue" means the United States Treasury security selected by the Quotation Agent as having a maturity comparable to the remaining term of the Notes to be redeemed that would be utilized, at the time of selection and in accordance with customary financial practice, in pricing new issues of corporate debt securities of comparable maturity to the remaining term of those Notes.

"Comparable Treasury Price" means, with respect to any date of redemption (a) the average of the Reference Treasury Dealer Quotations for the date of redemption, after excluding the highest and lowest Reference Treasury Dealer Quotations, or (b) if the trustee obtains fewer than four Reference Treasury Dealer Quotations, the average of all such Reference Treasury Dealer Quotations.

"Quotation Agent" means Banc of America Securities LLC or another Reference Treasury Dealer appointed by us.

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"Reference Treasury Dealer" means (a) Banc of America Securities LLC and its successors; provided, however, that if the foregoing shall cease to be a primary U.S. Government securities dealer in the United States (a "Primary Treasury Dealer"), we shall substitute another Primary Treasury Dealer; and (b) any other Primary Treasury Dealer selected by us.

"Reference Treasury Dealer Quotations" means, with respect to each Reference Treasury Dealer and any date of redemption, the average, as determined by the trustee, of the bid and asked prices for the Comparable Treasury Issue (expressed in each case as a percentage of its principal amount) quoted in writing to the trustee by that Reference Treasury Dealer at 5:00 p.m., New York City time, on the third business day preceding that date of redemption.

Unless we default in payment of the redemption price, on and after the date of redemption, interest will cease to accrue on the Notes or portions thereof called for redemption.

On or before a redemption date, we will deposit with a paying agent (or with the trustee) sufficient money to pay the redemption price and accrued interest on the Notes to be redeemed.

If less than all of the Notes are to be redeemed at any time, the trustee will select Notes (or any portion of Notes in integral multiples of $2,000) for redemption as follows:

•: if the Notes are listed, in compliance with the requirements of the principal national securities exchange on which the Notes are listed; or
•: if the Notes are not so listed or there are no such requirements, on a pro rata basis, by lot or by such method as the trustee shall deem fair and appropriate.

However, no Note with a principal amount of $2,000 or less will be redeemed in part. Notice of redemption will be mailed by first class mail at least 30 days but not more than 60 days before the redemption date to each holder of Notes to be redeemed at its registered address. If any Note is to be redeemed in part only, the notice of redemption that relates to that Note will state the portion of the principal amount of that Note to be redeemed.

Events of Default

Each of the following constitutes an "Event of Default" with respect to a series of Notes:

•: default in payment when due of the principal of or any premium on any Note of that series at maturity, upon redemption or otherwise;
•: default for 60 days in the payment when due of interest on any Note of that series;
•: failure by us or, so long as the Notes are guaranteed by a subsidiary guarantor, by such subsidiary guarantor, for 30 days after receipt of notice from the trustee or the holders to comply with any other term, covenant or warranty in the Indenture or the Notes of that series (provided that notice need not be given, and an Event of Default will occur, 30 days after any breach of the covenants described under "—Consolidation, Merger or Sale");
•: default under any mortgage, indenture or instrument under which there may be issued or by which there may be secured or evidenced any debt for money borrowed of us or any of the Subsidiaries of Plains All American Pipeline (or the payment of which is guaranteed by Plains All American Pipeline or any of its Subsidiaries), whether such debt or guarantee now exists or is created after the Issue Date, if (a) that default (x) is caused by a failure to pay principal of or premium, if any, or interest on such debt prior to the expiration of any grace period provided in such debt (a "Payment' Default"), or (y) results in the acceleration of the maturity of such debt to a date prior to its originally stated maturity, and, (b) in each case described in clauses (x) or (y) above, the principal amount of any such debt, together with the principal amount of any other such debt under which there has been a Payment Default or the maturity of which has

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been so accelerated, aggregates $25 million or more; provided that if any such default is cured or waived or any such acceleration rescinded, or such debt is repaid, within a period of 30 days from the continuation of such default beyond the applicable grace period or the occurrence of such acceleration, as the case may be, such Event of Default and any consequential acceleration of the Notes shall be automatically rescinded, so long as such rescission does not conflict with any judgment or decree;

•

specified events in bankruptcy, insolvency or reorganization of us or, so long as the Notes are guaranteed by a subsidiary guarantor, by such subsidiary guarantor;

•

so long as the Notes are guaranteed by a subsidiary guarantor:

•: the guarantee by such subsidiary guarantor ceases to be in full force and effect, except as otherwise provided in the Indenture;
•: the guarantee by such subsidiary guarantor is declared null and void in a judicial proceeding; or
•: such subsidiary guarantor denies or disaffirms its obligations under the Indenture or its guarantee.

An Event of Default for a particular series of Notes will not necessarily constitute an Event of Default for the other series of Notes or for any other series of debt securities that may be issued under the Base Indenture. In the case of an Event of Default arising from certain events of bankruptcy, insolvency or reorganization involving us, but not any subsidiary guarantor, all outstanding Notes will become due and payable immediately without further action or notice. If any other Event of Default occurs and is continuing with respect to a series of Notes, the trustee or the holders of at least 25% in principal amount of the then outstanding Notes of that series may declare all the Notes of that series to be due and payable immediately.

Consolidation, Merger or Sale

We will not merge, amalgamate or consolidate with or into any other Person or sell, convey, lease, transfer or otherwise dispose of all or substantially all of our assets to any Person, whether in a single transaction or series of related transactions, except in accordance with the provisions of the partnership agreement of Plains All American Pipeline, and unless:

•

we are the surviving Person in the case of a merger, or the surviving Person:

•: is a partnership, limited liability company or corporation organized under the laws of the United States, a state thereof or the District of Columbia, provided that PAA Finance Corp. may not merge, amalgamate or consolidate with or into another Person other than a corporation satisfying such requirement for so long as Plains All American Pipeline is not a corporation; and
•: expressly assumes, by supplemental indenture in form reasonably satisfactory to the trustee, the due and punctual payment of the principal of, premium, if any, and interest on all of the Notes, and the due and punctual performance or observance of all the other obligations under the Indenture to be performed or observed by us;

•

immediately after giving effect to the transaction or series of transactions, no Default or Event of Default has occurred and is continuing;

•

if we are not the surviving Person, then each subsidiary guarantor, unless such subsidiary guarantor is the Person with which we have consummated a transaction under this provision, shall have confirmed that its guarantee of the Notes shall continue to apply to the obligations under the Notes and the Indenture; and

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•: we have delivered to the trustee an officers' certificate and opinion of counsel, each stating that the merger, amalgamation, consolidation, sale, conveyance, transfer, lease or other disposition, and if a supplemental indenture is required, the supplemental indenture, comply with the Indenture and all other conditions precedent to the transaction have been complied with.

Thereafter, the surviving Person will be substituted for us under the Indenture. If we sell or otherwise dispose of (except by lease) all or substantially all of our assets and the above stated requirements are satisfied, we will be released from all our liabilities and obligations under the Indenture. If we lease all or substantially all of our assets, we will not be so released from our obligations under the Indenture.

Modification of the Indenture

Generally, we, the subsidiary guarantors and the trustee may amend or supplement the Indenture, the guarantees and the Notes with the written consent of the holders of at least a majority in principal amount of the then outstanding Notes of the affected series. However, without the consent of each holder affected, an amendment, supplement or waiver may not (with respect to any Notes held by a nonconsenting holder):

•: reduce the principal amount of Notes whose holders must consent to an amendment, supplement or waiver;
•: reduce the principal of or change the fixed maturity of any Note;
•: reduce or waive the premium payable upon redemption or alter or waive the provisions with respect to the redemption of any Notes;
•: reduce the rate of or change the time for payment of interest on any Note;
•: waive a Default or an Event of Default in the payment of principal of or premium, if any, or interest on, any Notes (except a rescission of acceleration of the Notes with respect to either series by the holders of at least a majority in aggregate principal amount of that series and a waiver of the payment default that resulted from such acceleration);
•: release any security that may have been granted with respect to the Notes;
•: make any Note payable in currency other than that stated in the Notes;
•: make any change in the provisions of the Indenture relating to waivers of past Defaults or the rights of holders of Notes to receive payments of principal of or premium, if any, or interest on the Notes;
•: waive a redemption payment with respect to any Note;
•: except as otherwise permitted in the Indenture, release any subsidiary guarantor from its obligations under its guarantee or the Indenture or change any guarantee in any manner that would adversely affect the rights of holders; or
•: make any change in the preceding amendment, supplement and waiver provisions (except to increase any percentage set forth therein).

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Notwithstanding the preceding, without the consent of any holder of Notes, we, the subsidiary guarantors and the trustee may amend or supplement the Indenture or the Notes:

•: to cure any ambiguity, defect or inconsistency;
•: to provide for uncertificated Notes in addition to or in place of certificated Notes;
•: to provide for the assumption of our or a subsidiary guarantor's obligations to holders of Notes in the case of a merger or consolidation or sale of all or substantially all of our or such subsidiary guarantor's assets;
•: to add or release subsidiary guarantors as permitted pursuant to the terms of a supplemental indenture (please read "—The Guarantees");
•: to make any changes that would provide any additional rights or benefits to the holders of Notes that do not, taken as a whole, adversely affect the rights under the Indenture of any holder of the Notes;
•: to comply with requirements of the SEC in order to effect or maintain the qualification of the Indenture under the Trust Indenture Act;
•: to evidence or provide for the acceptance of appointment under the Indenture of a successor trustee;
•: to add any additional Events of Default;
•: to secure the Notes and/or the guarantees; or
•: to establish the form or terms of any other series of debt securities under the Base Indenture.

Covenants

Limitations on Liens

We will not, nor will we permit any Subsidiary to, create, assume, incur or suffer to exist any lien upon any Principal Property or upon any Capital Interests of any Restricted Subsidiary, whether owned or leased or hereafter acquired, to secure any of our debt or any debt of any other Person (other than debt securities issued under the Indenture), without in any such case making effective provision whereby all of the Notes shall be secured equally and ratably with, or prior to, such debt so long as such debt shall be so secured. The following are excluded from this restriction:

•: Permitted Liens;
•: any lien upon any property or assets created at the time of acquisition of such property or assets by us or any Restricted Subsidiary or within one year after such time to secure all or a portion of the purchase price for such property or assets or debt incurred to finance such purchase price, whether such debt was incurred prior to, at the time of or within one year after the date of such acquisition;
•: any lien upon any property or assets to secure all or part of the cost of construction, development, repair or improvements thereon or to secure debt incurred prior to, at the time of, or within one year after completion of such construction, development, repair or improvements or the commencement of full operations thereof (whichever is later), to provide funds for any such purpose;
•: any lien upon any property or assets existing thereon at the time of the acquisition thereof by us or any Restricted Subsidiary (whether or not the obligations secured thereby are assumed by us or any Restricted Subsidiary); provided, however, that such lien only encumbers the property or assets so acquired;

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•: any lien upon any property or assets of a Person existing thereon at the time such Person becomes a Restricted Subsidiary by acquisition, merger or otherwise; provided, however, that such lien only encumbers the property or assets of such Person at the time such Person becomes a Restricted Subsidiary;
•: any lien upon any of our property or assets or the property or assets of any Restricted Subsidiary in existence on December 10, 2003 or provided for pursuant to agreements existing on December 10, 2003;
•: liens imposed by law or order as a result of any proceeding before any court or regulatory body that is being contested in good faith, and liens which secure a judgment or other court-ordered award or settlement as to which we or the applicable Restricted Subsidiary has not exhausted its appellate rights;
•: any extension, renewal, refinancing, refunding or replacement, or successive extensions, renewals, refinancings, refundings or replacements of liens, in whole or in part, referred to above; provided, however, that any such extension, renewal, refinancing, refunding or replacement lien shall be limited to the property or assets covered by the lien extended, renewed, refinanced, refunded or replaced and that the obligations secured by any such extension, renewal, refinancing, refunding or replacement lien shall be in an amount not greater than the amount of the obligations secured by the lien extended, renewed, refinanced, refunded or replaced and any of our expenses and the expenses of the Restricted Subsidiaries (including any premium) incurred in connection with such extension, renewal, refinancing, refunding or replacement; or
•: any lien resulting from the deposit of moneys or evidence of indebtedness in trust for the purpose of defeasing our debt or debt of any Restricted Subsidiary.

Notwithstanding the preceding, we may, and may permit any Restricted Subsidiary to, create, assume, incur, or suffer to exist any lien upon any Principal Property or Capital Interests of a Restricted Subsidiary to secure our debt or debt of any Person (other than debt securities issued under the Indenture), that is not excepted above without securing the Notes, provided that the aggregate principal amount of all debt then outstanding secured by such lien and all other liens not excepted above, together with all Attributable Indebtedness from Sale-leaseback Transactions, excluding Sale-leaseback Transactions permitted under "—Limitations on Sale-Leasebacks," does not exceed 10% of Consolidated Net Tangible Assets.

Limitations on Sale-Leasebacks

We will not, and will not permit any Subsidiary to, engage in a Sale-leaseback Transaction, unless:

•: such Sale-leaseback Transaction occurs within one year from the date of completion of the acquisition of the Principal Property subject thereto or the date of the completion of construction, development or substantial repair or improvement, or commencement of full operations on such Principal Property, whichever is later;
•: the Sale-leaseback Transaction involves a lease for a period, including renewals, of not more than three years;
•: the Attributable Indebtedness from that Sale-leaseback Transaction is an amount equal to or less than the amount that we or such Subsidiary would be allowed to incur as debt secured by a lien on the Principal Property subject thereto without equally and ratably securing the Notes; or
•: we or such Subsidiary, within a one-year period after such Sale-leaseback Transaction, applies or causes to be applied an amount not less than the net sale proceeds from such Sale-leaseback Transaction to (A) the prepayment, repayment, redemption, reduction or retirement of any Pari Passu Debt of us or any Subsidiary, or (B) the expenditure or expenditures for Principal

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Property used or to be used in the ordinary course of the business of Plains All American Pipeline or that of its Subsidiaries.

Notwithstanding the preceding, we may, and may permit any Subsidiary of Plains All American Pipeline to, effect any Sale-leaseback Transaction that is not excepted above, provided that the Attributable Indebtedness from such Sale-leaseback Transaction, together with the aggregate principal amount of then outstanding debt (other than debt securities issued under the Indenture) secured by liens upon Principal Properties not excepted in "—Limitations on Liens," do not exceed 10% of Consolidated Net Tangible Assets.

SEC Reports

Regardless of whether Plains All American Pipeline is required to remain subject to the reporting requirements of Section 13 or 15(d) of the Exchange Act, it will electronically file with the SEC, so long as either series of Notes is outstanding, the annual, quarterly and other periodic reports that it is required to file (or would otherwise be required to file) with the SEC pursuant to Sections 13 and 15(d) of the Exchange Act, and such documents will be filed with the SEC on or prior to the respective dates (the "Required Filing Dates") by which it is required to file (or would otherwise be required to file) such documents, unless, in each case, such filings are not then permitted by the SEC.

If such filings are not then permitted by the SEC, or such filings are not generally available on the Internet free of charge, we will provide the trustee with, and the trustee will mail to any holder of Notes requesting in writing to the trustee copies of, such annual, quarterly and other periodic reports specified in Sections 13 and 15(d) of the Exchange Act within 15 days after its Required Filing Date.

In addition, we will furnish to the holders of Notes and to prospective investors, upon the requests of holders of Notes, any information required to be delivered pursuant to Rule 144A(d)(4) under the Securities Act, so long as the Notes are not freely transferable under the Securities Act.

Defeasance and Discharge

We may choose to either discharge our obligations under the Notes of either series in a legal defeasance, or to release ourselves from our covenant restrictions applicable to the Notes of either series in a covenant defeasance. We may do so at any time (provided certain other conditions contained in the Indenture are met) after we deposit with the trustee sufficient cash or government securities to pay the principal, interest, premium, if any, and any other sums due to the stated maturity date or redemption date of the Notes of the relevant series.

If we choose the legal defeasance option, the holders of Notes of the relevant series will not be entitled to the benefits of the Indenture except for registration of transfer and exchange of Notes, replacement of lost, stolen, destroyed or mutilated Notes, receipt of principal and interest on the original stated due dates and other specified provisions in the Indenture.

We may discharge our obligations under the Indenture or release ourselves from covenant restrictions only if, in addition to making the deposit with the trustee, we meet some specific requirements. Among other things:

•: we must deliver an opinion of our legal counsel that the discharge or release will not result in holders having to recognize income, gain or loss for federal income tax purposes. In the case of legal defeasance, this opinion must be based on either an IRS letter ruling or change in federal tax law;
•: we may not have a Default or Event of Default on the Notes discharged on the date of deposit or, insofar as Events of Default from bankruptcy or insolvency events are concerned, at any time in the period ending on the 91st day after the date of deposit; and

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•: the discharge may not violate any of our agreements other than the Notes of the relevant series and the Indenture.

Concerning the Trustee

Wachovia Bank, National Association, acts as indenture trustee, security registrar and paying agent with respect to the Notes. The trustee makes no representation or warranty, express or implied, as to the accuracy or completeness of any information contained in this prospectus, except for such information that specifically pertains to the trustee.

Governing Law

The Indenture and the Notes are governed by and will be construed in accordance with the law of the State of New York.

Definitions

"Attributable Indebtedness," when used with respect to any Sale-leaseback Transaction, means, as at the time of determination, the present value, discounted at the rate set forth or implicit in the terms of the lease included in such transaction, of the total obligations of the lessee for rental payments, other than amounts required to be paid on account of property taxes, maintenance, repairs, insurance, assessments, utilities, operating and labor costs and other items that do not constitute payments for property rights during the remaining term of the lease included in such Sale-leaseback Transaction including any period for which such lease has been extended. In the case of any lease that is terminable by the lessee upon the payment of a penalty or other termination payment, such amount shall be the lesser of the amount determined assuming termination upon the first date such lease may be terminated, in which case the amount shall also include the amount of the penalty or termination payment, but no rent shall be considered as required to be paid under such lease subsequent to the first date upon which it may be so terminated, or the amount determined assuming no such termination.

"Board of Directors" means (a) with respect to Plains All American Pipeline, the board of directors of the Managing General Partner, and (b) with respect to PAA Finance Corp., its board of directors or, in each case, with respect to any determination or resolution permitted to be made under the Indenture, any authorized committee or subcommittee of such board.

"Capital Interests" means any and all shares, interests, participations, rights or other equivalents (however designated) of capital stock, including, without limitation, with respect to partnerships, partnership interests (whether general or limited) and any other interest or participation that confers on a Person the right to receive a share of the profits and losses of, or distributions of assets of, such Person.

"Consolidated Net Tangible Assets" means, at any date of determination, the total amount of assets after deducting therefrom:

(1)

all current liabilities excluding:

(a): any current liabilities that by their terms are extendible or renewable at the option of the obligor thereon to a time more than 12 months after the time as of which the amount thereof is being computed; and
(b): current maturities of long-term debt; and

(2)

the amount, net of any applicable reserves, of all goodwill, trade names, trademarks, patents and other like intangible assets,

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all as set forth on the consolidated balance sheet of Plains All American Pipeline for its most recently completed fiscal quarter, prepared in accordance with generally accepted accounting principles.

"Exchange Act" means the Securities Exchange Act of 1934, as amended.

"Funded Debt" means all debt maturing one year or more from the date of the creation thereof, all debt directly or indirectly renewable or extendible, at the option of the debtor, by its terms or by the terms of any instrument or agreement relating thereto, to a date one year or more from the date of the creation thereof, and all debt under a revolving credit or similar agreement obligating the lender or lenders to extend credit over a period of one year or more.

"Issue Date" means with respect to the Notes, the date on which the Notes are initially issued.

"Managing General Partner" means Plains All American GP LLC, a Delaware limited liability company, and its successors and permitted assigns, as general partner of Plains AAP, L.P., a Delaware limited partnership (and its successors and permitted assigns, as general partner of Plains All American Pipeline) or as the business entity with the ultimate authority to manage the business and operations of Plains All American Pipeline.

"Pari Passu Debt" means any of our Funded Debt, whether outstanding on the Issue Date or thereafter created, incurred or assumed, unless, in the case of any particular Funded Debt, the instrument creating or evidencing the same or pursuant to which the same is outstanding expressly provides that such Funded Debt shall be subordinated in right of payment to the Notes.

"Permitted Liens" means:

(1)

liens upon rights-of-way for pipeline purposes;

(2)

any statutory or governmental lien or lien arising by operation of law, or any mechanics', repairmen's, materialmen's, suppliers', carriers', landlords', warehousemen's or similar lien incurred in the ordinary course of business which is not yet due or which is being contested in good faith by appropriate proceedings and any undetermined lien which is incidental to construction, development, improvement or repair;

(3)

the right reserved to, or vested in, any municipality or public authority by the terms of any right, power, franchise, grant, license, permit or by any provision of law, to purchase or recapture or to designate a purchaser of any property;

(4)

liens of taxes and assessments which are:

(a): for the then current year,
(b): not at the time delinquent, or
(c): delinquent but the validity of which is being contested at the time by us or any Restricted Subsidiary in good faith;

(5)

liens of, or to secure performance of, leases, other than capital leases;

(6)

any lien upon, or deposits of, any assets in favor of any surety company or clerk of court for the purpose of obtaining indemnity or stay of judicial proceedings;

(7)

any lien upon property or assets acquired or sold by us or any Restricted Subsidiary resulting from the exercise of any rights arising out of defaults on receivables;

(8)

any lien incurred in the ordinary course of business in connection with worker's compensation, unemployment insurance, temporary disability, social security, retiree health or similar laws or regulations or to secure obligations imposed by statute or governmental regulations;

(9)

any lien in favor of us or any Restricted Subsidiary;

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(10): any lien in favor of the United States of America or any state thereof, or any department, agency or instrumentality or political subdivision of the United States of America or any state thereof, to secure partial, progress, advance, or other payments pursuant to any contract or statute, or any debt incurred by us or any Restricted Subsidiary for the purpose of financing all or any part of the purchase price of, or the cost of constructing, developing, repairing or improving, the property or assets subject to such lien;
(11): any lien securing industrial development, pollution control or similar revenue bonds;
(12): any lien securing our debt or debt of any Restricted Subsidiary, all or a portion of the net proceeds of which are used, substantially concurrently with the funding thereof (and for purposes of determining such "substantial concurrence," taking into consideration, among other things, required notices to be given to holders of outstanding securities under the Indenture (including the Notes) in connection with such refunding, refinancing or repurchase, and the required corresponding durations thereof), to refinance, refund or repurchase all outstanding securities under the Indenture (including the Notes), including the amount of all accrued interest thereon and reasonable fees and expenses and premium, if any, incurred by us or any Restricted Subsidiary in connection therewith;
(13): liens in favor of any Person to secure obligations under the provisions of any letters of credit, bank guarantees, bonds or surety obligations required or requested by any governmental authority in connection with any contract or statute;
(14): any lien upon or deposits of any assets to secure performance of bids, trade contracts, leases or statutory obligations;
(15): any lien or privilege vested in any grantor, lessor or licensor or permittor for rent or other charges due or for any other obligations or acts to be performed, the payment of which rent or other charges or performance of which other obligations or acts is required under leases, easements, rights-of-way, leases, licenses, franchises, privileges, grants or permits, so long as payment of such rent or the performance of such other obligations or acts is not delinquent or the requirement for such payment or performance is being contested in good faith by appropriate proceedings;
(16): easements, exceptions or reservations in any property of Plains All American Pipeline or any property of any of its Restricted Subsidiaries granted or reserved for the purpose of pipelines, roads, the removal of oil, gas, coal or other minerals, and other like purposes for the joint or common use of real property, facilities and equipment, which are incidental to, and do not materially interfere with, the ordinary conduct of its business or the business of Plains All American Pipeline and its Subsidiaries, taken as a whole;
(17): liens arising under operating agreements, joint venture agreements, partnership agreements, oil and gas leases, farmout agreements, division orders, contracts for sale, transportation or exchange of oil and natural gas, unitization and pooling declarations and agreements, area of mutual interest agreements and other agreements arising in the ordinary course of Plains All American Pipeline's or any Restricted Subsidiary's business that are customary in the business of marketing, transportation and terminalling of crude oil and/or marketing of liquefied petroleum gas; or
(18): any obligations or duties to any municipality or public authority with respect to any lease, easement, right-of-way, license, franchise, privilege, permit or grant.

"Person" means any individual, corporation, partnership, joint venture, limited liability company, association, joint-stock company, trust, other entity, unincorporated organization or government or any agency or political subdivision thereof.

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"Principal Property" means, whether owned or leased on the Issue Date or thereafter acquired:

(1)

any of the pipeline assets of Plains All American Pipeline or the pipeline assets of any Subsidiary of Plains All American Pipeline, including any related facilities employed in the transportation, distribution, terminalling, gathering, treating, processing, marketing or storage of crude oil or refined petroleum products, natural gas, natural gas liquids, fuel additives or petrochemicals; and

(2)

any processing or manufacturing plant or terminal owned or leased by Plains All American Pipeline or any Subsidiary of Plains All American Pipeline; except, in either case above:

(a): any such assets consisting of inventories, furniture, office fixtures and equipment, including data processing equipment, vehicles and equipment used on, or useful with, vehicles, and
(b): any such assets, plant or terminal which, in the good faith opinion of the Board of Directors, is not material in relation to the activities of Plains All American Pipeline or the activities of Plains All American Pipeline and its Subsidiaries, taken as a whole.

"Restricted Subsidiary" means any Subsidiary of Plains All American Pipeline owning or leasing, directly or indirectly through ownership in another Subsidiary, any Principal Property.

"Sale-leaseback Transaction" means the sale or transfer by us or any Subsidiary of Plains All American Pipeline of any Principal Property to a Person (other than us or a Subsidiary of Plains All American Pipeline) and the taking back by us or any Subsidiary of Plains All American Pipeline, as the case may be, of a lease of such Principal Property.

"Securities Act" means the Securities Act of 1933, as amended.

"Subsidiary" means, with respect to any Person:

(1): any other Person of which more than 50% of the total voting power of shares or other Capital Interests entitled, without regard to the occurrence of any contingency, to vote in the election of directors, managers or trustees (or equivalent persons) thereof is at the time owned or controlled, directly or indirectly, by such Person or one or more of the other Subsidiaries of such Person or a combination thereof; or
(2): in the case of a partnership, more than 50% of the partners' Capital Interests, considering all partners' Capital Interests as a single class, is at the time owned or controlled, directly or indirectly, by such Person or one or more of the other Subsidiaries of such Person or a combination thereof.

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TAX CONSIDERATIONS

The following discussion is a summary of certain federal income tax considerations relevant to the exchange of outstanding Notes for new Notes, but does not purport to be a complete analysis of all potential tax effects. The discussion is based upon the Internal Revenue Code of 1986, as amended, Treasury Regulations, Internal Revenue Service rulings and pronouncements and judicial decisions now in effect, all of which may be subject to change at any time by legislative, judicial or administrative action. These changes may be applied retroactively in a manner that could adversely affect a holder of new Notes. The description does not consider the effect of any applicable foreign, state, local or other tax laws or estate or gift tax considerations.

We believe that the exchange of outstanding Notes for new Notes should not be an exchange or otherwise a taxable event to a holder for United States federal income tax purposes. Accordingly, a holder should have the same adjusted issue price, adjusted basis and holding period in the new Notes as it had in the outstanding Notes immediately before the exchange.

PLAN OF DISTRIBUTION

Based on interpretations by the staff of the SEC in no action letters issued to third parties, we believe that you may transfer new Notes issued under either exchange offer in exchange for the outstanding Notes if:

•: you acquire the new Notes in the ordinary course of your business; and
•: you are not engaged in, and do not intend to engage in, and have no arrangement or understanding with any person to participate in, a distribution of such new Notes.

You may not participate in either exchange offer if you are:

•: our "affiliate" within the meaning of Rule 405 under the Securities Act; or
•: a broker-dealer that acquired outstanding Notes directly from us.

Each broker-dealer that receives new Notes for its own account pursuant to either exchange offer must acknowledge that it will deliver a prospectus in connection with any resale of such new Notes. To date, the staff of the SEC has taken the position that broker-dealers may fulfill their prospectus delivery requirements with respect to transactions involving an exchange of securities such as these exchange offers, other than a resale of an unsold allotment from the original sale of the outstanding Notes, with the prospectus contained in this registration statement. This prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer in connection with resales of new Notes received in exchange for outstanding Notes where such outstanding Notes were acquired as a result of market-making activities or other trading activities. We have agreed that, for a period of up to one year after the consummation of the exchange offers, we will make this prospectus, as amended or supplemented, promptly available to any broker-dealer for use in connection with any such resale.

If you wish to exchange your outstanding Notes for new Notes in the applicable exchange offer, you will be required to make representations to us as described in "Exchange Offers—Purpose and Effect of the Exchange Offers" and "—Procedures for Tendering—Your Representations to Us" in this prospectus and in the applicable letter of transmittal. In addition, if you are a broker-dealer who receives new Notes for your own account in exchange for outstanding Notes that were acquired by you as a result of market-making activities or other trading activities, you will be required to acknowledge that you will deliver a prospectus in connection with any resale by you of such new Notes.

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We will not receive any proceeds from any sale of new Notes by broker-dealers. New Notes received by broker-dealers for their own account pursuant to the applicable exchange offer may be sold from time to time in one or more transactions:

•: in the over-the-counter market;
•: in negotiated transactions;
•: through the writing of options on the new Notes or a combination of the preceding methods of resale;
•: at market prices prevailing at the time of resale; and
•: at prices related to such prevailing market prices or negotiated prices.

Any such resale may be made directly to purchasers or to or through brokers or dealers who may receive compensation in the form of commissions or concessions from any such broker-dealer or the purchasers of any such new Notes. Any broker-dealer that resells new Notes that were received by it for its own account pursuant to the exchange offers and any broker or dealer that participates in a distribution of such new Notes may be deemed to be an "underwriter" within the meaning of the Securities Act and any profit from any such resale of new notes and any commissions or concessions received by any such persons may be deemed to be underwriting compensation under the Securities Act. Each letter of transmittal states that by acknowledging that it will deliver and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an "underwriter" within the meaning of the Securities Act.

For a period of one year after the consummation of each exchange offer, we will promptly send additional copies of this prospectus and any amendment or supplement to this prospectus to any broker-dealer that requests such documents in a letter of transmittal. We have agreed to pay all expenses incident to each exchange offer (including the expenses of one counsel for the holders of the outstanding Notes) other than commissions or concessions of any broker-dealers and will indemnify the holders of the outstanding Notes (including any broker-dealers) against certain liabilities, including liabilities under the Securities Act.

VALIDITY OF THE NEW NOTES

The validity of the new Notes will be passed upon for us by Vinson & Elkins L.L.P., Houston, Texas.

EXPERTS

The consolidated financial statements of Plains All American Pipeline, L.P. as of December 31, 2003 and 2002 and for each of the three years in the period ended December 31, 2003 and the balance sheet of Plains AAP, L.P. as of December 31, 2003 included in this Prospectus have been so included in reliance on the reports of PricewaterhouseCoopers LLP, an independent registered public accounting firm, given on the authority of said firm as experts in auditing and accounting.

The combined financial statements of the Capline Pipe Line Business, Capwood Pipe Line Business and Patoka Pipe Line Business (the "Businesses") as of December 31, 2003 and 2002 and for the year ended December 31, 2003 and for the periods from February 14, 2002 through December 31, 2002 and January 1, 2002 through February 13, 2002 included in this Prospectus have been so included in reliance on the report (which report contains an explanatory paragraph relating to the Businesses being sold to Plains All American Pipeline, L.P. as described in Note 6 to the combined financial statements) of PricewaterhouseCoopers LLP, an independent registered public accounting firm, given on the authority of said firm as experts in auditing and accounting.

139

The consolidated financial statements of Link Energy LLC and its subsidiaries (Successor Company) at December 31, 2003 and for the period from March 1, 2003 to December 31, 2003 and of EOTT Energy Partners, L.P. and its subsidiaries (Predecessor Company) at December 31, 2002 and for the period from January 1, 2003 to February 28, 2003 and for each of the two years in the period ended December 31, 2002 included in this Prospectus have been so included in reliance on the reports (which contain an explanatory paragraph relating to the Successor Company's and Predecessor Company's ability to continue as a going concern as described in Note 3 to the consolidated financial statements, an explanatory paragraph relating to the adoption of fresh start accounting as described in Note 1 to the consolidated financial statements and an explanatory paragraph relating to the restatement of the financial results as described in Notes 1 and 10 to the consolidated financial statements) of PricewaterhouseCoopers LLP, an independent registered public accounting firm, given on the authority of said firm as experts in auditing and accounting.

WHERE YOU CAN FIND MORE INFORMATION

We file annual, quarterly and special reports and other information with the Securities and Exchange Commission under the Securities Exchange Act of 1934. You can inspect and/or copy these reports and other information at offices maintained by the SEC, including:

•: the principal offices of the SEC located at Judiciary Plaza, 450 Fifth Street, N.W., Room 1024, Washington, D.C. 20549;
•: the SEC's website at http://www.sec.gov.

In addition, please call the SEC at 1-800-732-0330 for further information on their public reference room.

Further, our common units are listed on the New York Stock Exchange, and you can inspect similar information at the offices of the New York Stock Exchange, located at 20 Broad Street, New York, New York 10005.

You can read and copy any of our materials filed with the SEC at our website at http://www.paalp.com or you may request a copy of these filings at no cost by making written or telephone requests for copies to:

Plains All American Pipeline, L.P.
333 Clay Street, Suite 1600
Houston, Texas 77002
Attention: Tim Moore
Telephone: (713) 646-4100

We intend to furnish or make available to our unitholders within 75 days following the close of our fiscal year end annual reports containing audited financial statements prepared in accordance with generally accepted accounting principles and furnish or make available within 40 days following the close of each fiscal quarter quarterly reports containing unaudited interim financial information, including the information required by Form 10-Q, for the first three fiscal quarters of each of our fiscal years. Our annual report will include a description of any transactions with the general partner or its affiliates, and of fees, commissions, compensation and other benefits paid, or accrued to the general partner or its affiliates for the fiscal year completed, including the amount paid or accrued to each recipient and the services performed.

You should rely only on the information provided in this prospectus. The information contained on our website is not a part of this prospectus. We have not authorized anyone else to provide you with any information. You should not assume that the information provided in this prospectus is accurate as of any date other than the date on the cover of this prospectus.

140

FORWARD-LOOKING STATEMENTS

All statements, other than statements of historical fact, included in this prospectus 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 for future operations. These statements reflect our current views with respect to future events, based on what we believe are reasonable assumptions. Certain factors could cause actual results to differ materially from results anticipated in the forward looking statements. These factors include, but are not limited to:

•: abrupt or severe production declines or production interruptions in outer continental shelf production located offshore California and transported on our pipeline system;
•: the success of our risk management activities;
•: the availability of, and our ability to consummate, acquisition or combination opportunities;
•: our access to capital to fund additional acquisitions and our ability to obtain debt or equity financing on satisfactory terms;
•: successful integration and future performance of acquired assets or businesses;
•: environmental liabilities that are not covered by an indemnity, insurance or existing reserves;
•: maintenance of our credit rating and ability to receive open credit from our suppliers;
•: declines in volumes shipped on the Basin Pipeline and our other pipelines by third party shippers;
•: the availability of adequate third party production volumes for transportation and marketing in the areas in which we operate;
•: successful third party drilling efforts in areas in which we operate pipelines or gather crude oil;
•: demand for various grades of crude oil and resulting changes in pricing conditions or transmission throughput requirements;
•: fluctuations in refinery capacity in areas supplied by our transmission lines;
•: the effects of competition;
•: continued creditworthiness of, and performance by, counter parties;
•: the impact of crude oil price fluctuations;
•: the impact of current and future laws and governmental regulations;
•: shortages or cost increases of power supplies, materials or labor;
•: weather interference with business operations or project construction;
•: the currency exchange rate of the Canadian dollar;
•: fluctuations in the debt and equity markets, including the price of our units at the time of vesting under our Long-Term Incentive Plan; and
•: general economic, market or business conditions.

Other factors described herein, or factors that are unknown or unpredictable, could also have a material adverse effect on future results. Please read "Risk Factors" beginning on page 6 of this prospectus. Except as required by securities laws, we do not intend to update these forward looking statements and information.

141

INDEX TO FINANCIAL STATEMENTS


PLAINS ALL AMERICAN PIPELINE, L.P.
	UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS:
		Introduction
		Unaudited Pro Forma Combined Statement of Operations for the nine months ended September 30, 2004
		Unaudited Pro Forma Combined Statement of Operations for the twelve months ended December 31, 2003
		Notes to Unaudited Pro Forma Combined Financial Statements
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
	UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS:
		Unaudited Consolidated Balance Sheets as of September 30, 2004 and December 31, 2003
		Unaudited Consolidated Statements of Operations for the nine months ended September 30, 2004 and 2003
		Unaudited Consolidated Statements of Cash Flows for the nine months ended September 30, 2004 and 2003
		Unaudited Consolidated Statement of Partners' Capital for the nine months ended September 30, 2004
		Unaudited Consolidated Statements of Comprehensive Income for the nine months ended September 30, 2004 and 2003
		Unaudited Consolidated Statement of Changes in Accumulated Other Comprehensive Income for the nine months ended September 30, 2004
		Unaudited Notes to the Consolidated Financial Statements
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
	CONSOLIDATED FINANCIAL STATEMENTS:
		Report of Independent Registered Public Accounting Firm
		Consolidated Balance Sheets as of December 31, 2003 and 2002
		Consolidated Statements of Operations for the years ended December 31, 2003, 2002 and 2001
		Consolidated Statements of Cash Flows for the years ended December 31, 2003, 2002 and 2001
		Consolidated Statement of Changes in Partners' Capital for the years ended December 31, 2003, 2002 and 2001
		Consolidated Statements of Comprehensive Income for the years ended December 31, 2003, 2002 and 2001
		Consolidated Statement of Changes in Accumulated Other Comprehensive Income (loss) for the years ended December 31, 2003, 2002 and 2001
		Notes to Consolidated Financial Statements

F-1

LINK ENERGY LLC
	UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS:
		Unaudited Condensed Consolidated Statements of Operations for the three months ended March 31, 2004 (Successor Company), one month ended March 31, 2003 (Successor Company) (Restated), and two months ended February 28, 2003 (Predecessor Company) (Restated)
		Unaudited Condensed Consolidated Balance Sheets as of March 31, 2004 and December 31, 2003 (Successor Company)
		Unaudited Condensed Consolidated Statements of Cash Flows for the three months ended March 31, 2004 (Successor Company), one month ended March 31, 2003 (Successor Company) (Restated), and two months ended February 28, 2003 (Predecessor Company) (Restated)
		Unaudited Condensed Consolidated Statement of Members' Capital for the three months ended March 31, 2004 (Successor Company)
		Notes to Unaudited Condensed Consolidated Financial Statements
LINK ENERGY LLC
	CONSOLIDATED FINANCIAL STATEMENTS:
		Report of Independent Registered Public Accounting Firm (Successor Company)
		Report of Independent Registered Public Accounting Firm (Predecessor Company)
		Consolidated Statements of Operations for the ten months ended December 31, 2003 (Successor Company) (Restated), two months ended February 28, 2003 (Predecessor Company) (Restated) and the years ended December 31, 2002 and 2001 (Predecessor Company) (Restated)
		Consolidated Balance Sheets as of December 31, 2003 (Successor Company) (Restated) and 2002 (Predecessor Company) (Restated)
		Consolidated Statements of Cash Flows for the ten months ended December 31, 2003 (Successor Company) (Restated), two months ended February 28, 2003 (Predecessor Company) (Restated) and the years ended December 31, 2002 and 2001 (Predecessor Company) (Restated)
		Consolidated Statements of Members'/Partners' Capital for the ten months ended December 31, 2003 (Successor Company) (Restated), two months ended February 28, 2003 (Predecessor Company) (Restated) and the years ended December 31, 2002 and 2001 (Predecessor Company) (Restated)
		Notes to Consolidated Financial Statements (As Restated)
		Schedule II—Valuation and Qualifying Accounts and Reserves

F-2

CAPLINE PIPE LINE BUSINESS, CAPWOOD PIPE LINE BUSINESS AND PATOKA PIPE LINE BUSINESS
	COMBINED FINANCIAL STATEMENTS:
		Report of Independent Auditors
		Combined Balance Sheets as of December 31, 2003 and 2002
		Combined Statements of Income and Owner's Net Investment for the year ended December 31, 2003 and for the periods from January 1, 2002 to February 13, 2002 and February 14, 2002 to December 31, 2002
		Combined Statements of Cash Flows for the year ended December 31, 2003 and for the periods from January 1, 2002 to February 13, 2002 and February 14, 2002 to December 31, 2002
		Notes to Combined Financial Statements
PLAINS AAP, L.P.
	UNAUDITED FINANCIAL STATEMENT:
		Balance Sheet as of June 30, 2004
		Notes to the Financial Statement
PLAINS AAP, L.P.
	FINANCIAL STATEMENT:
		Report of Independent Registered Public Accounting Firm
		Balance Sheet as of December 31, 2003
		Notes to the Financial Statement

F-3

PLAINS ALL AMERICAN PIPELINE, L.P.
UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS

Plains All American Pipeline, L.P. ("PAA") is a publicly traded Delaware limited partnership 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. The following unaudited pro forma financial statements are presented to give effect to the transactions described below:

The acquisition of the North American crude oil and pipeline operations of Link Energy LLC, ("Link Energy" and the "Link acquisition"). The acquisition price of approximately $332 million includes the assumption of liabilities and net working capital items and transaction and other acquisition costs. The acquisition closed and was effective on April 1, 2004 and has been accounted for using the purchase method of accounting.

The acquisition of Shell Pipeline Company LP's ("SPLC") interest in certain entities. The principal assets of the entities include interests in the Capline Pipe Line System, the Capwood Pipe Line System and the Patoka Pipe Line System (referred to in this report as "the SPLC acquisition"). The purchase price, including transaction and closing costs, was approximately $158.5 million. The acquisition closed and was effective on March 1, 2004. The acquisition has been accounted for using the purchase method of accounting.

The transactions described above are included in PAA's historical unaudited consolidated balance sheet as of September 30, 2004. Accordingly, a pro forma balance sheet is not presented. The unaudited pro forma statements of operations for the nine months ended September 30, 2004 and the year ended December 31, 2003 are based upon the following:

1): the historical consolidated statements of operations of PAA for the nine months ended September 30, 2004 and the year ended December 31, 2003;
2): the historical consolidated statements of operations of Link Energy for the three months ended March 31, 2004 and the year ended December 31, 2003; and
3): the historical combined statements of operations for the businesses acquired in the SPLC acquisition for the two months ended February 29, 2004 and the year ended December 31, 2003.

The unaudited pro forma combined statements of operations are not necessarily indicative of the results of the actual or future operations that would have been achieved had the transactions occurred at the dates assumed (as noted below). The unaudited pro forma combined statements of operations should be read in conjunction with: i) the notes thereto; ii) the historical unaudited financial statements of PAA for the nine months ended September 30, 2004; iii) the historical unaudited financial statements of Link Energy for the three months ended March 31, 2004; and iv) the audited financial statements of PAA for the year ended December 31, 2003, as well as those for Link Energy and the businesses acquired in the SPLC acquisition, for the same period.

The following unaudited pro forma combined statements of operations for the nine months ended September 30, 2004 and the year ended December 31, 2003 have been prepared as if the transactions described above had taken place at the beginning of the period presented.

F-4

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
UNAUDITED PRO FORMA COMBINED STATEMENT OF OPERATIONS
For the Nine Months Ended September 30, 2004
(in thousands, except per unit data)

		Plains All American Historical			Link Energy Historical			SPLC Acquisition Historical		Pro Forma Acquisition Adjustments			Plains All American Pro Forma
REVENUES		$	14,803,384		$	40,682		$	7,416	$	(465	)(a)	$	14,851,017
COSTS AND EXPENSES
Purchases and related costs			14,400,426			8,081			—		(465	)(a)		14,408,042
Field operating costs (excluding LTIP charge)			158,053			20,725			2,023		—			180,801
LTIP charge—operations			567			—			—		—			567
General and administrative expenses (excluding LTIP charge)			54,565			18,514			—		—			73,079
LTIP charge — general and administrative			3,661			—			—		—			3,661
Depreciation and amortization			45,887			5,060			874		(5,934 2,571	)(b) (c)		48,458

	Total costs and expenses		14,663,159			52,380			2,897		(3,828	)		14,714,608

	Other, net		—			(20	)		—		—			(20	)
	Gains on sales of assets		643			730	(e)		—		—			1,373

OPERATING INCOME			140,868			(10,988	)		4,519		3,363			137,762
OTHER INCOME/(EXPENSE)
Interest expense			(32,201	)		(11,531	)		—		(2,893	)(d)		(46,625	)
Interest and other income (expense), net			(250	)		(24	)		—		—			(274	)

Income from continuing operations before cumulative effect of change in accounting principle			108,417			(22,543	)		4,519		470			90,863
Cumulative effect of change in accounting principle			(3,130	)		—			—		—			(3,130	)

NET INCOME (LOSS) FROM CONTINUING OPERATIONS		$	105,287		$	(22,543	)	$	4,519	$	470		$	87,733

NET INCOME FROM CONTINUING OPERATIONS—LIMITED PARTNERS		$	97,692										$	80,489

NET INCOME FROM CONTINUING OPERATIONS—GENERAL PARTNER		$	7,595										$	7,244

BASIC AND DILUTED NET INCOME FROM CONTINUING OPERATIONS PER LIMITED PARTNER UNIT
Income from continuing operations before cumulative effect of change in accounting principle		$	1.63										$	1.35
Cumulative effect of change in accounting principle			(0.05	)										(0.05	)

Net income from continuing operations		$	1.58										$	1.30

BASIC AND DILUTED WEIGHTED AVERAGE UNITS OUTSTANDING			61,929											61,929

See notes to unaudited pro forma combined financial statements

F-5

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
UNAUDITED PRO FORMA COMBINED STATEMENT OF OPERATIONS
For the Twelve Months Ended December 31, 2003
(in thousands, except per unit data)

					Link Energy Historical
					Successor Company			Predecessor Company
		Plains All American Historical			Ten Months Ended December 31, 2003			Two Months Ended February 28, 2003			SPLC Acquisition Historical		Pro Forma Acquisition Adjustments			Plains All American Pro Forma
REVENUES		$	12,589,849		$	153,033		$	31,635		$	35,855	$	(2,828	)(a)	$	12,807,544
COSTS AND EXPENSES
Purchases and related costs			12,232,536			23,863			4,521			—		(2,828	)(a)		12,258,092
Field operating costs (excluding LTIP charge)			134,177			70,102			13,020			10,574		—			227,873
LTIP charge—operations			5,727			—			—			—		—			5,727
General and administrative expenses (excluding LTIP charge)			49,969			45,959			6,846			1,275		—			104,049
LTIP charge—general and administrative			23,063			—			—			—		—			23,063
Depreciation and amortization			46,821			17,161			4,642			5,264		(27,067 11,607	)(b) (c)		58,428

	Total costs and expenses		12,492,293			157,085			29,029			17,113		(18,288	)		12,677,232

	Other, net		—			1,982			8			—		—			1,990
	Gains on sales of assets		648			11,885	(e)		—			—		(11,700	)(f)		833

OPERATING INCOME			98,204			9,815			2,614			18,742		3,760			133,135
OTHER INCOME/(EXPENSE)
Interest expense			(35,226	)		(32,708	)		(5,645	)		—		(13,206	)(d)		(86,785	)
Interest and other income (expense), net			(3,530	)		192			156			—		—			(3,182	)

Income (Loss) from Continuing Operations Before Reorganization Items, Net Gain on Discharge of Debt and Fresh Start Adjustments			59,448			(22,701	)		(2,875	)		18,742		(9,446	)		43,168
Reorganization Items			—			—			(7,330	)		—		—			(7,330	)
Net Gain on Discharge of Debt			—			—			131,560			—		—			131,560
Fresh Start Adjustments			—			—			(56,771	)		—		—			(56,771	)

NET INCOME (LOSS) FROM CONTINUING OPERATIONS		$	59,448		$	(22,701	)	$	64,584		$	18,742	$	(9,446	)	$	110,627

NET INCOME FROM CONTINUING OPERATIONS—LIMITED PARTNERS		$	53,473													$	103,628

NET INCOME FROM CONTINUING OPERATIONS—GENERAL PARTNER		$	5,975													$	6,999

BASIC NET INCOME FROM CONTINUING OPERATIONS PER LIMITED PARTNER UNIT		$	1.01													$	1.96

DILUTED NET INCOME FROM CONTINUING OPERATIONS PER LIMITED PARTNER UNIT		$	1.00													$	1.94

BASIC WEIGHTED AVERAGE UNITS OUTSTANDING			52,743														52,743

DILUTED WEIGHTED AVERAGE UNITS OUTSTANDING			53,400														53,400

See notes to unaudited pro forma combined financial statements

F-6

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS

Note 1—Acquisitions

Link Acquisition

The Link acquisition presented in these pro forma statements has been accounted for using the purchase method of accounting and the purchase price has been allocated in accordance with Statement of Financial Accounting Standards No. 141, "Business Combinations." The acquisition consists of the North American crude oil and pipeline operations of Link Energy. The purchase price of approximately $332 million includes cash paid of approximately $268 million and approximately $64 million of net liabilities assumed and acquisition related costs. The acquisition closed and was effective on April 1, 2004. The total purchase price and the related allocation are preliminary as we are in the process of evaluating certain estimates. The purchase price allocation is set forth in the table below (in millions):

Fair value of assets acquired:
Property and equipment		$	262.3
Inventory			1.1
Linefill			48.4
Inventory in third party assets			15.1
Goodwill			5.0
Other long term assets			0.2

	Subtotal		332.1
Accounts receivable			405.4
Other current assets			1.8

	Subtotal		407.2
	Total assets acquired		739.3
Fair value of liabilities assumed:
Accounts payable and accrued liabilities			(455.4	)
Other current liabilities			(8.5	)
Other long-term liabilities			(7.4	)

	Total liabilities assumed		(471.3	)
Cash paid for acquisition		$	268.0	⁽¹⁾

⁽¹⁾: Cash paid is net of $5.5 million subsequently returned to us from an indemnity escrow account and does not include the subsequent payment of various transaction and other acquisition related costs.

SPLC Acquisition

The SPLC acquisition presented in these pro forma statements has been accounted for using the purchase method of accounting and the purchase price has been allocated in accordance with Statement of Financial Accounting Standards No. 141, "Business Combinations." The purchase consists of the acquisition of Shell Pipeline Company LP's ("SPLC") interest in certain entities. The principal assets of the entities include interests in certain businesses from Shell Pipeline Company, including its interests in the Capline Pipe Line System, the Capwood Pipe Line System and the Patoka Pipe Line System. The purchase price of approximately $158.5 million includes transaction and closing costs. The

F-7

acquisition closed and was effective on March 1, 2004. The purchase price allocation is as follows (in millions):

Crude oil pipelines and facilities	$	151.4
Crude oil storage and terminal facilities		5.7
Land		1.3
Office equipment and other		0.1

Total	$	158.5

Note 2—Pro Forma Adjustments

The pro forma adjustments are as follows:

a.: Elimination of purchases and sales related to transactions between PAA and Link Energy.
b.: Reversal of historical depreciation in the amounts of $5.1 million and $0.9 million in the nine-month period ended September 30, 2004 as recorded by Link Energy and SPLC for the three months and two months prior to acquisition, respectively and $21.8 million and $5.3 million for the year ended December 31, 2003 as recorded by Link Energy and SPLC, respectively.
c.: Recording of depreciation based on the straight-line method over average useful lives ranging from 5 to 50 years in the amounts of $1.9 million and $0.7 million in the nine-month period ended September 30, 2004 for the assets acquired from Link Energy and SPLC for the three months and two months prior to acquisition, respectively and $7.6 million and $4.0 million for the year ended December 31, 2003 for the assets acquired from Link Energy and SPLC, respectively.
d.: Adjustment to interest expense for the increase in long-term debt from draws on our revolving credit facilities to finance the acquisitions using an average interest rate of 3.1% for both periods presented. The increase in long-term debt of $268 million for the Link acquisition resulted in incremental interest expense on a pro forma basis of $2.1 million for the three months prior to acquisition in the nine-month period ended September 30, 2004 and $8.3 million for the year ended December 31, 2003. The increase in long-term debt of $158.5 million for the SPLC acquisition resulted in incremental interest expense on a pro forma basis of $0.8 million for the two months prior to acquisition in the nine-month period ended September 30, 2004 and $4.9 million for the year ended December 31, 2003. The impact to interest expense of a ¹/8% change in interest rates would be approximately $0.5 million per year.
e.: Reclassification of gain on sale of assets from Other (Income) Expense as shown in Link Energy's historical financial statements to conform to PAA's presentation.
f.: Elimination of the gain on sale of assets in October 2003 resulting from Link Energy's sale of the ArkLaTex assets to PAA, which is included in Link Energy's historical financial statements.

F-8

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands, except unit data)

		September 30, 2004			December 31, 2003
		(unaudited)
ASSETS
CURRENT ASSETS
Cash and cash equivalents		$	4,547		$	4,137
Trade accounts receivable, net			846,347			590,645
Inventory			242,312			105,967
Other current assets			55,501			32,225

	Total current assets		1,148,707			732,974

PROPERTY AND EQUIPMENT			1,824,314			1,272,634
Accumulated depreciation			(165,589	)		(121,595	)

			1,658,725			1,151,039

OTHER ASSETS
Pipeline linefill in owned assets			159,985			95,928
Inventory in third party assets			46,359			26,725
Other, net			92,245			88,965

	Total assets	$	3,106,021		$	2,095,631

LIABILITIES AND PARTNERS' CAPITAL
CURRENT LIABILITIES
Accounts payable		$	965,265		$	603,460
Due to related parties			33,447			26,981
Short-term debt			122,882			127,259
Other current liabilities			77,641			44,219

	Total current liabilities		1,199,235			801,919

LONG-TERM LIABILITIES
Long-term debt under credit facilities			40,408			70,000
Senior notes, net of unamortized discount of $2,820 and $1,009, respectively			797,180			448,991
Other long-term liabilities and deferred credits			24,780			27,994

	Total liabilities		2,061,603			1,348,904

COMMITMENTS AND CONTINGENCIES (NOTE 10)
PARTNERS' CAPITAL
Common unitholders (62,740,218 and 49,502,556 units outstanding at September 30, 2004, and December 31, 2003, respectively)			895,479			744,073
Class B common unitholder (1,307,190 units outstanding at each date)			18,302			18,046
Class C common unitholders (3,245,700 units and no units outstanding at September 30, 2004, and December 31, 2003, respectively)			98,856			—
Subordinated unitholders (no units and 7,522,214 units outstanding at September 30, 2004, and December 31, 2003, respectively)			—			(39,913	)
General partner			31,781			24,521

	Total partners' capital		1,044,418			746,727

		$	3,106,021		$	2,095,631

The accompanying notes are an integral part of these consolidated financial statements.

F-9

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per unit data)

		Nine Months Ended September 30,
		2004			2003
		(unaudited)
REVENUES
Crude oil and LPG sales		$	14,218,956		$	8,572,569
Other gathering, marketing, terminalling and storage revenues			27,920			22,777
Pipeline margin activities revenues			424,165			376,660
Pipeline tariff activities revenues			132,343			72,768

	Total revenues		14,803,384			9,044,774
COSTS AND EXPENSES
Crude oil and LPG purchases and related costs			13,992,768			8,417,316
Pipeline margin activities purchases			407,658			362,250
Field operating costs (excluding LTIP charge)			158,053			100,301
LTIP charge—operations			567			1,390
General and administrative expenses (excluding LTIP charge)			54,565			37,431
LTIP charge—general and administrative			3,661			6,006
Depreciation and amortization			45,887			34,164

	Total costs and expenses		14,663,159			8,958,858

Gains on sales of assets			643			608

OPERATING INCOME			140,868			86,524

OTHER INCOME/(EXPENSE)
Interest expense (net of $207 and $461 capitalized for the nine month periods, respectively)			(32,201	)		(26,480	)
Interest income and other, net			(250	)		(424	)

Income before cumulative effect of change in accounting principle			108,417			59,620
Cumulative effect of change in accounting principle			(3,130	)		—

NET INCOME		$	105,287		$	59,620

NET INCOME-LIMITED PARTNERS		$	97,692		$	54,958

NET INCOME-GENERAL PARTNER		$	7,595		$	4,662

BASIC NET INCOME PER LIMITED PARTNER UNIT
Income before cumulative effect of change in accounting principle		$	1.63		$	1.06
Cumulative effect of change in accounting principle			(0.05	)		—

Basic net income per limited partner unit		$	1.58		$	1.06

DILUTED NET INCOME PER LIMITED PARTNER UNIT
Income before cumulative effect of change in accounting principle		$	1.63		$	1.05
Cumulative effect of change in accounting principle			(0.05	)		—

Diluted net income per limited partner unit		$	1.58		$	1.05

BASIC WEIGHTED AVERAGE UNITS OUTSTANDING			61,929			51,735

DILUTED WEIGHTED AVERAGE UNITS OUTSTANDING			61,929			52,407

The accompanying notes are an integral part of these consolidated financial statements.

F-10

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

			Nine Months Ended September 30,
			2004			2003
			(unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income			$	105,287		$	59,620
Adjustments to reconcile to cash flows from operating activities:
	Depreciation and amortization			45,887			34,164
	Cumulative effect of accounting change			3,130			—
	Change in derivative fair value			(1,431	)		1,731
	Noncash portion of LTIP charge			4,228			3,700
	Gain on foreign currency revaluation			(3,423	)		—
	Noncash amortization of terminated interest rate swap			1,092			—
	Loss on refinancing of debt			658			—
	Gain on sale of assets			(643	)		(608	)
	Net cash paid for terminated swaps			(1,465	)		—
Changes in assets and liabilities, net of acquisitions:
	Trade accounts receivable and other			(285,123	)		132,366
	Inventory			(127,391	)		(84,690	)
	Accounts payable and other current liabilities			365,784			84,717
	Settlement of environmental indemnities			—			4,600
	Due to related parties			6,461			500

		Net cash provided by operating activities		113,051			236,100

CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid in connection with acquisitions				(495,715	)		(99,897	)
Additions to property and equipment				(63,596	)		(52,180	)
Cash paid for linefill in assets owned				(10,242	)		(40,449	)
Proceeds from sales of assets				2,234			7,076
Other investing activities				—			232

		Net cash used in investing activities		(567,319	)		(185,218	)

CASH FLOWS FROM FINANCING ACTIVITIES
Net repayments on long-term revolving credit facility				(29,977	)		(13,122	)
Net borrowings on working capital revolving credit facility				34,700			—
Net repayments on short-term letter of credit and hedged inventory facility				(42,234	)		(67,315	)
Principal payments on senior secured term loan				—			(43,000	)
Cash paid in connection with financing arrangements				(3,172	)		(87	)
Proceeds from the issuance of senior notes				346,427			—
Net proceeds from the issuance of common units				262,132			161,905
Distributions paid to unitholders and general partner				(114,468	)		(89,346	)

		Net cash provided by (used in) financing activities		453,408			(50,965	)

Effect of translation adjustment on cash				1,270			—
Net increase (decrease) in cash and cash equivalents				410			(83	)
Cash and cash equivalents, beginning of period				4,137			3,501

Cash and cash equivalents, end of period			$	4,547		$	3,418

Cash paid for interest, net of amounts capitalized			$	23,366		$	24,286

The accompanying notes are an integral part of these consolidated financial statements.

F-11

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF PARTNERS' CAPITAL

(in thousands)

					Class B Common Units				Class C Common Units
	Common Units												Subordinated Units									Total Partners' Capital Amount
	Common Units												Subordinated Units					General Partners' Amount			Total Units
	Units	Amount			Units	Amount			Units	Amount			Units		Amount			General Partners' Amount			Total Units
	(unaudited)
Balance at December 31, 2003	49,502	$	744,073		1,307	$	18,046		—	$	—		7,523		$	(39,913	)	$	24,521		58,332	$	746,727
Issuance of common units	4,968		157,568		—		—		—		—		—			—			3,371		4,968		160,939
Issuance of common units under LTIP	362		11,772		—		—		—		—		—			—			238		362		12,010
Private placement of Class C common units	—		—		—		—		3,246		98,782		—			—			2,041		3,246		100,823
Issuance of units for acquisition contingent consideration	385		13,082		—		—		—		—		—			—			267		385		13,349
Distributions	—		(96,531	)	—		(2,225	)	—		(3,700	)	—			(4,231	)		(7,781	)	—		(114,468	)
Other comprehensive income	—		18,029		—		410		—		624		—			(841	)		1,529		—		19,751
Net income	—		91,027		—		2,071		—		3,150		—			1,444			7,595		—		105,287
Conversion of subordinated units	7,523		(43,541	)	—		—		—		—		(7,523	)		43,541			—		—		—

Balance at September 30, 2004	62,740	$	895,479		1,307	$	18,302		3,246	$	98,856		—		$	—		$	31,781		67,293	$	1,044,418

The accompanying notes are an integral part of these consolidated financial statements.

F-12

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME AND
CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME

(in thousands)

Statements of Comprehensive Income

	Nine Months Ended September 30,
	2004		2003
	(unaudited)
Net income	$	105,287	$	59,620
Other comprehensive income		19,751		61,599

Comprehensive income	$	125,038	$	121,219

Statement of Changes in Accumulated Other Comprehensive Income

			Net Deferred Gain (Loss) on Derivative Instruments			Currency Translation Adjustments		Total
			(unaudited)
Balance at December 31, 2003			$	(7,692	)	$	39,861	$	32,169
	Current period activity:
		Reclassification adjustments for settled contracts		20,265			—		20,265
		Changes in fair value of outstanding hedge positions		(12,160	)		—		(12,160	)
		Currency translation adjustment		—			11,646		11,646

	Total period activity			8,105			11,646		19,751

Balance at September 30, 2004			$	413		$	51,507	$	51,920

The accompanying notes are an integral part of these consolidated financial statements.

F-13

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Note 1—Organization and Accounting Policies

The accompanying consolidated financial statements and related notes present (i) our consolidated financial position as of September 30, 2004, and December 31, 2003, (ii) the results of our consolidated operations for the nine months ended September 30, 2004 and 2003, (iii) our consolidated cash flows for the nine months ended September 30, 2004 and 2003, (iv) our consolidated changes in partners' capital for the nine months ended September 30, 2004, (v) our consolidated comprehensive income for the nine months ended September 30, 2004 and 2003, and (vi) our changes in consolidated accumulated other comprehensive income for the nine months ended September 30, 2004. The financial statements have been prepared in accordance with the instructions for interim reporting as prescribed by the Securities and Exchange Commission. All adjustments (consisting only of normal recurring adjustments) that in the opinion of management were necessary for a fair statement of the results for the interim periods have been reflected. All significant intercompany transactions have been eliminated. Certain reclassifications are made to prior period amounts to conform to current period presentation. The results of operations for the nine months ended September 30, 2004 should not be taken as indicative of the results to be expected for the full year. The consolidated interim financial statements should be read in conjunction with our consolidated financial statements and notes thereto presented in our 2003 Annual Report on Form 10-K/A Amendment No. 1.

Foreign Currency Transactions

For subsidiaries whose functional currency is not the U.S. Dollar, assets and liabilities are translated at period end rates of exchange and revenues and expenses are translated at average exchange rates prevailing for each month. Translation adjustments for the asset and liability accounts are included as a separate component of other comprehensive income in partners' capital. Currency transaction gains and losses are recorded in income.

Change in Accounting Principle

F-14

and into "Inventory in Third Party Assets" (a long-term asset), which is now reflected as a separate line item within other assets on the consolidated balance sheet.

This change in accounting principle is effective January 1, 2004 and is reflected in the consolidated statement of operations for the nine months ended September 30, 2004 and the consolidated balance sheet as of September 30, 2004, included herein. The cumulative effect of this change in accounting principle as of January 1, 2004, is a charge of approximately $3.1 million, representing a reduction in Inventory of approximately $1.7 million, a reduction in Pipeline Linefill of approximately $30.3 million and an increase in Inventory in Third Party Assets of $28.9 million. The pro forma impact for the first nine months of 2003 would have been an increase to net income of approximately $2.2 million ($0.04 per basic and diluted limited partner unit) resulting in pro forma net income of $61.8 million and pro forma basic net income per limited partner unit of $1.10 and pro forma diluted net income per limited partner unit of $1.09.

Note 2—Acquisitions and Dispositions

The following acquisitions were made in 2004 and were accounted for under Statement of Financial Accounting Standards ("SFAS") No. 141 "Business Combinations."

Link Energy LLC

On April 1, 2004, we completed the acquisition of all of the North American crude oil and pipeline operations of Link Energy LLC ("Link") for approximately $332 million, including $268 million of cash (net of approximately $5.5 million subsequently returned to us from an indemnity escrow account) and approximately $64 million of net liabilities assumed and acquisition-related costs. The Link crude oil business consists of approximately 7,000 miles of active crude oil pipeline and gathering systems, over 10 million barrels of crude oil storage capacity, a fleet of approximately 200 owned or leased trucks and approximately 2 million barrels of crude oil linefill and working inventory. The Link assets complement our assets in West Texas and along the Gulf Coast and allow us to expand our presence in the Rocky Mountain and Oklahoma/Kansas regions. The results of operations and assets from this acquisition (the "Link acquisition") have been included in our consolidated financial statements and both our pipeline operations and gathering, marketing, terminalling and storage operations segments since April 1, 2004.

F-15

The purchase price was allocated as follows and includes goodwill primarily related to Link's gathering and marketing business (in millions):

Fair value of assets acquired:
Property and equipment		$	262.3
Inventory			1.1
Linefill			48.4
Inventory in third party assets			15.1
Goodwill			5.0
Other long term assets			0.2

	Subtotal		332.1
Accounts receivable⁽¹⁾			405.4
Other current assets			1.8

	Subtotal		407.2
Total assets acquired			739.3
Fair value of liabilities assumed:
Accounts payable and accrued liabilities⁽¹⁾			(455.4	)
Other current liabilities			(8.5	)
Other long-term liabilities			(7.4	)

	Total liabilities assumed		(471.3	)
Cash paid for acquisition⁽²⁾		$	268.0

⁽¹⁾: Accounts receivable and accounts payable are gross and do not reflect the adjustment of approximately $250 million to net settle, based on contractual agreements with our counterparties.
⁽²⁾: Cash paid is net of $5.5 million subsequently returned to us from an indemnity escrow account and does not include the subsequent payment of various transaction and other acquisition related costs.

We are in the process of evaluating certain estimates made in the purchase price and related allocation; thus, the purchase price and allocation are both subject to refinement. In addition, we anticipate making capital expenditures of approximately $20.0 million ($9.0 million in 2004) to upgrade certain of the assets and comply with certain regulatory requirements.

The acquisition was initially funded with cash on hand, borrowings under our revolving credit facilities and under a new $200 million, 364-day credit facility and borrowings under our existing revolving credit facilities (see Note 5). In connection with the acquisition, on April 15, 2004, we completed the private placement of 3,245,700 Class C common units to a group of institutional investors. During the third quarter of 2004, we completed a public offering of common units and the sale of an aggregate of $350 million of senior notes. A portion of the proceeds from these transactions was used to retire the $200 million, 364-day credit facility (see Note 7).

On April 2, 2004, the Office of the Attorney General of Texas (the "Texas AG") delivered written notice to us that it was investigating the possibility that the acquisition of Link's assets might reduce competition in one or more markets within the petroleum products industry in the State of Texas. In

F-16

connection with the Link purchase, both PAA and Link completed all necessary filings required under the Hart-Scott-Rodino Act, and the required 30-day waiting period expired on March 24, 2004 without any inquiry or request for additional information from the U.S. Department of Justice or the Federal Trade Commission. Representatives from the Antitrust and Civil Medicaid Fraud Division of the Office of the Attorney General of Texas (the "Texas AG Antitrust Division") indicated their investigation was prompted by complaints received from allegedly interested industry parties regarding the potential impact on competition in the Permian Basin area of West Texas. We understand that similar complaints have been received by the Federal Trade Commission (the "FTC"), and that, consistent with federal-state protocols for conducting joint merger investigations, appropriate federal and state antitrust authorities are coordinating their activities. We have cooperated fully with the antitrust enforcement authorities, including the provision of information at the request of the Texas AG Antitrust Division. We have been informed by the Texas AG Antitrust Division that it is closing its investigation and does not intend to pursue any additional course of action with respect to these assets at this time. We have not yet received an indication from the FTC as to whether it intends to close its investigation.

Capline and Capwood Pipeline Systems

In March 2004, we completed the acquisition of all of Shell Pipeline Company LP's interests in two entities for approximately $158.0 million in cash (including a $15.8 million deposit paid in December 2003) and approximately $0.5 million of transaction and other costs. In December 2003, subsequent to the announcement of the acquisition and in anticipation of closing, we issued approximately 2.8 million common units for net proceeds of approximately $88.4 million, after paying approximately $4.1 million of transaction costs. The proceeds from this issuance were used to pay down our revolving credit facility. At closing, the cash portion of this acquisition was funded from cash on hand and borrowings under our revolving credit facility.

The principal assets of these entities are: (i) an approximate 22% undivided joint interest in the Capline Pipeline System, and (ii) an approximate 76% undivided joint interest in the Capwood Pipeline System. The Capline Pipeline System is a 633-mile, 40-inch mainline crude oil pipeline originating in St. James, Louisiana, and terminating in Patoka, Illinois. The Capwood Pipeline System is a 57-mile, 20-inch mainline crude oil pipeline originating in Patoka, Illinois, and terminating in Wood River, Illinois. The results of operations and assets from this acquisition (the "Capline acquisition") have been included in our consolidated financial statements and in our pipeline operations segment since March 1, 2004. These pipelines provide one of the primary transportation routes for crude oil shipped into the Midwestern U.S., and delivered to several refineries and other pipelines.

The purchase price was allocated as follows (in millions):

Crude oil pipelines and facilities	$	151.4
Crude oil storage and terminal facilities		5.7
Land		1.3
Office equipment and other		0.1

Total	$	158.5

F-17

Pro Forma Data

The following unaudited pro forma data is presented to show pro forma revenues, income before cumulative effect of change in accounting principle, net income, basic and diluted income before cumulative effect of accounting change per limited partner unit and basic and diluted net income per limited partner unit for the Partnership as if the Capline and Link acquisitions had occurred as of the beginning of the periods reported:

	Nine Months Ended September 30,
	2004		2003
	(in millions, except per unit amounts)
Revenues	$	14,851.3	$	9,211.7

Income before cumulative effect of change in accounting principle⁽¹⁾	$	91.2	$	105.3

Net income⁽²⁾	$	88.1	$	101.3

Basic income before cumulative effect of change in accounting principle per limited partner unit⁽¹⁾	$	1.35	$	1.95

Diluted income before cumulative effect of change in accounting principle per limited partner unit⁽¹⁾	$	1.35	$	1.93

Basic net income per limited partner unit⁽²⁾	$	1.30	$	1.87

Diluted net income per limited partner unit⁽²⁾	$	1.30	$	1.86

⁽¹⁾: Includes a net gain in the 2003 period of approximately $67.5 million related to Link's predecessor company's reorganization, discharge of debt and fresh start adjustments.
⁽²⁾: The 2003 period includes the amounts described in note (1) above as well as a loss of approximately $4.0 million related to Link's predecessor company's cumulative effect of change in accounting principle.

Other Acquisitions

The following acquisitions, both individually and in the aggregate, are not material, and thus, no supplemental pro forma information is included herein.

In August 2004, we completed the acquisition of the Schaefferstown Propane Storage Facility from Koch Hydrocarbon, L.P. The total purchase price was approximately $32 million, including transaction costs. In connection with the transaction, the Partnership also acquired an additional $14.2 million of inventory. The transaction was funded through a combination of cash on hand and borrowings under the Partnership's revolving credit facilities. The facility is located approximately 65 miles northwest of Philadelphia near Schaefferstown, Pennsylvania, and has the capacity to store approximately 20.0 million gallons of refrigerated propane. In addition, the facility has 19 bullet storage tanks with an aggregate capacity of 570,000 gallons. Propane is delivered to the facility via truck or pipeline and is transported out of the facility by truck. In addition, the transaction also included approximately 61 acres of land and a truck rack. The results of operations and assets from this acquisition have been included in our consolidated financial statements and our gathering, marketing, terminalling and

F-18

storage operations segment since August 25, 2004. The preliminary purchase price was primarily allocated to property and equipment.

On May 7, 2004, we completed the acquisition of the Cal Ven Pipeline System from Cal Ven Limited, a subsidiary of Unocal Canada Limited. The total purchase price was approximately $19 million, including transaction costs. The transaction was funded through a combination of cash on hand and borrowings under our revolving credit facilities. The Cal Ven Pipeline System includes approximately 195 miles of 8-inch and 10-inch gathering and mainline crude oil pipelines. The system is located in northern Alberta and delivers crude oil into the Rainbow Pipeline System. The Rainbow Pipeline System then transports the crude south to the Edmonton market, where it can be used in local refineries or shipped on connecting pipelines to the U.S. market. The results of operations and assets from this acquisition have been included in our consolidated financial statements and our pipeline operations segment since May 1, 2004.

Shutdown and Sale of Rancho Pipeline System

Note 3—Trade Accounts Receivable

The majority of our trade accounts receivable relate to our gathering and marketing activities and can generally be described as high volume and low margin activities. As is customary in the industry, a portion of these receivables is reflected net of payables to the same counterparty based on contractual agreements. We routinely review our trade accounts receivable balances to identify past due amounts and analyze the reasons such amounts have not been collected. In many instances, such uncollected amounts involve billing delays and discrepancies or disputes as to the appropriate price, volume or quality of crude oil delivered, received or exchanged. We also attempt to monitor changes in the creditworthiness of our customers as a result of developments related to each customer, the industry as a whole and the general economy. Based on these analyses, as well as our historical experience and the facts and circumstances surrounding certain aged balances, we have established an allowance for doubtful trade accounts receivable. At September 30, 2004, approximately 99% of our net trade accounts receivable were less than 60 days past the scheduled invoice date. Our allowance for doubtful trade accounts receivable totaled $0.5 million. We consider this reserve adequate; however, there is no

F-19

assurance that actual amounts will not vary significantly from estimated amounts. The discovery of previously unknown facts or adverse developments affecting one of our counterparties or the industry as a whole could adversely impact our results of operations.

Note 4—Inventory and Linefill

Inventory primarily consists of crude oil and LPG in pipelines, storage tanks and rail cars that is valued at the lower of cost or market, with cost determined using an average cost method. Linefill and minimum working inventory requirements are recorded at historical cost and consist of crude oil and LPG used to pack a pipeline such that when an incremental barrel enters a pipeline it forces a barrel out at another location, as well as the minimum amount of crude oil necessary to operate our storage and terminalling facilities.

Linefill in third party assets is included in "Inventory" (a current asset) in determining the average cost of operating inventory and applying the lower of cost or market analysis. At the end of each period, we reclassify the linefill in third party assets not expected to be liquidated within the succeeding twelve months out of "Inventory," at average cost, and into "Inventory in Third Party Assets" (a long-term asset), which is reflected as a separate line item within other assets on the consolidated balance sheet.

At September 30, 2004 and December 31, 2003, inventory and linefill consisted of:

		September 30, 2004					December 31, 2003
		Barrels	Dollars		$/ barrel		Barrels	Dollars		$/ barrel
		(Barrels in thousands and dollars in millions)
Inventory⁽¹⁾
Crude oil		2,802	$	110.1	$	39.29	1,676	$	50.6	$	30.19
LPG		3,874		130.3		33.63	2,243		53.8		23.99
Other		—		1.9		N/A	—		1.6		N/A

	Inventory subtotal	6,676		242.3			3,919		106.0
Inventory in third-party assets
Crude oil		1,137		40.6		35.71	853		22.6		26.49
LPG		183		5.7		31.15	183		4.1		22.40

	Inventory in third-party assets subtotal	1,320		46.3			1,036		26.7
Linefill
Crude oil linefill		5,804		160.0		27.57	3,767		95.9		25.46

Total		13,800	$	448.6			8,722	$	228.6

⁽¹⁾: Value per barrel reflects the impact of inventory hedges on a portion of our volumes.

F-20

Note 5—Debt

Debt consists of the following:

		September 30, 2004		December 31, 2003
		(in millions)
Short-term debt:
Senior secured hedged inventory borrowing facility bearing interest at a rate of 2.6% and 1.9% at September 30, 2004 and December 31, 2003, respectively		$	59.5	$	100.5
Working capital borrowings, bearing interest at a rate of 2.8% and 4.0% at September 30, 2004 and December 31, 2003, respectively⁽¹⁾			60.0		25.3
Other			3.4		1.5

	Total short-term debt		122.9		127.3
Long-term debt:
Senior unsecured $425 million domestic revolving credit facility, bearing interest at 4.8% at September 30, 2004⁽¹⁾		$	18.6	$	—
Senior unsecured $30 million Canadian working capital revolving credit facility, bearing interest at a rate of 4.6% at September 30, 2004			11.4		—
Senior unsecured $170 million Canadian revolving credit facility, bearing interest at a rate of 2.8% and 2.2% at September 30, 2004 and December 31, 2003, respectively			10.0		70.0
4.75% senior notes due August 2009, net of unamortized discount of $0.8 million at September 30, 2004			174.2		—
7.75% senior notes due October 2012, net of unamortized discount of $0.3 million and $0.3 million at September 30, 2004 and December 31, 2003, respectively			199.7		199.7
5.63% senior notes due December 2013, net of unamortized discount of $0.6 million and $0.7 million at September 30, 2004 and December 31, 2003, respectively			249.4		249.3
5.88% senior notes due August 2016, net of unamortized discount of $1.1 million at September 30, 2004			173.9		—
Other			0.4		—

	Total long-term debt⁽¹⁾⁽²⁾		837.6		519.0

Total debt		$	960.5	$	646.3

⁽¹⁾: At September 30, 2004 and December 31, 2003, we have classified $60.0 million and $25.3 million, respectively, of borrowings under our senior unsecured $425 million domestic revolving credit facility as short-term. These borrowings are designated as working capital borrowings and primarily are for hedged LPG inventory and New York Mercantile Exchange margin deposits and must be repaid within one year.
⁽²⁾: At September 30, 2004, the aggregate fair value of our fixed rate senior notes was approximately $854.8 million.

During August 2004, we completed the sale of $175 million of 4.75% Senior Notes due 2009 and $175 million of 5.88% Senior Notes due 2016. The 4.75% notes were sold at 99.551% of face value and the 5.88% notes were sold at 99.345% of face value. The notes were co-issued by Plains All American

F-21

Pipeline, L.P. and a 100% owned consolidated finance subsidiary (neither of which have independent assets or operations). Interest payments are due on February 15 and August 15 of each year. The notes are fully and unconditionally guaranteed, jointly and severally, by all of our existing 100% owned subsidiaries, except for subsidiaries which are minor. We used the proceeds to repay amounts outstanding under our credit facilities, including the remaining balance under the $200 million, 364-day facility described above, and for general partnership purposes. In connection with this repayment, we terminated the facility. The repayment and termination of this facility resulted in a non-cash charge of approximately $0.7 million associated with the write-off of unamortized debt issue costs. Subsequent to the notes offering, we also terminated our $125 million, 364-day facility which was scheduled to expire in November 2004.

In the third quarter of 2004, we increased our secured hedged inventory facility from $200 million to $300 million, with the ability to further increase the facility in the future by an incremental $200 million. This facility is an uncommitted working capital facility, which is used to finance the purchase of hedged crude oil inventory for storage when market conditions warrant. Borrowings under the hedged inventory facility are secured by the inventory purchased under the facility and the associated accounts receivable, and are repaid with the proceeds from the sale of such inventory. This facility expires in November 2004, and we expect to extend the maturity to November 2005 before expiration.

F-22

Note 6—Earnings Per Common Unit

The following sets forth the computation of basic and diluted earnings per common unit:

		Nine months ended September 30,
		2004			2003
		(in thousands, except per unit data)
Net income		$	105,287		$	59,620
Less:
	Incentive distribution right		(5,601	)		(3,540	)

	Subtotal		99,686			56,080
	General partner 2% ownership		(1,994	)		(1,122	)

Numerator:
Numerator for basic earnings per limited partner unit—
	Net income available for limited partners		97,692			54,958
Effect of dilutive securities:
	Increase in incentive distribution right-contingent equity issuance		—			(46	)

Numerator for diluted earnings per limited partner unit		$	97,692		$	54,912

Denominator:
	Denominator for basic earnings per limited partner unit—weighted average number of limited partner units		61,929			51,735

Effect of dilutive securities:
	Contingent equity issuance		—			672

Denominator for diluted earnings per limited partner unit			61,929			52,407

Basic net income per limited partner unit		$	1.58		$	1.06

Diluted net income per limited partner unit		$	1.58		$	1.05

In March 2004, the Emerging Issues Task Force issued Issue No. 03-06 ("EITF 03-06"), "Participating Securities and the Two-Class Method under FASB Statement No. 128." EITF 03-06 addresses a number of questions regarding the computation of earnings per share by companies that have issued securities other than common stock that contractually entitle the holder to participate in dividends and earnings of the company when, and if, it declares dividends on its common stock. The issue also provides further guidance in applying the two-class method of calculating earnings per share, clarifying what constitutes a participating security and how to apply the two-class method of computing earnings per share once it is determined that a security is participating, including how to allocate undistributed earnings to such a security. EITF 03-06 was effective for fiscal periods beginning after March 31, 2004. The adoption of EITF 03-06 did not result in a change in the Partnership's earnings per limited partner unit for any of the periods presented.

F-23

Note 7—Partners' Capital and Distributions

Subordinated Unit Conversion

In November 2003, pursuant to the terms of our Partnership Agreement, 25% of our subordinated units converted to common units on a one-for-one basis. In February 2004, all of the remaining subordinated units converted to common units on a one-for-one basis.

Issuance of Common Units

Long-Term Incentive Plan. We issued approximately 315,500 common units during the first half of 2004 and approximately 47,500 common units during the third quarter of 2004 in conjunction with the vesting of awards under our Long-Term Incentive Plan ("LTIP"). In connection with such issuances, the General Partner made a proportionate two percent contribution. See Note 8 for additional discussion.

Payment of Deferred Acquisition Price. On April 30, 2004, we issued approximately 385,000 common units and paid approximately $6.5 million in cash to satisfy the contingent consideration related to the July 2001 CANPET acquisition. In accordance with the provisions of the purchase and sale agreement, the number of common units issued in satisfaction of the deferred payment was based upon $34.02 per share, the average trading price of our common units for the ten-day trading period prior to the payment date, and a Canadian dollar to U.S. dollar exchange rate of 1.35 to 1, the average noon-day exchange rate for the ten-day trading period prior to the payment date. In addition, an incremental $3.7 million in cash was paid for the distributions that would have been paid on the common units had they been outstanding since the effective date of the acquisition.

Private Placement of Class C Common Units. In connection with the Link acquisition, on April 15, 2004 we issued 3,245,700 Class C common units for $30.81 per unit in a private placement to a group of institutional investors consisting of affiliates of Kayne Anderson Capital Advisors, Vulcan Capital and Tortoise Capital Advisors. Affiliates of both Kayne Anderson Capital Advisors and Vulcan Capital own interests in our general partner. Total proceeds from the transaction, after deducting transaction costs and including the general partner's proportionate contribution, were approximately $101 million, and were used to reduce the balance outstanding under our revolving credit facilities. The Class C common units are unlisted securities that are pari passu in voting and distribution rights with the Partnership's publicly traded common units. The Class C common units are similar in most respects to the Partnership's Class B common units. Both classes become convertible into common units upon approval by the holders of a majority of the common units. See "—Class B and Class C Common; Unitholder Meeting."

Class B and Class C Common; Unitholder Meeting. Each of the Class B common unitholders and Class C common unitholders may request that the Partnership call a meeting of its common unitholders to consider approval of a change in the terms of the Class B units or Class C units, as applicable, to provide that those units may be converted at the option of the holder into common units. The holders of both the Class B common units and the Class C common units made such a request on October 18, 2004. If the approval of the common unitholders is not obtained within 120 days of the request, the holders of the Class B and Class C units (unless and until converted into common units) will be entitled to receive distributions, on a per unit basis, equal to 110% of the amount of distributions paid on a common unit. If the approval of the common unitholders is not secured within 90 days after the

F-24

end of the 120-day period, the distribution right increases to 115%. The Partnership is in the process of preparing for a meeting of unitholders.

Equity Offering. In the third quarter of 2004, we completed a public offering of 4,968,000 common units for $33.25 per unit. The offering resulted in gross proceeds of approximately $165.2 million from the sale of units and approximately $3.4 million from our general partner's proportionate capital contribution. Total costs associated with the offering, including underwriter fees and other expenses, were approximately $7.7 million. Net proceeds of $160.9 million were used to permanently reduce outstanding borrowings under the $200 million, 364-day credit facility (see Note 5).

Distributions

On October 22, 2004, we declared a cash distribution of $0.60 per unit on our outstanding common units, Class B common units and Class C common units. The distribution is payable on November 12, 2004, to unitholders of record on November 2, 2004, for the period July 1, 2004, through September 30, 2004. The total distribution to be paid is approximately $43.9 million, with approximately $40.4 million to be paid to our common unitholders and $0.8 million and $2.7 million to be paid to our general partner for its general partner and incentive distribution interests, respectively.

On August 13, 2004, we paid a cash distribution of $0.5775 per unit on our outstanding common units, Class B common units and Class C common units, for the period April 1, 2004, through June 30, 2004. The total distribution paid was approximately $41.8 million, with approximately $38.8 million paid to our common unitholders and $0.8 million and $2.2 million paid to our general partner for its general partner and incentive distribution interests, respectively.

On May 14, 2004, we paid a cash distribution of $0.5625 per unit on our outstanding common units, Class B common units and Class C common units, for the period January 1, 2004, through March 31, 2004. The total distribution paid was approximately $37.5 million, with approximately $35.0 million paid to our common unitholders and $0.7 million and $1.8 million paid to our general partner for its general partner and incentive distribution interests, respectively.

On February 13, 2004, we paid a cash distribution of $0.5625 per unit on our outstanding common units, Class B common units and subordinated units, for the period October 1, 2003, through December 31, 2003. The total distribution paid was approximately $35.2 million, with approximately $28.7 million paid to our common unitholders, $4.2 million paid to our subordinated unitholders and $0.7 million and $1.6 million paid to our general partner for its general partner and incentive distribution interests, respectively.

Note 8—Vesting of Unit Grants Under Long-Term Incentive Plan

During the first nine months of 2004, approximately 895,000 phantom units vested. We paid cash in lieu of delivery of common units for approximately 328,000 of the phantom units and issued approximately 362,000 new common units (after netting for taxes) in connection with the remainder of the vesting.

Under generally accepted accounting principles, we are required to recognize an expense when it is considered probable that phantom unit grants under our LTIP will vest. During the first nine months of

F-25

2004, we recognized $4.2 million of compensation expense related to the vesting of phantom units under the LTIP. We will recognize additional expense when it is considered probable that additional vestings will occur. Generally, future vestings will occur when the annualized distribution rate reaches $2.50 and again at $2.70. After giving effect to the third quarter 2004 vesting and related tax withholding and cash settlement, approximately 874,000 phantom units are available under the plan for future grant and approximately 134,000 phantom units remain outstanding. In accordance with the provisions of the LTIP and applicable NYSE standards, no more than approximately 460,000 of such phantom unit grants (outstanding or future) could be satisfied by delivery of common units.

Note 9—Derivative Instruments and Hedging Activities

We utilize various derivative instruments to (i) manage our exposure to commodity price risk, (ii) engage in a controlled trading program, (iii) manage our exposure to interest rate risk and (iv) manage our exposure to currency exchange rate risk. Our risk management policies and procedures are designed to monitor interest rates, currency exchange rates, NYMEX and over-the-counter positions, and physical volumes, grades, locations and delivery schedules to ensure that our hedging activities address our market risks. We formally document all relationships between hedging instruments and hedged items, as well as our risk management objectives and strategy for undertaking the hedge. We calculate hedge effectiveness on a quarterly basis. This process includes specific identification of the hedging instrument and the hedged transaction, the nature of the risk being hedged and how the hedging instrument's effectiveness will be assessed. Both at the inception of the hedge and on an ongoing basis, we assess whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in cash flows of hedged items.

Summary of Financial Impact

The following is a summary of the financial impact of the derivative instruments and hedging activities discussed below. The September 30, 2004, balance sheet includes assets of $53.6 million ($39.5 million current), liabilities of $43.9 million ($32.8 million current) and unrealized net gains deferred to Other Comprehensive Income ("OCI") of $0.4 million. Total derivative activities for the nine months ended September 30, 2004, generated a gain of $66.3 million. Total derivative activities include the mark-to-market of open positions that do not meet hedge accounting requirements and gains and losses recognized in earnings for all hedges settled during the period. The majority of these gains are related to our commodity price risk hedges that are offset by physical transactions, as discussed below.

As of September 30, 2004, the total amount of deferred net gains recorded in OCI are expected to be reclassified to future earnings, contemporaneously with the related physical purchase or delivery of the underlying commodity or payments of interest. During the nine months ended September 30, 2004, no amounts were reclassified to earnings from OCI in connection with forecasted transactions that were no longer considered probable of occurring. Of the $0.4 million net gain deferred in OCI at September 30, 2004, a net gain of $7.3 million will be reclassified into earnings in the next twelve months and the remaining net loss at various intervals ending in 2016. Since a portion of these amounts is based on market prices at the current period end, actual amounts to be reclassified will differ and could vary materially as a result of changes in market conditions.

F-26

The following sections discuss our risk management activities in the indicated categories.

Commodity Price Risk Hedging

We hedge our exposure to price fluctuations with respect to crude oil and LPG in storage, and expected purchases, sales and transportation of these commodities. The derivative instruments we use consist primarily of futures and option contracts traded on the NYMEX and over-the-counter transactions, including crude oil swap and option contracts entered into with financial institutions and other energy companies. In accordance with SFAS No. 133 "Accounting for Derivative Instruments and Hedging Activities," these derivative instruments are recognized in the balance sheet or earnings at their fair values. The majority of the instruments that qualify for hedge accounting are cash flow hedges. Therefore, the corresponding changes in fair value for the effective portion of the hedges are deferred into OCI and recognized in revenues or crude oil and LPG purchases and related costs in the periods during which the underlying physical transactions occur. We have determined that substantially all of our physical purchase and sale agreements qualify for the normal purchase and sale exclusion and thus are not subject to SFAS 133. Physical transactions that are derivatives and are ineligible, or become ineligible, for the normal purchase and sale treatment (e.g. due to changes in settlement provisions) are recorded in the balance sheet as assets or liabilities at their fair value, with the changes in fair value recorded net in revenues.

Controlled Trading Program

Although we seek to maintain a position that is substantially balanced within our crude oil lease purchase activities, we may experience net unbalanced positions for short periods of time as a result of production, transportation and delivery variances as well as logistical issues associated with inclement weather conditions. In connection with managing these positions and maintaining a constant presence in the marketplace, both necessary for our core business, we engage in a controlled trading program for up to an aggregate of 500,000 barrels of crude oil. These activities are monitored independently by our risk management function and must take place within predefined limits and authorizations. In accordance with SFAS 133, these derivative instruments are recorded in the balance sheet as assets or liabilities at their fair value, with the changes in fair value recorded net in revenues.

Interest Rate Risk Hedging

At September 30, 2004, we have no open interest rate hedging instruments. However, there are approximately $6.5 million deferred in OCI that relates to instruments that were terminated and cash settled ($1.4 million related to an instrument settled in 2004 and $5.1 million related to instruments settled in 2003). The net deferred loss related to these instruments is being amortized into interest expense over the original terms of the terminated instruments (approximately forty percent over the next two years and the remaining sixty percent over approximately ten years). Approximately $1.1 million related to the terminated instruments has been reclassified into interest expense during the first nine months of 2004, and approximately $1.5 million will be reclassified for the entire year of 2004. In addition, earnings for the first nine months of 2004 include a loss of approximately $0.7 million that was reclassified out of OCI related to an instrument that matured in March 2004.

F-27

Currency Exchange Rate Risk Hedging

Because a significant portion of our Canadian business is conducted in Canadian dollars and, at times, a portion of our debt is denominated in Canadian dollars, we use certain financial instruments to minimize the risks of unfavorable changes in exchange rates. These instruments include forward exchange contracts and cross currency swaps. The forward exchange contracts qualify for hedge accounting as cash flow hedges and the cross currency swaps qualify for hedge accounting as fair value hedges, both in accordance with SFAS 133.

At September 30, 2004, we had forward exchange contracts that allow us to exchange Canadian dollars for U.S. dollars, quarterly, at set exchange rates as detailed below:

	Canadian Dollars		US Dollars		Rate
	($ in millions)
2004	$	5.0	$	3.8	1.32 to 1
2005	$	3.0	$	2.3	1.33 to 1
2006	$	2.0	$	1.5	1.32 to 1

In addition, at September 30, 2004, we also had cross currency swap contracts for an aggregate notional principal amount of $21.0 million, effectively converting this amount of our U.S. dollar denominated debt to $32.5 million of Canadian dollar debt (based on a Canadian dollar to U.S. dollar exchange rate of 1.55 to 1). The notional principal amount will reduce by $2.0 million U.S. in May 2005 and has a final maturity in May 2006 of $19.0 million U.S. At September 30, 2004, $6.2 million of our long-term debt was denominated in Canadian dollars ($7.8 million Canadian based on a Canadian dollar to U.S. dollar exchange rate of 1.26 to 1). All of these financial instruments are placed with what we believe to be large, creditworthy financial institutions.

Note 10—Commitments and Contingencies

Litigation

Export License Matter. In our gathering and marketing activities, we import and export crude oil from and to Canada. Exports of crude oil are subject to the short supply controls of the Export Administration Regulations ("EAR") and must be licensed by the Bureau of Industry and Security (the "BIS") of the U.S. Department of Commerce. In 2002, we determined that we may have exceeded the quantity of crude oil exports authorized by previous licenses. Export of crude oil in excess of the authorized amounts is a violation of the EAR. On October 18, 2002, we submitted to the BIS an initial notification of voluntary disclosure. The BIS subsequently informed us that we could continue to export while previous exports were under review. We applied for and have received a new license allowing for exports of volumes more than adequately reflecting our anticipated needs. We also conducted reviews of new and existing contracts and implemented new procedures and practices in order to monitor compliance with applicable laws regarding the export of crude oil to Canada. As a result, we subsequently submitted additional information to the BIS in October 2003 and May 2004. We have received a request from the BIS for additional information, which we are in the process of providing. At this time, we have received no indication whether the BIS intends to charge us with a violation of

F-28

the EAR or, if so, what penalties would be assessed. As a result, we cannot estimate the ultimate impact of this matter.

Environmental

Other

The occurrence of a significant event not fully insured, indemnified or reserved against, or the failure of a party to meet its indemnification obligations, could materially and adversely affect our operations and financial condition. We believe we are adequately insured for public liability and property damage to others with respect to our operations. We believe that our levels of coverage and retention are generally consistent with those of similarly situated companies in our industry. With respect to all of our coverage, no assurance can be given that we will be able to maintain adequate insurance in the future at rates we consider reasonable, or that we have established adequate reserves to the extent that such risks are not insured.

Note 11—Operating Segments

Our operations consist of two operating segments: (1) Pipeline Operations, which engage in interstate and intrastate crude oil pipeline transportation and certain related margin activities; and (2) Gathering, Marketing, Terminalling and Storage Operations, which engage in purchases and resales of crude oil and LPG at various points along the distribution chain and the operation of certain terminalling and storage assets. We believe that the combination of our terminalling and storage activities and gathering and marketing activities provides a counter-cyclical balance that has a stabilizing effect on our results of operations and cash flow. In a contango market (oil prices for future deliveries are higher than for current deliveries), we use our tankage to improve our gathering margins by storing crude oil we have purchased at lower prices in the current month for delivery at higher prices in future months. In a backwardated market (oil prices for future deliveries are lower than for current deliveries), we use and lease less storage capacity, but increased marketing margins (premiums for prompt delivery) provide an offset to this reduced cash flow.

F-29

We evaluate segment performance based on segment profit and maintenance capital. We define segment profit as revenues less (i) purchases, (ii) field operating costs, and (iii) segment general and administrative expenses. Maintenance capital consists of capital expenditures required either to maintain the existing operating capacity of partially or fully depreciated assets or to extend their useful lives. Capital expenditures made to expand our existing capacity, whether through construction or acquisition, are not considered maintenance capital expenditures. Repair and maintenance expenditures associated with existing assets that do not extend the useful life or expand the operating capacity are charged to expense as incurred. The following table reflects our results of operations for each segment for the periods indicated (note that each of the items in the following table excludes depreciation and amortization):

			Pipeline		GMT&S			Total
			(in millions)
Nine Months Ended September 30, 2004
Revenues:
	External Customers		$	556.5	$	14,246.9		$	14,803.4
	Intersegment⁽¹⁾			83.0		0.7			83.7

		Total revenues of reportable segments	$	639.5	$	14,247.6		$	14,887.1

Segment profit			$	117.2	$	68.9		$	186.1

		Total assets	$	1,100.5	$	2,005.5		$	3,106.0

Non-cash SFAS 133 impact⁽²⁾			$	—	$	1.4		$	1.4

Maintenance capital			$	4.1	$	2.0		$	6.1

Nine Months Ended September 30, 2003
Revenues:
	External Customers		$	450.6	$	8,594.1		$	9,044.7
	Intersegment⁽¹⁾			38.5		0.7			39.2

		Total revenues of reportable segments	$	489.1	$	8,594.8		$	9,083.9

Segment profit			$	67.2	$	52.9		$	120.1

Non-cash SFAS 133 impact⁽²⁾			$	—	$	(1.7	)	$	(1.7	)

Maintenance capital			$	4.8	$	0.7		$	5.5

⁽¹⁾: Intersegment sales are conducted at arms length.
⁽²⁾: Amounts related to SFAS 133 are included in revenues and impact segment profit.

F-30

The following table reconciles segment profit to consolidated income before cumulative effect of change in accounting principle:

	For the nine months ended September 30,
	2004			2003
	(in millions)
Segment profit	$	186.1		$	120.1
Depreciation and amortization		(45.9	)		(34.2	)
Interest expense		(32.2	)		(26.5	)
Interest income and other, net		0.4			0.2

Income before cumulative effect of change in accounting principle	$	108.4		$	59.6

F-31

Report of Independent Registered Public Accounting Firm

To the Board of Directors of the General Partner and Unitholders of
Plains All American Pipeline, L.P.:

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, of cash flows, of changes in partners' capital, of comprehensive income and of changes in accumulated other comprehensive income (loss) present fairly, in all material respects, the financial position of Plains All American Pipeline, L.P. and its subsidiaries (the "Partnership") at December 31, 2003 and 2002, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2003 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note 2 to the consolidated financial statements, the Partnership changed its method of accounting for derivative instruments and hedging activities effective January 1, 2001.

PricewaterhouseCoopers LLP

Houston, Texas
February 26, 2004, except as to Note 1
which is as of July 21, 2004

F-32

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands, except unit data)

		December 31, 2003			December 31, 2002
ASSETS
CURRENT ASSETS
Cash and cash equivalents		$	4,137		$	3,501
Accounts receivable, net			590,645			499,909
Inventory			105,967			81,849
Other current assets			32,225			17,676

	Total current assets		732,974			602,935

PROPERTY AND EQUIPMENT			1,272,634			1,030,303
Accumulated depreciation			(121,595	)		(77,550	)

			1,151,039			952,753

OTHER ASSETS
Pipeline linefill			122,653			62,558
Other, net			88,965			48,329

	Total assets	$	2,095,631		$	1,666,575

LIABILITIES AND PARTNERS' CAPITAL
CURRENT LIABILITIES
Accounts payable		$	603,460		$	488,922
Due to related parties			26,981			23,301
Short-term debt (see Note 6)			127,259			99,249
Other current liabilities			44,219			25,777

	Total current liabilities		801,919			637,249

LONG-TERM LIABILITIES
Long-term debt under credit facilities, including current maturities of $9,000 for the 2002 period			70,000			310,126
Senior notes, net of unamortized discount of $1,009 and $390, respectively			448,991			199,610
Other long-term liabilities and deferred credits			27,994			7,980

	Total liabilities		1,348,904			1,154,965

COMMITMENTS AND CONTINGENCIES (NOTE 12)
PARTNERS' CAPITAL
Common unitholders (49,502,556 and 38,240,939 units outstanding at December 31, 2003, and December 31, 2002, respectively)			744,073			524,428
Class B common unitholder (1,307,190 units outstanding at each date)			18,046			18,463
Subordinated unitholders (7,522,214 and 10,029,619 units outstanding at December 31, 2003, and December 31, 2002, respectively)			(39,913	)		(47,103	)
General partner			24,521			15,822

	Total partners' capital		746,727			511,610

		$	2,095,631		$	1,666,575

The accompanying notes are an integral part of these consolidated financial statements.

F-33

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per unit data)

		Year Ended December 31,
		2003			2002			2001
REVENUES
Crude oil and LPG sales		$	11,952,623		$	7,892,162		$	6,481,305
Pipeline margin activities			505,287			382,513			285,618
Pipeline tariffs and fees			99,887			79,939			54,234
Other			32,052			29,609			47,058

	Total revenues		12,589,849			8,384,223			6,868,215
COSTS AND EXPENSES
Crude oil and LPG purchases and related costs			11,727,355			7,726,323			6,338,365
Pipeline margin activities purchases			486,154			362,311			270,786
Other purchases			19,027			14,862			4,965
Field operating costs (excluding LTIP charge)			134,177			106,436			106,854
LTIP charge—operations			5,727			—			—
Inventory valuation adjustment			—			—			4,984
General and administrative (excluding LTIP charge)			49,969			45,663			46,586
LTIP charge—general and administrative			23,063			—			—
Depreciation and amortization			46,821			34,068			24,307

	Total costs and expenses		12,492,293			8,289,663			6,796,847

Gains on sales of assets			648			—			984

OPERATING INCOME			98,204			94,560			72,352
OTHER INCOME/(EXPENSE)
Interest expense (net of capitalized interest of $524, $773 and $153)			(35,226	)		(29,057	)		(29,082	)
Interest income and other, net (Note 2)			(3,530	)		(211	)		401

Income before cumulative effect of accounting change			59,448			65,292			43,671
Cumulative effect of accounting change			—			—			508

NET INCOME		$	59,448		$	65,292		$	44,179

NET INCOME-LIMITED PARTNERS		$	53,473		$	60,912		$	42,239

NET INCOME-GENERAL PARTNER		$	5,975		$	4,380		$	1,940

BASIC NET INCOME PER LIMITED PARTNER UNIT
Income before cumulative effect of accounting change		$	1.01		$	1.34		$	1.12
Cumulative effect of accounting change			—			—			0.01

Net income		$	1.01		$	1.34		$	1.13

DILUTED NET INCOME PER LIMITED PARTNER UNIT
Income before cumulative effect of accounting change		$	1.00		$	1.34		$	1.12
Cumulative effect of accounting change			—			—			0.01

Net Income		$	1.00		$	1.34		$	1.13

BASIC WEIGHTED AVERAGE UNITS OUTSTANDING			52,743			45,546			37,528

DILUTED WEIGHTED AVERAGE UNITS OUTSTANDING			53,400			45,546			37,528

The accompanying notes are an integral part of these consolidated financial statements.

F-34

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

			Year Ended December 31,
			2003			2002			2001
CASH FLOWS FROM OPERATING ACTIVITIES
Net income			$	59,448		$	65,292		$	44,179
Adjustments to reconcile to cash flows from operating activities:
	Depreciation and amortization			46,821			34,068			24,307
	Gains on sales of assets			(648	)		—			(984	)
	Cumulative effect of accounting change			—			—			(508	)
	Noncash compensation expense			—			—			5,741
	Allowance for doubtful accounts			360			146			3,000
	Inventory valuation adjustment			—			—			4,984
	Change in derivative fair value			(363	)		(243	)		(207	)
	Net cash paid for termination of interest rate hedging instruments			(6,152	)		—			—
	Write-off of unamortized debt issue costs			3,272			—			—
	Noncash portion of LTIP charge (Note 11)			28,052			—			—
Changes in assets and liabilities, net of acquisitions:
	Accounts receivable and other			(102,005	)		(136,480	)		(18,856	)
	Inventory			(38,941	)		105,944			(117,878	)
	Accounts payable and other current liabilities			117,412			106,065			46,671
	Other long-term liabilities and deferred credits			4,600			1,200			600
	Due to related parties			3,452			8,962			(7,266	)

		Net cash provided by (used in) operating activities		115,308			184,954			(16,217	)

CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid in connection with acquisitions (Note 3)				(168,359	)		(324,628	)		(229,162	)
Additions to property and equipment				(65,416	)		(40,590	)		(21,069	)
Cash paid for linefill on assets owned				(46,790	)		(11,060	)		(13,736	)
Proceeds from sales of assets				8,450			1,437			740

		Net cash used in investing activities		(272,115	)		(374,841	)		(263,227	)

CASH FLOWS FROM FINANCING ACTIVITIES
Net borrowings/(repayments) on short-term letter of credit and hedged inventory facilities				(6,197	)		(4,770	)		99,583
Net borrowings/(repayments) on long-term revolving credit facilities				87,773			(42,144	)		34,677
Principal payments on senior secured term loans (Note 6)				(297,000	)		(3,000	)		—
Cash paid in connection with financing arrangements				(5,191	)		(5,435	)		(6,351	)
Net proceeds from the issuance of common units (Note 7)				250,341			145,046			227,549
Proceeds from the issuance of senior unsecured notes (Note 6)				249,340			199,600			—
Distributions paid to unitholders and general partner (Note 7)				(121,822	)		(99,841	)		(75,929	)

		Net cash provided by financing activities		157,244			189,456			279,529

Effect of translation adjustment on cash				199			421			—
Net increase (decrease) in cash and cash equivalents				636			(10	)		85
Cash and cash equivalents, beginning of period				3,501			3,511			3,426

Cash and cash equivalents, end of period			$	4,137		$	3,501		$	3,511

Cash paid for interest, net of amounts capitalized			$	36,382		$	28,550		$	33,341

The accompanying notes are an integral part of these consolidated financial statements.

F-35

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS' CAPITAL

(in thousands)

	Common Unitholders				Class B Common Unitholders				Subordinated Unitholders					General Partner			Total Partners' Capital
	Units	Amount			Units	Amount			Units		Amount			Amount			Amount
Balance at December 31, 2000	23,049	$	217,073		1,307	$	21,042		10,030		$	(27,316	)	$	3,200		$	213,999
Issuance of units	8,867		222,032		—		—		—			—			5,517			227,549
Noncash compensation expense	—		—		—		—		—			—			5,741			5,741
Net income	—		29,436		—		1,476		—			11,327			1,940			44,179
Distributions	—		(51,271	)	—		(2,549	)	—			(19,558	)		(2,551	)		(75,929	)
Other comprehensive loss	—		(8,708	)	—		(435	)	—			(3,344	)		(255	)		(12,742	)

Balance at December 31, 2001	31,916		408,562		1,307		19,534		10,030			(38,891	)		13,592			402,797
Issuance of units	6,325		142,013		—		—		—			—			3,033			145,046
Net income	—		45,857		—		1,736		—			13,319			4,380			65,292
Distributions	—		(70,821	)	—		(2,762	)	—			(21,188	)		(5,070	)		(99,841	)
Other comprehensive loss	—		(1,183	)	—		(45	)	—			(343	)		(113	)		(1,684	)

Balance at December 31, 2002	38,241		524,428		1,307		18,463		10,030			(47,103	)		15,822			511,610
Issuance of units	8,736		245,093		—		—		—			—			5,237			250,330
Issuance of units under LTIP	18		555		—		—		—			—			11			566
Net income	—		41,278		—		1,370		—			10,825			5,975			59,448
Conversion of 25% of subordinated units	2,507		(9,823	)	—		—		(2,507	)		9,823			—			—
Distributions	—		(89,801	)	—		(2,860	)	—			(21,939	)		(7,222	)		(121,822	)
Other comprehensive income	—		32,343		—		1,073		—			8,481			4,698			46,595

Balance at December 31, 2003	49,502	$	744,073		1,307	$	18,046		7,523		$	(39,913	)	$	24,521		$	746,727

The accompanying notes are an integral part of these consolidated financial statements.

F-36

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

	Year Ended December 31,
	2003		2002			2001
	(in thousands)
Net income	$	59,448	$	65,292		$	44,179
Other comprehensive income (loss)		46,595		(1,684	)		(12,742	)

Comprehensive income	$	106,043	$	63,608		$	31,437

CONSOLIDATED STATEMENT OF CHANGES IN ACCUMULATED
OTHER COMPREHENSIVE INCOME (LOSS)

		Net Deferred Loss on Derivative Instruments			Currency Translation Adjustments			Total
		(in thousands)
Balance at December 31, 2000		$	—		$	—		$	—
Cumulative effect of accounting change			(8,337	)		—			(8,337	)
Reclassification adjustments for settled contracts			(2,526	)		—			(2,526	)
Changes in fair value of outstanding hedge positions			6,123			—			6,123
Currency translation adjustment			—			(8,002	)		(8,002	)

Balance at December 31, 2001			(4,740	)		(8,002	)		(12,742	)
Reclassification adjustments for settled contracts			797			—			797
Changes in fair value of outstanding hedge positions			(4,264	)		—			(4,264	)
Currency translation adjustment			—			1,783			1,783

	2002 Activity		(3,467	)		1,783			(1,684	)

Balance at December 31, 2002			(8,207	)		(6,219	)		(14,426	)
Reclassification adjustments for settled contracts			(28,151	)		—			(28,151	)
Changes in fair value of outstanding hedge positions			28,666			—			28,666
Currency translation adjustment			—			46,080			46,080

	2003 Activity		515			46,080			46,595

Balance at December 31, 2003		$	(7,692	)	$	39,861		$	32,169

The accompanying notes are an integral part of these consolidated financial statements.

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Note 1—Organization and Basis of Presentation

Organization

Plains All American Pipeline, L.P. is a publicly traded Delaware limited partnership (the "Partnership") 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. We refer to liquified petroleum gas and other petroleum products collectively as "LPG". We were formed in September 1998 to acquire and operate the midstream crude oil business and assets of Plains Resources Inc. and its wholly-owned subsidiaries ("Plains Resources") as a separate, publicly traded master limited partnership. We completed our initial public offering in November 1998. As a result of subsequent equity offerings and the purchase in 2001 by senior management and a group of financial investors of majority control of our general partner and a portion of Plains Resources' limited partner units (the "General Partner Transition"), Plains Resources' overall effective ownership in us was reduced to approximately 22%.

As a result of the 2001 transaction, our 2% general partner interest is held by Plains AAP, L.P., a Delaware limited partnership. Plains All American GP LLC, a Delaware limited liability company, is Plains AAP, L.P.'s general partner. Plains All American GP LLC manages our operations and activities and employs our officers and personnel, who devote 100% of their efforts to the management of the Partnership. Unless the context otherwise requires, we use the term "general partner" to refer to both Plains AAP, L.P. and Plains All American GP LLC. Plains AAP, L.P. and Plains All American GP LLC are essentially held by 7 owners with the largest interest, 44%, held by Plains Resources. We use the phrase "former general partner" to refer to the subsidiary of Plains Resources that formerly held the general partner interest.

Our operations are conducted directly and indirectly through our operating subsidiaries, Plains Marketing, L.P., Plains Pipeline, L.P. and Plains Marketing Canada, L.P., and are concentrated in Texas, Oklahoma, California, Louisiana and the Canadian provinces of Alberta and Saskatchewan.

Change in Accounting Principle

During the second quarter of 2004, we changed our method of accounting for pipeline linefill in third party assets. Historically, we have viewed pipeline linefill, whether in our assets or third party assets, as having long-term characteristics rather than characteristics typically associated with the short-term classification of operating inventory. Therefore, previously we have not included linefill barrels in the same average costing calculation as our operating inventory, but instead have carried linefill at historical cost. Following this change in accounting principle, the linefill in third party assets that we have historically classified as a portion of "Pipeline Linefill" on the face of the balance sheet (a long-term asset) and carried at historical cost, will be included in "Inventory" (a current asset) in determining the average cost of operating inventory and applying the lower of cost or market analysis. At the end of each period, we will reclassify the linefill in third party assets not expected to be liquidated within the succeeding twelve months out of "Inventory" (a current asset), at average cost, and into "Inventory in Third Party Assets" (a long-term asset), which is now reflected as a separate line item within other assets on the consolidated balance sheet.

This change in accounting principle is effective January 1, 2004. The cumulative effect of this change in accounting principle as of January 1, 2004, is a charge of approximately $3.1 million, representing a reduction in Inventory of approximately $1.7 million, a reduction in Pipeline Linefill of approximately $30.3 million and an increase in Inventory in Third Party Assets of $28.9 million. The pro forma impact on net income and net income per limited partner unit (basic and diluted) presented

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below gives effect to the retroactive application of the change in accounting for pipeline linefill in third party assets had the new method been in effect in the years presented.

		2003		2002		2001
		(in millions, except per unit data)
Income before cumulative effect of accounting change		$	59.4	$	65.3	$	43.7
Income before cumulative effect of accounting change per limited partner unit:
	Basic	$	1.01	$	1.34	$	1.12
	Diluted	$	1.00	$	1.34	$	1.12
Net Income		$	59.4	$	65.3	$	44.2
Net Income per limited partner unit:
	Basic	$	1.01	$	1.34	$	1.13
	Diluted	$	1.00	$	1.34	$	1.13
Pro Forma Income before cumulative effect of accounting change		$	61.4	$	64.8	$	38.4
Pro Forma Income before cumulative effect of accounting change per limited partner unit:
	Basic	$	1.05	$	1.33	$	0.97
	Diluted	$	1.04	$	1.33	$	0.97
Pro Forma Net Income		$	61.4	$	64.8	$	38.9
Pro Forma Net Income per limited partner unit:
	Basic	$	1.05	$	1.33	$	0.99
	Diluted	$	1.04	$	1.33	$	0.99

In conjunction with this change in accounting principle, we have classified the cash flows associated with purchases and sales of linefill on assets that we own as cash flows from investing activities instead of the historical classification as cash flows from operating activities. Accordingly, the accompanying statement of cash flows for the year ended December 31, 2003, 2002 and 2001 has been revised to reclassify the cash paid for linefill in assets owned from operating activities to investing activities. As a result of this change in classification, net cash provided by operating activities for the years ended December 31, 2003 and 2002 increased to $115.3 million from $68.5 million and to $185.0 million from $173.9 million, respectively. Net cash used in investing activities for the years ended December 31, 2003 and 2002 increased to $272.1 million from $225.3 million and $374.8 million from $363.8 million, respectively. In addition, net cash used in operating activities for the year ended December 31, 2001 decreased from $30 million to $16.2 million and net cash used in investing activities increased to $263.2 million from $249.5 million.

Basis of Consolidation and Presentation

The accompanying financial statements and related notes present our consolidated financial position as of December 31, 2003 and 2002, and the consolidated results of our operations, cash flows, changes in partners' capital and comprehensive income (loss) for the years ended December 31, 2003, 2002 and 2001, and changes in accumulated other comprehensive income for the years ended December 31, 2003 and 2002. All significant intercompany transactions have been eliminated. Certain reclassifications were made to prior periods to conform with the current period presentation.

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Note 2—Summary of Significant Accounting Policies

Use of Estimates

The preparation of financial statements in conformity with generally accepted accounting principles requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Significant estimates we make include: (i) accruals related to purchases and sales, (ii) mark-to-market estimates pursuant to Statement of Financial Accounting Standards ("SFAS") No. 133 "Accounting For Derivative Instruments and Hedging Activities", as amended, (iii) contingent liability accruals, (iv) accruals related to our Long-Term Incentive Plan (the "LTIP") and (v) estimated fair value of assets and liabilities acquired and identification of associated goodwill and intangible assets. Although we believe these estimates are reasonable, actual results could differ from these estimates.

Revenue Recognition

Gathering, Marketing, Terminalling and Storage Segment Revenues. Revenues from crude oil and LPG sales are recognized at the time title to the product sold transfers to the purchaser, which occurs upon receipt of the product by the purchaser. All sales of crude oil and LPG are booked gross except in the case of barrel exchanges that are net settled. Terminalling and storage revenues, which are classified as other revenues on the income statement, consist of (i) storage fees from actual storage used on a month-to-month basis; (ii) storage fees resulting from short-term and long-term contracts for committed space that may or may not be utilized by the customer on a given month; and (iii) terminal throughput charges to pump crude oil to connecting carriers. Revenues on storage are recognized ratably over the term of the contract. Terminal throughput charges are recognized as the crude oil exits the terminal and is delivered to the connecting crude oil carrier. Any throughput volumes in transit at the end of a given month are treated as third party inventory and do not incur storage fees. All terminalling and storage revenues are based on actual volumes and rates.

Pipeline Segment Revenues. Pipeline margin activities primarily consist of the purchase and sale of crude oil shipped on our San Joaquin Valley system from barrel exchanges and buy/sell arrangements. Revenues associated with these activities are recognized at the time title to the product sold transfers to the purchaser, which occurs upon receipt of the product by the purchaser. Revenues for these transactions are recorded gross except in the case of barrel exchanges that are net settled. All of our pipeline margin activities revenues are based on actual volumes and prices. Revenues from pipeline tariffs and fees are associated with the transportation of crude oil at a published tariff as well as fees associated with line leases for committed space on a particular system that may or may not be utilized. Tariff revenues are recognized either at the point of delivery or at the point of receipt pursuant to specifications outlined in the regulated and non-regulated tariffs. Revenues associated with line lease fees are recognized in the month to which the lease applies, whether or not the space is actually utilized. All pipeline tariff and fee revenues are based on actual volumes and rates.

Purchases and Related Costs

Purchases and related costs include: (i) the cost of crude oil and LPG purchased; (ii) third party transportation and storage, whether by pipeline, truck or barge; and (iii) expenses to issue letters of credit to support these purchases. These purchases are accrued at the time title transfers to us which occurs upon receipt of the product.

Operating Expenses and General and Administrative Expenses

Operating expenses consist of various field and pipeline operating expenses including fuel and power costs, telecommunications, labor costs for truck drivers and pipeline field personnel, maintenance

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costs, regulatory compliance, insurance, vehicle leases, and property taxes. General and administrative expenses consist primarily of payroll and benefit costs, certain information system and legal costs, office rent, contract and consultant costs, and audit and tax fees.

Cash and Cash Equivalents

Cash and cash equivalents consist of all demand deposits and funds invested in highly liquid instruments with original maturities of three months or less and at times may exceed federally insured limits. We periodically assess the financial condition of the institutions where these funds are held and believe that any possible credit risk is minimal.

Accounts Receivable

Our accounts receivable are primarily from purchasers and shippers of crude oil. There were no amounts due from related parties at December 31, 2003 or 2002. The majority of our accounts receivable relate to our gathering and marketing activities that can generally be described as high volume and low margin activities, in many cases involving complex exchanges of crude oil volumes. We make a determination of the amount, if any, of the line of credit to be extended to any given customer and the form and amount of financial performance assurances we require. Such financial assurances are commonly provided in the form of standby letters of credit.

Accounts receivable included in the consolidated balance sheets are reflected net of our allowance for doubtful accounts. We routinely review our receivable balances to identify past due amounts and analyze the reasons such amounts have not been collected. In many instances, such delays involve billing delays and discrepancies or disputes as to the appropriate price, volumes or quality of crude oil delivered or exchanged. We also attempt to monitor changes in the creditworthiness of our customers as a result of developments related to each customer, the industry as a whole and the general economy. Based on these analyses as well as our historical experience and the facts and circumstances surrounding certain aged balances, we have established an allowance for doubtful trade accounts receivable and consider this reserve adequate; however, there is no assurance that actual amounts will not vary significantly from estimated amounts. The discovery of previously unknown facts or adverse developments affecting one of our counterparties or the industry as a whole could adversely impact our results of operations.

At December 31, 2003 and 2002, approximately 99% of net accounts receivable classified as current were less than 60 days past scheduled invoice date, and our allowance for doubtful accounts receivable classified as current totaled $0.2 million and $3.1 million, respectively. We consider these reserves adequate. At December 31, 2003 we had no accounts receivable balances or allowance for doubtful accounts classified as long-term. At December 31, 2002, approximately $11.5 million of accounts receivable ($6.5 million, net of a $5.0 million allowance) was classified as long-term. Following is a reconciliation of the changes in our allowance for doubtful accounts balances (in millions):

	December 31,
	2003			2002		2001
Balance at beginning of year	$	8.1		$	8.0	$	5.0
Applied to accounts receivable balances		(8.3	)		—		—
Charged to expense		0.4			0.1		3.0

Balance at end of year	$	0.2		$	8.1	$	8.0

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Inventory

Inventory primarily consists of crude oil and LPG in pipelines, storage tanks and rail cars which is valued at the lower of cost or market, with cost determined using an average cost method. In the fourth quarter of 2001, the Partnership recorded a $5.0 million noncash writedown of operating crude oil inventory to reflect prices at December 31, 2001. During 2001, the price of crude oil traded on the NYMEX averaged $25.98 per barrel. At December 31, 2001, the NYMEX crude oil price was approximately 24% lower, or $19.84 per barrel. There was no writedown of operating crude oil inventory at December 31, 2003 or 2002, as the market prices of crude oil and LPG were higher than our average cost per barrel. At December 31, 2003 and 2002, inventory consisted of (in millions):

	December 31,
	2003		2002
Crude oil	$	50.6	$	53.5
LPG		53.8		28.3
Other		1.6		—

	$	106.0	$	81.8

Property and Equipment and Pipeline Linefill

Property and equipment, net is stated at cost and consisted of the following (in millions):

	December 31,
	2003			2002
Crude oil pipelines and facilities	$	1,114.5		$	909.3
Crude oil and LPG storage and terminal facilities		100.8			82.4
Trucking equipment and other		43.8			30.0
Office property and equipment		13.5			8.6

		1,272.6			1,030.3
Less accumulated depreciation		(121.6	)		(77.5	)

	$	1,151.0		$	952.8

Depreciation expense for each of the three years in the period ended December 31, 2003, was $42.4 million, $30.2 million and $21.6 million, respectively. Our policy is to depreciate property and equipment over estimated useful lives as follows:

•: crude oil pipelines and facilities—30 to 40 years;
•: crude oil and LPG storage and terminal facilities—30 to 40 years;
•: trucking equipment and other—5 to 15 years; and
•: office property and equipment—3 to 5 years

We calculate our depreciation and amortization using the straight-line method, based on estimated useful lives and salvage values of our assets. These estimates are based on various factors including age (in the case of acquired assets), manufacturing specifications, technological advances and historical data concerning useful lives of similar assets. Uncertainties that impact these estimates include changes in laws and regulations relating to restoration and abandonment requirements, economic conditions, and supply and demand in the area. When assets are put into service, we make estimates with respect to useful lives and salvage values that we believe are reasonable. However, subsequent events could cause us to change our estimates, thus impacting the future calculation of depreciation and amortization.

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Historically, adjustments to useful lives have not had a material impact on our aggregate depreciation levels from year to year.

In accordance with our capitalization policy, costs associated with acquisitions and improvements, including related interest costs, which expand our existing capacity are capitalized. For the years ended December 31, 2003, 2002 and 2001, capitalized interest was $0.5 million, $0.8 million and $0.2 million, respectively. In addition, costs required either to maintain the existing operating capacity of partially or fully depreciated assets or to extend their useful lives are capitalized and classified as maintenance capital. Repair and maintenance expenditures associated with existing assets that do not extend the useful life or expand the operating capacity are charged to expense as incurred.

Linefill and minimum working inventory requirements are recorded at lower of cost or market and consists of crude oil and LPG used to pack a pipeline such that when an incremental barrel enters a pipeline it forces a barrel out at another location as well as minimum crude oil necessary to operate our storage and terminalling facilities. At December 31, 2003, we had approximately 4.6 million barrels of crude oil and 7.7 million gallons of LPG used to maintain our minimum linefill and working inventory requirements. Proceeds from the sale and repurchase of pipeline linefill are reflected as cash flows from operating activities in the accompanying consolidated statements of cash flows.

Asset Retirement Obligation

In June 2001, the FASB issued SFAS No. 143 "Asset Retirement Obligations." SFAS 143 establishes accounting requirements for retirement obligations associated with tangible long-lived assets, including (1) the time of the liability recognition, (2) initial measurement of the liability, (3) allocation of asset retirement cost to expense, (4) subsequent measurement of the liability and (5) financial statement disclosures. SFAS 143 requires that the cost for asset retirement should be capitalized as part of the cost of the related long-lived asset and subsequently allocated to expense using a systematic and rational method. Effective January 1, 2003, we adopted SFAS 143, as required. Determination of the amounts to be recognized upon adoption is based upon numerous estimates and assumptions, including future retirement costs, future inflation rates and the credit-adjusted risk-free interest rate. The majority of our assets, primarily related to our pipeline operations segment, have obligations to perform remediation and, in some instances, removal activities when the asset is abandoned. However, the fair value of the asset retirement obligations cannot be reasonably estimated, as the settlement dates are indeterminate. We will record such asset retirement obligations in the period in which we can reasonably determine the settlement dates. The adoption of this statement did not have a material impact on our financial position, results of operations or cash flows.

Impairment of Long-Lived Assets

Long-lived assets with recorded values that are not expected to be recovered through future cash flows are written-down to estimated fair value in accordance with SFAS No. 144 "Accounting for the Impairment or Disposal of Long-Lived Assets," as amended. Under SFAS 144, an asset shall be tested for impairment when events or circumstances indicate that its carrying value may not be recoverable. The carrying value of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. If the carrying value exceeds the sum of the undiscounted cash flows, an impairment loss equal to the amount the carrying value exceeds the fair value of the asset is recognized. Fair value is generally determined from estimated discounted future net cash flows. We adopted SFAS 144 on January 1, 2002, and there have been no events or circumstances indicating that the carrying value of any of our assets may not be recoverable.

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Other Assets

Other assets, net consist of the following (in millions):

	December 31,
	2003			2002
Goodwill	$	39.4		$	12.9
Deposit on Capline Acquisition		15.8			—
Debt issue costs		12.1			21.6
Investment in affiliate		7.8			8.0
Long term receivable, net		—			6.5
Fair value of derivative instruments		5.9			2.6
Intangible assets (contracts)		2.6			2.4
Other		7.1			2.6

		90.7			56.6
Less accumulated amortization		(1.7	)		(8.3	)

	$	89.0		$	48.3

Goodwill is recorded as the amount of the purchase price in excess of the fair value of certain assets purchased. At December 31, 2003, we recorded additional consideration related to the deferred portion of the purchase price in the CANPET acquisition (See Note 3). The entire amount of this consideration was recorded as additional goodwill. In accordance with SFAS No. 142, "Goodwill and Other Intangible Assets," which we adopted January 1, 2002, we test goodwill and other intangible assets periodically to determine whether an impairment has occurred. Goodwill is tested for impairment at a level of reporting referred to as a reporting unit. 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. As of December 31, 2003, no impairment has occurred.

Costs incurred in connection with the issuance of long-term debt and amendments to our credit facilities are capitalized and amortized using the straight-line method over the term of the related debt. Use of the straight-line method does not differ materially from the "effective interest" method of amortization. During the fourth quarter of 2003, we replaced our senior secured credit facilities with new senior unsecured credit facilities and we completed the sale of $250 million of 5.625% senior notes (See Note 6). We capitalized approximately $5.1 million of costs associated with those transactions. Also, in conjunction with the credit facility refinancing, we incurred a non-cash charge of approximately $3.3 million attributable to a loss on the early extinguishment of debt (included in Interest income and other, net on the Consolidated Statement of Operations). The loss consists of unamortized debt issue costs written off as a result of the completion of the new credit facility. In addition, we wrote off approximately $11.3 million of fully amortized debt issue costs and the related accumulated amortization.

Amortization of other assets for each of the three years in the period ended December 31, 2003, was $4.4 million, $3.9 million and $2.7 million, respectively.

Environmental Matters

We expense or capitalize, as appropriate, environmental expenditures. 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 when environmental assessments and/or remedial efforts are probable and we can reasonably estimate the costs. Generally, our recording of

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these accruals coincides with our completion of a feasibility study or our commitment to a formal plan of action.

Income and Other Taxes

Except as noted below, no provision for U.S. federal or Canadian income taxes related to our operations is included in the accompanying consolidated financial statements, because as a partnership we are not subject to federal, state or provincial income tax and the tax effect of our activities accrues to the unitholders. Net earnings for financial statement purposes may differ significantly from taxable income reportable to unitholders as a result of differences between the tax bases and financial reporting bases of assets and liabilities and the taxable income allocation requirements under the partnership agreement. Individual unitholders will have different investment bases depending upon the timing and price of acquisition of partnership units. Further, each unitholder's tax accounting, which is partially dependent upon the unitholder's tax position, may differ from the accounting followed in the consolidated financial statements. Accordingly, there could be significant differences between each individual unitholder's tax bases and the unitholder's share of the net assets reported in the consolidated financial statements. We do not have access to information about each individual unitholder's tax attributes, and the aggregate tax basis cannot be readily determined. Accordingly, we do not believe that in our circumstances, the aggregate difference would be meaningful information.

The Partnership's Canadian operations are conducted through an operating limited partnership, of which our wholly owned subsidiary PMC (Nova Scotia) Company is the general partner. For Canadian tax purposes, the general partner is taxed as a corporation, subject to income taxes and a capital-based tax at federal and provincial levels. For 2003 and 2002, the income tax was not material and the capital-based tax was approximately $0.4 million (U.S.) and $0.5 million (U.S), respectively. In addition, interest payments made by Plains Marketing Canada, L.P. on its intercompany loan from Plains Marketing, L.P. are subject to a 10% Canadian withholding tax, which for 2003 and 2002 totaled $0.4 million and $0.5 million, respectively, and is recorded in other expense.

In addition to federal income taxes, owners of our common units may be subject to other taxes, such as state and local and Canadian federal and provincial taxes, unincorporated business taxes, and estate, inheritance or intangible taxes that may be imposed by the various jurisdictions in which we do business or own property. A unitholder may be required to file Canadian federal income tax returns, pay Canadian federal and provincial income taxes, file state income tax returns and pay taxes in various states.

Derivative Instruments and Hedging Activities

We utilize various derivative instruments to (i) manage our exposure to commodity price risk, (ii) engage in a controlled trading program, (iii) manage our exposure to interest rate risk and (iv) manage our exposure to currency exchange rate risk. Beginning January 1, 2001, we record all derivative instruments on the balance sheet as either assets or liabilities measured at their fair value under the provisions of SFAS 133, "Accounting for Derivative Instruments and Hedging Activities" as amended by SFAS 137 and SFAS 138 (collectively "SFAS 133"). At adoption, and in accordance with the transition provisions of SFAS 133, we recorded a loss of $8.3 million in Other Comprehensive Income ("OCI"), representing the cumulative effect of an accounting change to recognize, at fair value, all cash flow derivatives. We also recorded a noncash gain of $0.5 million in earnings as a cumulative effect adjustment. SFAS 133 requires that changes in derivative instruments fair value be recognized currently in earnings unless specific hedge accounting criteria are met, in which case, changes in fair value are deferred to OCI and reclassified into earnings when the underlying transaction affects earnings. Accordingly, changes in fair value are included in the current period for (i) derivatives characterized as fair value hedges, (ii) derivatives that do not qualify for hedge accounting and (iii) the

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portion of cash flow hedges that is not highly effective in offsetting changes in cash flows of hedged items.

Net Income Per Unit

Basic and diluted net income per unit is determined by dividing net income after deducting the amount allocated to the general partner interest, (including its incentive distribution in excess of its 2% interest), by the weighted average number of outstanding limited partner units, including common units and subordinated units. Partnership income is first allocated to the general partner based on the amount of incentive distributions. The remainder is then allocated between the limited partners and general partner based on percentage ownership in the Partnership. Other comprehensive income is allocated based on the same effective percentages. The following table sets forth the computation of basic and diluted net income per limited partner unit for 2003, 2002 and 2001 (in millions, except per unit amounts). The net income available to limited partners and the weighted average limited partner units outstanding have been adjusted for the impact of the contingent equity issuance related to the CANPET acquisition for the calculation of diluted net income per limited partner unit (See Note 3).

			Year Ended December 31,
			2003			2002			2001
			(in millions, except per unit data)
Net income			$	59.4		$	65.3		$	44.2
Less:
	General partner incentive distributions			(4.9	)		(3.1	)		(1.1	)
	General partner 2% ownership			(1.1	)		(1.3	)		(0.9	)

Numerator for basic earnings per limited partner unit:
	Net income available for common unitholders			53.4			60.9			42.2
	Effect of dilutive securities:
		Increase in general partner's incentive distribution—Contingent equity issuance		(0.1	)		—			—

Numerator for diluted earnings per limited partner unit			$	53.3		$	60.9		$	42.2

Denominator:
	Denominator for basic earnings per limited partner unit—weighted average number of limited partner units			52.7			45.5			37.5
	Effect of dilutive securities:
		Contingent equity issuance		0.7			—			—

Denominator for diluted earnings per limited partner unit—weighted average number of limited partner units				53.4			45.5			37.5

Basic net income per limited partner unit			$	1.01		$	1.34		$	1.13

Diluted net income per limited partner unit			$	1.00		$	1.34		$	1.13

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Note 3—Acquisitions

The following acquisitions were accounted for using the purchase method of accounting and the purchase price was allocated in accordance with such method. In addition, we adopted SFAS No. 141, "Business Combinations" in 2001 and followed the provisions of that statement for all business combinations initiated after June 30, 2001.

Significant Acquisitions

Shell West Texas Assets

On August 1, 2002, we acquired from Shell Pipeline Company LP and Equilon Enterprises LLC interests in approximately 2,000 miles of gathering and mainline crude oil pipelines and approximately 8.9 million barrels (net to our interest) of above-ground crude oil terminalling and storage assets in West Texas (the "Shell acquisition"). The results of operations and assets from this acquisition have been included in our consolidated financial statements and in our pipeline operations segment since that date. The primary assets included in the transaction were interests in the Basin Pipeline System, the Permian Basin Gathering System and the Rancho Pipeline System. These assets complement our existing asset infrastructure in West Texas and represent a transportation link to Cushing, Oklahoma, where we are a provider of storage and terminalling services. The total purchase price of $324.4 million consisted of (i) $304.0 million in cash, which was borrowed under our revolving credit facility, (ii) approximately $9.1 million related to the settlement of pre-existing accounts receivable and inventory balances and (iii) approximately $11.3 million of estimated transaction and closing costs. The entire purchase price was allocated to property and equipment.

CANPET Energy Group Inc.

In July 2001, we acquired the assets of CANPET Energy Group Inc. ("CANPET"), a Calgary-based Canadian crude oil and LPG marketing company, for approximately $24.6 million plus excess inventory at the closing date of approximately $25.0 million. A portion of the purchase price, payable in common units or cash at our option, was deferred subject to various performance standards being met. In addition, an amount will be paid equivalent to the distributions that would have been paid on the common units assuming (i) the deferred portion of the purchase price was paid in common units and (ii) they had been outstanding since the acquisition date. As of December 31, 2003, we determined that it was beyond a reasonable doubt that the performance standards were met and we recorded additional consideration of $24.3 million (see Note 7) resulting in aggregate consideration of $73.9 million. The deferred consideration was recorded as additional goodwill.

At the time of the acquisition, CANPET's activities consisted of gathering approximately 75,000 barrels per day of crude oil and marketing an average of approximately 26,000 barrels per day of natural gas liquids or LPG's. The principal assets acquired include a crude oil handling facility, a 130,000-barrel tank facility, LPG facilities, existing business relationships and operating inventory. The acquired assets are part of our strategy to establish a Canadian operation that complements our operations in the United States. Initial financing for the acquisition was provided through borrowings under our credit facility.

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The purchase price, as adjusted post-closing, was allocated as follows (in millions):

Inventory	$	28.1
Goodwill		35.4
Intangible assets (contracts)		1.0
Pipeline linefill		4.3
Crude oil gathering, terminalling and other assets		5.1

Total	$	73.9

Murphy Oil Company Ltd. Midstream Operations

In May 2001, we closed the acquisition of substantially all of the Canadian crude oil pipeline, gathering, storage and terminalling assets of Murphy Oil Company Ltd. for approximately $158.4 million in cash after post-closing adjustments (the "Murphy acquisition"), including financing and transaction costs. Initial financing for the acquisition was provided through borrowings under our credit facilities. The purchase included $6.5 million for excess inventory in the pipeline systems. The principal assets acquired include approximately 560 miles of crude oil and condensate transmission mainlines (including dual lines on which condensate is shipped for blending purposes and blended crude is shipped in the opposite direction) and associated gathering and lateral lines, approximately 1.1 million barrels of crude oil storage and terminalling capacity located primarily in Kerrobert, Saskatchewan, approximately 254,000 barrels of pipeline linefill and tank inventories, and 121 trailers used primarily for crude oil transportation. The acquired assets are part of our strategy to establish a Canadian operation that complements our operations in the United States.

Murphy agreed to continue to transport production from fields previously delivering crude oil to these pipeline systems, under a long-term contract. At the time of the acquisition, the volume under the contract was approximately 11,000 barrels per day. Total volumes transported on the pipeline system in 2001 were approximately 223,000 barrels per day of light, medium and heavy crudes, as well as condensate.

The purchase price, as adjusted post-closing, was allocated as follows (in millions):

Crude oil pipeline, gathering and terminal assets	$	148.0
Pipeline linefill		7.6
Net working capital items		2.0
Other property and equipment		0.5
Other assets, including debt issue costs		0.3

Total	$	158.4

Other Acquisitions

2003 Acquisitions

During 2003, we completed ten acquisitions for aggregate consideration totaling approximately $159.5 million. The aggregate consideration includes cash paid, estimated transaction costs, assumed liabilities and estimated near-term capital costs. These acquisitions included mainline crude oil

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pipelines, crude oil gathering lines, terminal and storage facilities, and an underground LPG storage facility. The aggregate purchase price was allocated as follows (in million):

Crude oil pipelines and facilities	$	138.0
Crude oil and LPG storage facilities		7.3
Trucking equipment and other		7.8
Office property and equipment		1.2
Pipeline Linefill		4.7
Goodwill		0.5

	$	159.5

2002 Acquisitions

During 2002, in addition to the Shell acquisition, we completed two acquisitions for aggregate consideration totaling approximately $15.9 million including transaction costs. These acquisitions include crude oil pipeline, gathering and marketing assets and a 22% equity interest in a pipeline company. With the exception of $1.3 million that was allocated to goodwill, the aggregate purchase price was allocated to property and equipment.

2001 Acquisition

In December 2001, in addition to the CANPET and Murphy acquisitions, we acquired the Wapella Pipeline System from private investors for approximately $12.0 million, including transaction costs. The entire purchase price was allocated to property and equipment. The system includes a crude oil pipeline and approximately 21,500 barrels of crude oil storage capacity located along the system as well as a truck terminal.

Note 4—Asset Dispositions

Shutdown of Rancho Pipeline System

We acquired the Rancho Pipeline System in conjunction with the Shell acquisition. The Rancho Pipeline System Agreement dated November 1, 1951, pursuant to which the system was constructed and operated, terminated in March 2003. Upon termination, the agreement required the owners to take the pipeline system, in which we owned an approximate 50% interest, out of service. Accordingly, we notified our shippers and did not accept nominations for movements after February 28, 2003. This shutdown was contemplated at the time of the acquisition and was accounted for under purchase accounting in accordance with SFAS No. 141 "Business Combinations." The pipeline was shut down on March 1, 2003 and a purge of the crude oil linefill was completed in April 2003. In June 2003, we completed transactions whereby we transferred all of our ownership interest in approximately 240 miles of the total 458 miles of the pipeline in exchange for $4.0 million and approximately 500,000 barrels of crude oil tankage in West Texas. The remaining portion will either be sold or salvaged. No gain or loss has been recorded on the shutdown of the Rancho System or these transactions.

Other Dispositions

During 2003 and 2002, we sold various other property and equipment for proceeds totaling approximately $8.5 million and $1.4 million, respectively. A gain of approximately $0.6 million was recognized in 2003 and no gain or loss was recognized in 2002. In December 2001, we sold excess communications equipment and recognized a gain of $1.0 million.

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Note 5—Industry Credit Markets

Throughout the latter part of 2001 and all of 2002, there have been significant disruptions and extreme volatility in the financial markets and credit markets. Because of the credit intensive nature of the energy industry and extreme financial distress at several large, diversified energy companies, the energy industry has been especially impacted by these developments. Accordingly, we are exposed to an increased level of direct and indirect counterparty credit and performance risk.

The majority of our credit extensions and therefore our accounts receivable relate to our gathering and marketing activities that can generally be described as high volume and low margin activities. In our credit approval process, we must determine the amount, if any, of the line of credit to be extended to any given customer and the form and amount of financial performance assurances we require. Such financial assurances are commonly provided to us in the form of standby letters of credit, advance cash payments or "parental" guarantees. At December 31, 2003, we had received approximately $44.0 million of advance cash payments and prepayments from third parties to mitigate credit risk.

Note 6—Debt

Short-term debt consists of the following (in millions):

	December 31,
	2003		2002
Senior secured hedged inventory borrowing facility bearing interest at a rate of 1.9% at December 31, 2003	$	100.5	$	—
Senior unsecured $425 million domestic revolving credit facility—working capital borrowings, bearing interest at a rate of 4.0% at December 31, 2003⁽¹⁾		25.3		—
Senior secured letter of credit and borrowing facility bearing interest at a rate of 3.4% at December 31, 2002		—		97.7
Other		1.5		1.5

Total short-term debt and current maturities of long-term debt	$	127.3	$	99.2

⁽¹⁾: At December 31, 2003, we have classified $25.3 million of borrowings under our Senior unsecured domestic revolving credit facility as short-term. These borrowings are designated as working capital borrowings under this facility and primarily are for hedged LPG inventory and New York Mercantile Exchange ("NYMEX") margin deposits and must be repaid within one year.

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Long-term debt consists of the following (in millions):

	December 31,
	2003		2002
5.63% senior notes due December 2013, net of unamortized discount of $0.7 million	$	249.3	$	—
7.75% senior notes due October 2012, net of unamortized discount of $0.3 million and $0.4 million at December 31, 2003 and 2002, respectively		199.7		199.6
Senior unsecured $170 million Canadian revolving credit facility, bearing interest at a rate of 2.17% at December 31, 2003		70.0		—
Senior secured domestic revolving credit facility, bearing interest at a rate of 4.8% at December 31, 2002		—		10.4
Senior secured term B loan, bearing interest at a rate of 3.9% at December 31, 2002		—		198.0
Senior secured term loan, bearing interest at a rate of 3.9% at December 31, 2002		—		99.0
$30 million Canadian senior secured revolving credit facility, bearing interest at a rate of 5.0% at December 31, 2002		—		2.7

Total long-term debt^(1),(2)	$	519.0	$	509.7

⁽¹⁾: At December 31, 2002, we classified $9 million of term loan payments due in 2003 as long term due to our intent and ability to refinance those maturities using the revolving facility.
⁽²⁾: At December 31, 2003, we have classified $25.3 million of borrowings under our Senior unsecured domestic revolving credit facility as short-term. These borrowings are designated as working capital borrowings under this facility and primarily are for hedged LPG inventory and NYMEX margin deposits and must be repaid within one year.

Credit Facilities

During November 2003, we refinanced our bank credit facilities with new senior unsecured credit facilities totaling $750 million and a $200 million uncommitted facility for the purpose of financing hedged crude oil. The $750 million of new facilities consist of:

•: a four-year, $425 million U.S. revolving credit facility;
•: a 364-day, $170 million Canadian revolving credit facility with a five-year term-out option;
•: a four-year, $30 million Canadian working capital revolving credit facility; and
•: a 364-day, $125 million revolving credit facility.

All of the facilities with the exception of the $200 million hedged inventory facility are unsecured. The $200 million hedged inventory facility is an uncommitted working capital facility, which will be used to finance the purchase of hedged crude oil inventory for storage when market conditions warrant. Borrowings under the hedged inventory facility will be secured by the inventory purchased under the facility and the associated accounts receivable, and will be repaid from the proceeds from the sale of such inventory.

Senior Notes

During December 2003, we completed the sale of $250 million of 5.625% senior notes due in December 2013. The notes were issued by Plains All American Pipeline, L.P. and a 100% owned consolidated finance subsidiary (neither of which have independent assets or operations) at a discount of $0.7 million, resulting in an effective interest rate of 5.66%. Interest payments are due on June 15

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and December 15 of each year. The notes are fully and unconditionally guaranteed, jointly and severally, by all of our existing 100% owned subsidiaries, except for subsidiaries which are minor.

During September 2002, we completed the sale of $200 million of 7.75% senior notes due in October 2012. The notes were issued by Plains All American Pipeline, L.P. and a 100% owned consolidated finance subsidiary (neither of which have independent assets or operations) at a discount of $0.4 million, resulting in an effective interest rate of 7.78%. Interest payments are due on April 15 and October 15 of each year. The notes are fully and unconditionally guaranteed, jointly and severally, by all of our existing 100% owned subsidiaries, except for subsidiaries which are minor.

Covenants and Compliance

Our credit facilities, the indenture governing the 5.625% senior notes and the indenture governing the 7.75% senior notes contain cross default provisions. Our credit facilities prohibit distributions on, or purchases or redemptions of, units if any default or event of default is continuing. In addition, the agreements contain various covenants limiting our ability to, among other things:

•: incur indebtedness if certain financial ratios are not maintained;
•: grant liens;
•: engage in transactions with affiliates;
•: enter into sale-leaseback transactions;
•: sell substantially all of our assets or enter into a merger or consolidation

Our credit facilities treat a change of control as an event of default and also require us to maintain:

•: a debt coverage ratio which will not be greater than: 4.50 to 1.0 on all outstanding debt and 5.25 to 1.0 on all outstanding debt during an acquisition period (generally, the period consisting of three fiscal quarters following an acquisition); and
•: an interest coverage ratio that is not less than 2.75 to 1.0.

For covenant compliance purposes, letters of credit and borrowings to fund hedged inventory and margin requirements are excluded when calculating the debt coverage ratio.

A default under our credit facilities would permit the lenders to accelerate the maturity of the outstanding debt. As long as we are in compliance with our credit agreements, they do not restrict our ability to make distributions of "available cash" as defined in our partnership agreement. We are in compliance with the covenants contained in our credit facilities and indentures.

Letters of Credit

As is customary in our industry, and in connection with our crude oil marketing, we provide certain suppliers and transporters with irrevocable standby letters of credit to secure our obligation for the purchase of crude oil. Our liabilities with respect to these purchase obligations are recorded in accounts payable on our balance sheet in the month the crude oil is purchased. Generally, these letters of credit are issued for up to seventy-day periods and are terminated upon completion of each transaction. At December 31, 2003 and 2002, we had outstanding letters of credit of approximately $57.9 million and $52.5 million, respectively. In addition to changes in the level of activity and other factors, the amount of letters of credit outstanding varies based on NYMEX crude oil prices, which were $32.52 per barrel and $29.45 per barrel at December 31, 2003 and 2002, respectively.

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Maturities

The weighted average life of our long-term debt outstanding at December 31, 2003, was approximately 9 years and all balances mature in 2009 or later.

Note 7—Partners' Capital and Distributions

Units Outstanding

Partners' capital at December 31, 2003 consists of (1) 50,809,746 common units, including 1,307,190 Class B common units, representing a 85.4% effective aggregate ownership interest in the Partnership and its subsidiaries, (after giving affect to the general partner interest), (2) 7,522,214 subordinated units representing a 12.6% effective aggregate ownership interest in the Partnership and its subsidiaries (after giving affect to the general partner interest) and (3) a 2% general partner interest.

Class B Common Units

The Class B common units are initially pari passu with common units with respect to distributions, and are convertible into common units upon approval of a majority of the common unitholders. The Class B unitholders may request that we call a meeting of common unitholders to consider approval of the conversion of Class B units into common units. If the approval of a conversion by the common unitholders is not obtained within 120 days of a request, each Class B common unitholder will be entitled to receive distributions, on a per unit basis, equal to 110% of the amount of distributions paid on a common unit, with such distribution right increasing to 115% if such approval is not secured within 90 days after the end of the 120-day period. Except for the vote to approve the conversion, Class B common units have the same voting rights as the common units.

Subordinated Units and Conversion

The subordinated units have a debit balance in Partners' Capital of approximately $39.9 million at December 31, 2003. The debit balance is the result of several different factors including: (i) a low initial capital balance in connection with the formation of the partnership as a result of a low carry-over book basis in the assets contributed to the Partnership at the date of formation, (ii) a significant net loss in 1999 and (iii) distributions to unitholders that have exceeded net income allocated to unitholders each period. Additionally, the capital balances of the common unitholders and the General Partner have increased periodically as additional units have been sold and as the General Partner has made additional capital contributions associated with those offerings. The subordinated unitholders are not required to make any additional contributions associated with those offerings of common units. No additional Subordinated Units were issued after the initial issuance.

Pursuant to the terms of our Partnership Agreement and having satisfied the financial tests contained therein, in November 2003, 25% of the Subordinated Units converted to Common Units on a one-for-one basis. In February 2004, all of the remaining Subordinated Units converted to Common Units on a one-for-one basis.

General Partner Incentive Distributions

Our general partner is entitled to receive incentive distributions if the amount we distribute with respect to any quarter exceeds levels specified in our partnership agreement. Under the quarterly incentive distribution provisions, generally the general partner is entitled, without duplication, to 15% of amounts we distribute in excess of $0.450 per unit ("MQD"), 25% of the amounts we distribute in excess of $0.495 per unit and 50% of amounts we distribute in excess of $0.675 per unit (referred to as

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"incentive distributions"). Cash distributions on our outstanding units and the portion of the distributions representing an excess over the MQD were as follows:

	Year
	2003				2002				2001
	Distribution		Excess over MQD		Distribution		Excess over MQD		Distribution		Excess over MQD
First Quarter	$	0.5500	$	0.1000	$	0.5250	$	0.0750	$	0.4750	$	0.0250
Second Quarter	$	0.5500	$	0.1000	$	0.5375	$	0.0875	$	0.5000	$	0.0500
Third Quarter	$	0.5500	$	0.1000	$	0.5375	$	0.0875	$	0.5125	$	0.0625
Fourth Quarter	$	0.5625	$	0.1125	$	0.5375	$	0.0875	$	0.5125	$	0.0625

Distributions

We will distribute 100% of our available cash within 45 days after the end of each quarter to unitholders of record and to our general partner. Available cash is generally defined as all of our cash and cash equivalents on hand at the end of each quarter less reserves established by our general partner for future requirements.

During 2003, we paid distributions of approximately $121.8 million ($2.19 on a per unit basis), with approximately $92.7 million paid to our common unitholders, $21.9 million paid to our subordinated unitholders and $2.3 million and $4.9 million paid to our general partner for its general partner and incentive distribution interests, respectively.

During 2002, we paid distributions of approximately $99.8 million ($2.11 on a per unit basis), with approximately $73.6 million paid to our common unitholders, $21.1 million paid to our subordinated unitholders and $2.0 million and $3.1 million paid to our general partner for its general partner and incentive distribution interests, respectively.

During 2001, we paid distributions of approximately $75.9 million ($1.95 on a per unit basis), with approximately $53.8 million paid to our common unitholders, $19.5 million paid to our subordinated unitholders and $1.5 million and $1.1 million paid to our general partner for its general partner and incentive distribution interests, respectively.

On January 22, 2004, we declared a cash distribution of $0.5625 per unit on our outstanding common units, Class B common units and subordinated units. The distribution was paid on February 13, 2004, to unitholders of record on February 3, 2004, for the period October 1, 2003, through December 31, 2003. The total distribution paid was approximately $35.2 million, with approximately $28.7 million paid to our common unitholders, $4.2 million paid to our subordinated unitholders and $0.7 million and $1.6 million paid to our general partner for its general partner and incentive distribution interests, respectively.

Equity Offerings

In December 2003, we completed a public offering of 2,840,800 common units for $31.94 per unit. The offering resulted in gross proceeds of approximately $90.7 million from the sale of the units and approximately $1.8 million from our general partner's proportionate capital contribution. Total costs associated with the offering, including underwriter fees and other expenses, were approximately $4.1 million. Net proceeds of approximately $88.4 million were used to reduce outstanding borrowings under our revolving credit facility.

In September 2003, we completed a public offering of 3,250,000 common units for $30.91 per unit. The offering resulted in gross proceeds of approximately $100.5 million from the sale of the units and approximately $2.1 million from our general partner's proportionate capital contribution. Total costs associated with the offering, including underwriter fees and other expenses, were approximately

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$4.5 million. Net proceeds of approximately $98.0 million were used to reduce outstanding borrowings under the domestic revolving credit facility and reduce the principal balance on our Senior secured term B loan.

In March 2003, we completed a public offering of 2,645,000 common units for $24.80 per unit. The offering resulted in gross proceeds of approximately $65.6 million from the sale of the units and approximately $1.3 million from our general partner's proportionate capital contribution. Total costs associated with the offering, including underwriter fees and other expenses, were approximately $3.0 million. Net proceeds of approximately $63.9 million were used to reduce outstanding borrowings under the domestic revolving credit facility.

In August 2002, we completed a public offering of 6,325,000 common units for $23.50 per unit. The offering resulted in cash proceeds of approximately $148.6 million from the sale of the units and approximately $3.0 million from our general partner's proportionate capital contribution. Total costs associated with the offering, including underwriter fees and other expenses, were approximately $6.6 million. Net proceeds of approximately $145.0 million were used to reduce outstanding borrowings under the domestic revolving credit facility.

In May 2001, we completed a public offering of 3,966,700 common units. Total net cash proceeds from the offering, including our former general partner's proportionate contribution, were approximately $100.7 million. In addition, in October 2001, we completed a public offering of 4,900,000 common units. Net cash proceeds from the offering, including our general partner's proportionate contribution, were approximately $126.0 million. The net proceeds were used to repay borrowings under our revolving credit facility, a portion of which was used to finance our Canadian acquisitions.

Contingent Equity Issuance

In connection with the CANPET acquisition in July 2001, a portion of the purchase price, payable in common units, was deferred subject to various performance objectives being met. These objectives have been met as of December 31, 2003, and the deferred amount is payable on April 30, 2004. The number of common units issued in satisfaction of the deferred payment will depend upon the average trading price of our common units for a ten-day trading period prior to the payment date and the Canadian and U.S. dollar exchange rate on the payment date. In addition, an amount will be paid equivalent to the distributions that would have been paid on the common units had they been outstanding since the acquisition was consummated. At our option, the deferred payment may be paid in cash rather than the issuance of units. Assuming the entire obligation is satisfied with common units, based on the foreign exchange rate in effect at December 31, 2003, (1.30 to 1 Canadian dollar to U.S. dollar exchange rate) and an estimated $33.35 per unit price, approximately 613,000 units would be issued and approximately $3.9 million would be paid related to distributions. We currently anticipate that one-third of the contingent purchase price and all of the amount related to past distributions will be paid in cash and the remainder will be settled with approximately 409,000 common units.

Note 8—Derivatives and Financial Instruments

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hedging instrument's effectiveness will be assessed. Both at the inception of the hedge and on an ongoing basis, we assess whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in cash flows of hedged items.

Summary of Financial Impact

The following is a summary of the financial impact of the derivative instruments and hedging activities discussed below. At December 31, 2003, the balance sheet includes assets of $27.9 million ($22.0 million current), liabilities of $28.1 million ($17.1 million current) and related unrealized losses deferred to OCI of $1.6 million related to open derivative positions. Revenues for the year ended December 31, 2003 include a noncash gain of $0.4 million ($1.4 million noncash gain net of the reversal of the prior period fair value adjustment related to contracts that settled during the current year). Our hedge-related assets and liabilities are included in other current and non-current assets and liabilities in the consolidated balance sheet. In addition, during the fourth quarter of 2003 we terminated and cash settled three interest-rate risk hedging instruments for approximately $6.2 million. The net deferred loss related to these instruments was deferred in OCI and is being amortized into interest expense over the original terms of the terminated instruments (approximately fifty percent over three years and the remaining fifty percent over ten years).

As of December 31, 2003, the total amount of deferred net losses recorded in OCI are expected to be reclassified to future earnings, contemporaneously with the related physical purchase or delivery of the underlying commodity or payments of interest. During the periods ended December 31, 2003 and 2002, no amounts were reclassified to earnings from OCI in connection with forecasted transactions that were no longer considered probable of occurring. Based on the aggregate amounts deferred in OCI at December 31, 2003, a net loss of $0.4 million will be reclassified to earnings in the next twelve months and the remainder by 2013. Since a portion of these amounts are based on market prices at the current period end, actual amounts to be reclassified will differ and could vary materially as a result of changes in market conditions.

The following sections discuss our risk management activities in the indicated categories.

Commodity Price Risk Hedging

We hedge our exposure to price fluctuations with respect to crude oil and LPG in storage, and expected purchases, sales and transportation of these commodities. The derivative instruments utilized consist primarily of futures and option contracts traded on the NYMEX and over-the-counter transactions, including crude oil swap and option contracts entered into with financial institutions and other energy companies (see Note 5 for a discussion of the mitigation of credit risk). In accordance with SFAS 133, these derivative instruments are recorded in the balance sheet as assets or liabilities at their fair values. The majority of our commodity price risk derivative instruments qualify for hedge accounting as cash flow hedges. Therefore, the corresponding changes in fair value for the effective portion of the hedge are deferred in OCI and recognized in revenues or purchases in the periods during which the underlying physical transactions occur. At December 31, 2003 there was an unrealized gain of $2.1 million deferred in OCI related to our commodity price risk activities. All of these deferred positions mature by December 2004. An unrealized gain of $1.2 million related to these activities was deferred in OCI at December 31, 2002. For each of the three years ended December 31, 2003, income of $0.5 million, $0.3 million and $0.4 million (excluding the impact of the adoption of SFAS 133), respectively, was included in revenues due to changes in the fair value of derivatives that do not qualify for hedge accounting and the portion of cash flow hedges that are not highly effective. We have determined that our physical purchase and sale agreements qualify for the normal purchase and sale exclusion and thus are not subject to SFAS 133.

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Controlled Trading Program

While we seek to maintain a position that is substantially balanced within our crude oil lease purchase and LPG activities, we may experience net unbalanced positions for short periods of time as a result of production, transportation and delivery variances as well as logistical issues associated with inclement weather conditions. In connection with managing these positions and maintaining a constant presence in the marketplace, both necessary for our core business, we engage in a controlled trading program for up to an aggregate of 500,000 barrels of crude oil and an aggregate of 250,000 barrels of LPG. These activities are monitored independently by our risk management function and must take place within predefined limits and authorizations. In accordance with SFAS 133, these derivative instruments are recorded in the balance sheet as assets or liabilities at their fair value, with the changes in fair value recorded net in revenues. There were no open positions under this program at December 31, 2003 and 2002. The realized earnings impact related to these activities for the years ended December 31, 2003, 2002 and 2001, was a loss of $0.1 million, income of $0.1 million and a loss of $0.9 million, respectively.

Interest Rate Risk Hedging

We also utilize various products, such as interest rate swaps, collars and treasury locks to hedge interest obligations on specific debt issuances, including anticipated debt issuances. All of these instruments are placed with large creditworthy financial institutions.

At December 31, 2003, there was one interest rate swap outstanding with an aggregate notional principal amount of $50 million. The interest rate swap is based on LIBOR rates and provides for a LIBOR rate of 4.3% expiring in March 2004. Interest on the underlying debt being hedged is based on LIBOR plus a margin.

The instruments outstanding at December 31, 2002, consisted of interest rate swaps and a treasury lock with an aggregate notional principal amount of $150 million. The interest rate swaps were based on LIBOR rates and provided for a LIBOR rate of 5.1% for a $50.0 million notional principal amount expiring October 2006 and a LIBOR rate of 4.3% for a $50.0 million notional principal amount expiring March 2004. Interest on the underlying debt that was hedged was based on LIBOR plus a margin. During 2002, we entered into a treasury lock in anticipation of the issuance of our 7.75% senior notes due October 2012 and potential subsequent add-on thereto. A treasury lock is a financial derivative instrument that enables the company to lock in the U.S. Treasury Note rate. The treasury lock had a notional principal amount of $50.0 million and an effective interest rate of 4.60%. The treasury lock matured in January 2003, was extended to March 2003 with an effective interest rate of 4.68%, was converted to a forward starting swap and was subsequently unwound in conjunction with the issuance of our 5.625% Senior Notes.

The instruments outstanding at December 31, 2003 and 2002 qualify for hedge accounting as cash flow hedges in accordance with SFAS 133. The effective portion of changes in fair values of these hedges is recorded in OCI until the related hedged item impacts earnings. At December 31, 2003, and 2002, there was a $6.5 million unrealized loss and a $9.6 million unrealized loss, respectively, deferred in OCI related to our interest rate risk activities. As discussed above, approximately $6.1 million of the loss deferred in OCI at December 31, 2003, relates to instruments terminated and cash settled during 2003. During 2003 and 2002, there were no amounts recognized in earnings related to hedge ineffectiveness.

Currency Exchange Rate Risk Hedging

Because a significant portion of our Canadian business is conducted in Canadian dollars (CAD), we use certain financial instruments to minimize the risks of unfavorable changes in exchange rates. These instruments include forward exchange contracts, forward extra option contracts and cross

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currency swaps. Additionally, at times, a portion of our debt is denominated in Canadian dollars. At December 31, 2003 we did not have any Canadian dollar debt and at December 31, 2002, $2.7 million of our long-term debt was denominated in Canadian dollars ($4.3 million CAD based on a Canadian dollar to U.S. dollar exchange rate of 1.58 to 1). All of these financial instruments are placed with large creditworthy financial institutions.

At December 31, 2003, we had forward exchange contracts that allow us to exchange approximately $2.0 million Canadian for at least $1.5 million U.S. quarterly during 2004 and approximately $1.0 million Canadian for at least $0.7 million U.S. quarterly during 2005 (based on a Canadian dollar to U.S. dollar exchange rate of approximately 1.33 to 1 and 1.34 to 1, respectively). In addition, at December 31, 2003, we also had cross currency swap contracts for an aggregate notional principal amount of $23.0 million, effectively converting this amount of our U.S. dollar denominated debt to $35.6 million of Canadian dollar debt (based on a Canadian dollar to U.S. dollar exchange rate of 1.55 to 1). The notional principal amount reduces by $2.0 million U.S. on May 2004 and May 2005 and has a final maturity in May 2006 ($19.0 million U.S.).

At December 31, 2002, we had forward exchange contracts and forward extra option contracts that allow us to exchange $3.0 million Canadian for at least $1.9 million U.S. quarterly during 2003 (based on a Canadian dollar to U.S. dollar exchange rate of 1.54 to 1). At December 31, 2002, we also had cross currency swap contracts for an aggregate notional principal amount of $24.8 million, effectively converting this amount of our U.S. dollar denominated debt to $38.3 million of Canadian dollar debt (based on a Canadian dollar to U.S. dollar exchange rate of 1.55 to 1).

The forward exchange contracts and forward extra option contracts qualify for hedge accounting as cash flow hedges and the cross currency swaps qualify for hedge accounting as fair value hedges, both in accordance with SFAS 133. Such derivative activity resulted in an unrealized loss of $0.3 million and an unrealized gain of $0.2 million deferred in OCI related to our currency exchange rate cash flow hedges at December 31, 2003 and 2002, respectively. The earnings impact related to our currency exchange rate fair value hedges was a loss of $0.1 million for the year ended December 31, 2003 and nominal for the year ended December 31, 2002.

Fair Value of Financial Instruments

The carrying amounts and fair values of our financial instruments are as follows (in millions):

	December 31,
	2003						2002
	Carrying Amount			Fair Value			Carrying Amount			Fair Value
NYMEX futures	$	7.5		$	7.5		$	0.6		$	0.6
Options and swaps	$	(3.3	)	$	(3.3	)	$	(0.6	)	$	(0.6	)
Forward exchange contracts	$	(0.4	)	$	(0.4	)	$	0.1		$	0.1
Forward extra option contracts	$	—		$	—		$	0.2		$	0.2
Cross currency swaps	$	(4.8	)	$	(4.8	)	$	0.3		$	0.3
Treasury lock	$	—		$	—		$	(3.3	)	$	(3.3	)
Interest rate swaps	$	(0.4	)	$	(0.4	)	$	(6.3	)	$	(6.3	)
Short and long-term debt under credit facilities	$	95.3		$	95.3		$	409.4		$	409.4
Senior notes	$	449.0		$	482.9		$	199.6		$	209.0

As of December 31, 2003 and 2002, the carrying amounts of items comprising current assets and current liabilities approximate fair value due to the short-term maturities of these instruments. The carrying amounts of the variable rate instruments in our credit facilities approximate fair value primarily because the interest rates fluctuate with prevailing market rates, while the interest rate on the 5.625% and the 7.75% senior notes is fixed and the fair value is based on quoted market prices.

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The carrying amount of our derivative financial instruments approximate fair value as these instruments are recorded on the balance sheet at their fair value under SFAS 133. Our derivative financial instruments include cross currency swaps, forward exchange and extra option contracts, interest rate swap collar and treasury lock agreements for which fair values are based on current liquidation values. We also have over-the-counter option and swap contracts for which fair values are estimated based on quoted prices from various sources such as independent reporting services, industry publications and brokers. For positions where independent quotations are not available, an estimate is provided, or the prevailing market price at which the positions could be liquidated is used. In addition, we have NYMEX futures and options for which the fair values are based on quoted market prices.

Note 9—Major Customers and Concentration of Credit Risk

Marathon Ashland Petroleum accounted for 12%, 10% and 11% of our revenues for each of the three years in the period ended December 31, 2003. No other customers accounted for 10% or more of our revenues during any of the three years. The majority of the revenues from Marathon Ashland Petroleum pertain to our gathering, marketing, terminalling and storage operations. We believe that the loss of this customer would have only a short-term impact on our operating results. There can be no assurance, however, that we would be able to identify and access a replacement market at comparable margins.

Financial instruments that potentially subject us to concentrations of credit risk consist principally of trade receivables. Our accounts receivable are primarily from purchasers and shippers of crude oil. This industry concentration has the potential to impact our overall exposure to credit risk, either positively or negatively, in that the customers may be similarly affected by changes in economic, industry or other conditions. We review credit exposure and financial information of our counterparties and generally require letters of credit for receivables from customers that are not considered credit worthy, unless the credit risk can otherwise be reduced (see Note 5).

Note 10—Related Party Transactions

Reimbursement of Expenses of Our General Partner and Its Affiliates

We do not directly employ any persons to manage or operate our business. These functions are provided by employees of our general partner (or, in the case of our Canadian operations, PMC (Nova Scotia) Company). Our general partner does not receive a management fee or other compensation in connection with its management of us. We reimburse our general partner for all direct and indirect costs of services provided, 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. Our agreement provides that our general partner will determine the expenses allocable to us in any reasonable manner determined by our general partner in its sole discretion. Historically, an allocation was made for overhead associated with officers and employees who divided time between us and Plains Resources. As a result of the General Partner Transition, all of the employees and officers of the general partner devote 100% of their efforts to our business and there are no allocated expenses. Total costs reimbursed by us to our general partner in for the years ended December 31, 2003, 2002 and 2001 were approximately $88.1 million, $70.8 million and $31.3 million, respectively. Total costs reimbursed by us to our former general partner and Plains Resources were approximately $31.2 million for the year ended December 31, 2001.

Crude Oil Marketing Agreement

We are the exclusive marketer/purchaser for all of Plains Resources' and its subsidiaries' equity crude oil production. The marketing agreement with Plains Resources provides that we will purchase for resale at market prices the majority of Plains Resources' crude oil production for which we charge a

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fee of $0.20 per barrel. This fee is subject to adjustment every three years based on then-existing market conditions. For the years ended December 31, 2003, 2002 and 2001, we paid Plains Resources approximately $25.7 million, $247.7 million and $223.2 million, respectively, for the purchase of crude oil under the agreement, including the royalty share of production, and recognized margins of approximately $0.2 million, $1.8 million and $1.8 million from the marketing fee for the same periods, respectively. In our opinion, these purchases were made at prevailing market prices. In November 2001, the marketing agreement automatically extended for an additional three-year period. In connection with the separation of Plains Resources and one of its subsidiaries, discussed below, Plains Resources divested the bulk of its producing properties. As a result, we do not anticipate the marketing arrangement with Plains Resources to be material to our operating results in the future. We are in the process of negotiating an amended agreement to reflect the separation. As currently in effect, the marketing agreement will terminate upon a "change in control" of Plains Resources or our general partner. The recently announced buyout of Plains Resources stock would constitute a change of control; however, we received assurances prior to the initial announcement that neither Plains Resources nor the buyout group intend for the agreement to terminate.

In December 2002, Plains Resources completed a spin-off of one of its subsidiaries, Plains Exploration and Production Company ("PXP") to its shareholders. PXP is a successor participant to the Plains Resources Marketing agreement. For the year ended December 31, 2003, we paid PXP approximately $277.9 million for the purchase of crude oil under the agreement, including the royalty share of production and recognized margins of approximately $1.7 million from the marketing fee. In our opinion, these purchases were made at prevailing market prices. We are also party to a Letter Agreement with Stocker Resources, L.P. (now PXP) that provides that if the Marketing Agreement terminates before our crude oil sales agreement with Tosco Refining Co. ("Tosco") terminates, PXP will continue to sell and we will continue to purchase PXP's equity crude oil production from the Arroyo Grande field (now owned by a subsidiary of PXP) under the same terms as the Marketing Agreement until our Tosco sales agreement terminates. We are in the process of negotiating the terms of an amended agreement with PXP.

Separation Agreement

A separation agreement was entered into in connection with the General Partner Transition pursuant to which (i) Plains Resources has indemnified us for (a) claims relating to securities laws or regulations in connection with the upstream or midstream businesses, based on alleged acts or omissions occurring on or prior to June 8, 2001 or (b) claims related to the upstream business, whenever arising, and (ii) we have indemnified Plains Resources for claims related to the midstream business, whenever arising. Plains Resources also has agreed to indemnify and maintain liability insurance for the individuals who were, on or before June 8, 2001, directors or officers of Plains Resources or our former general partner.

Due to Related Parties

The balance of amounts due to related parties at December 31, 2003 and 2002 was $27.0 million and $23.3 million, respectively, and was primarily related to crude oil purchased by us but not yet paid as of December 31 of each year.

Transaction Grant Agreements

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the remainder in 2001. The value of the units and associated distribution equivalent rights that vested under the Transaction Grant Agreements for all grantees in 2001 were $5.7 million. Although we recorded noncash compensation expenses with respect to these vestings, the compensation expense incurred in connection with these grants was funded by our former general partner, without reimbursement by us.

Performance Option Plan

In connection with the General Partner Transition, 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 375,000 units have been granted. These options vest in 25% increments based upon achieving quarterly distribution levels on our units of $0.525, $0.575, $0.625 and $0.675 ($2.10, $2.30, $2.50 and $2.70, annualized). The first such level was reached, and 25% of the options vested, in 2002. The options will vest in their entirety immediately upon a change in control (as defined in the grant agreements). The original purchase price under the options is $22 per subordinated unit, declining over time in an amount equal to 80% of each quarterly distribution per unit. As of February 17, 2004, the purchase price was $17.30 per unit. The terms of future grants may differ from the existing grants. Because the units underlying the plan were contributed to the general partner, we will have no obligation to reimburse the general partner for the cost of the units upon exercise of the options. At December 31, 2003 approximately 371,875 units were outstanding following the exercise of 3,125 options during 2003.

Stock Option Replacement

In connection with the General Partner Transition, certain members of the management team that had been employed by Plains Resources were transferred to the general partner. At that time, such individuals held in-the-money but unvested stock options in Plains Resources, which were subject to forfeiture because of the transfer of employment. Plains Resources, through its affiliates, agreed to substitute a contingent grant of subordinated units (or common units after conversion) with a value equal to the spread on the unvested options, with distribution equivalent rights from the date of grant. The units vest on the same schedule as the stock options would have vested. The general partner administers the vesting and delivery of the units under the grants. Because the units necessary to satisfy the delivery requirements under the grants are provided by Plains Resources, we have no obligation to reimburse the general partner for the cost of such units.

Benefit Plan

A subsidiary of Plains Resources was, until June 8, 2001, our general partner. On that date, such entity transferred the general partner interest to our current general partner, which effective July 1, 2001, maintains a 401(k) defined contribution plan whereby it matches 100% of an employee's contribution (subject to certain limitations in the plan). For the years ended December 31, 2003 and 2002, the defined contribution plan expense was approximately $2.6 million and $2.1 million, respectively. For the period July 1 through December 31, 2001, defined contribution plan expense was approximately $1.1 million.

Prior to July 1, 2001, Plains Resources maintained a 401(k) defined contribution plan whereby it matched 100% of an employee's contribution (subject to certain limitations in the plan), with matching contributions being made 50% in cash and 50% in common stock of Plains Resources (the number of shares for the stock match being based on the market value of the common stock at the time the shares were granted). For the period January 1 through June 30, 2001, defined contribution plan expense was $1.0 million.

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Note 11—Long-Term Incentive Plans

Our general partner has adopted the Plains All American GP LLC 1998 Long-Term Incentive Plan (the "LTIP") for employees and directors of our general partner and its affiliates who perform services for us. The LTIP consists of two components, a restricted ("phantom") unit plan and a unit option plan. The LTIP currently permits the grant of phantom units and unit options covering an aggregate of 1,425,000 common units. The plan is administered by the Compensation Committee of our general partner's board of directors. Our general partner's board of directors in its discretion may terminate the LTIP at any time with respect to any common units for which a grant has not yet been made. Our general partner's board of directors also has the right to alter or amend the LTIP or any part of the plan from time to time, including, subject to any applicable NYSE listing requirements, increasing the number of common units with respect to which awards may be granted; provided, however, that no change in any outstanding grant may be made that would materially impair the rights of the participant without the consent of such participant.

Restricted Unit Plan. A restricted unit is a "phantom" unit that entitles the grantee to receive, upon the vesting of the phantom unit, a common unit (or cash equivalent, depending on the terms of the grant). As of December 31, 2003, aggregate outstanding grants of approximately 1,003,000 have been made to employees, officers and directors of our general partner. As discussed in more detail below, a substantial number of phantom units have recently vested or are expected to vest in the first half of 2004. As of February 17, 2004, giving effect to vested grants, grants of approximately 684,000 unvested phantom units remain outstanding to employees, officers and directors of our general partner. As discussed below, a substantial portion of these phantom units are expected to vest in May 2004. The Compensation Committee may, in the future, make additional grants under the plan to employees and directors containing such terms as the Compensation Committee shall determine.

If a grantee terminates employment or membership on the board for any reason, the grantee's phantom units will be automatically forfeited unless, and to the extent, the Compensation Committee provides otherwise. Common units to be delivered upon the vesting of rights may be common units acquired by our general partner in the open market or in private transactions, common units already owned by our general partner, or any combination of the foregoing. Our general partner will be entitled to reimbursement by us for the cost incurred in acquiring common units. In addition, the Partnership may issue up to 975,000 new common units to satisfy delivery obligations under the grants, less any common units issued upon exercise of unit options under the plan (see below). If we issue new common units upon vesting of the phantom units, the total number of common units outstanding will increase. The Compensation Committee, in its discretion, may grant tandem distribution equivalent rights with respect to phantom units.

The phantom units (other than director grants) granted during the subordination period were subject to the basic restriction that vesting could take place only after and in proportion to any conversion of subordinated units into common units. Certain grants were subject to additional vesting criteria, primarily related to the Partnership's performance. In November 2003, 25% of the outstanding subordinated units converted on a one-for-one basis into common units and the remainder of our subordinated units converted into common units in February 2004. As a result, approximately 35,000 phantom units vested in November 2003, approximately 326,000 phantom units vested in February 2004, and we anticipate that approximately 473,000 additional phantom units will vest in May 2004, subject to the satisfaction of service period requirements. Under generally accepted accounting principles, we are required to recognize an expense when it is considered probable that the financial tests for conversion of subordinated units and required distribution levels will be met and that the phantom units will vest. As of December 31, 2003, we had recorded approximately $28.8 million of compensation expense for the units that vested during 2003 and those that we concluded probable of vesting during 2004. The compensation expense recorded is based upon the actual amounts paid in 2003, or for the unpaid

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portion, an estimated market price of $33.35 per unit, our share of employment taxes and other related costs.

During 2003, we paid cash in lieu of issuing units for approximately 7,500 of the phantom units that vested during the year and issued approximately 18,000 common units (after netting for taxes). For those units that vested in February 2004, we paid cash in lieu of issuing units for approximately 104,000 of the phantom units and issued approximately 138,000 new common units (after netting for taxes) in connection with such vesting. We anticipate paying cash for approximately 201,000 of the phantom units expected to vest in May 2004, as well as issuing approximately 181,000 new common units (after netting for taxes) in connection with such vesting.

The issuance of the common units pursuant to the restricted unit plan is primarily intended to serve as a means of incentive compensation for performance. Therefore, no consideration will be paid to us by the plan participants upon receipt of the common units.

In 2000, the three non-employee directors of our former general partner were each granted 5,000 phantom units. These units vested in connection with the consummation of the General Partner Transition. Additional grants of 5,000 phantom units were made in 2002 to each non-employee director of our general partner. These units vest in 25% increments on each anniversary of June 8, 2001. The first vesting took place on June 8, 2002.

Unit Option Plan. The Unit Option Plan under our Long-Term Incentive Plan currently permits the grant of options covering common units. No grants have been made under the Unit Option Plan to date. However, the Compensation Committee may, in the future, make grants under the plan to employees and directors containing such terms as the committee shall determine, provided that unit options have an exercise price equal to the fair market value of the units on the date of grant.

Note 12—Commitments and Contingencies

We lease certain real property, equipment and operating facilities under various operating leases. We also incur costs associated with leased land, rights-of-way, permits and regulatory fees, the contracts for which generally extend beyond one year but can be cancelled at any time should they not be required for operations. Future non-cancellable commitments related to these items at December 31, 2003, are summarized below (in millions):

2004	$	12.7
2005	$	11.2
2006	$	8.8
2007	$	5.3
2008	$	2.8
Thereafter	$	0.7

Total lease expense incurred for 2003, 2002 and 2001 was $10.5 million, $8.3 million and $7.4 million, respectively. As is common within the industry and in the ordinary course of business, we have also entered into various operational commitments and agreements related to pipeline operations and to marketing, transportation, terminalling and storage of crude oil and LPG.

Litigation

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authorized amounts is a violation of the EAR. On October 18, 2002, we submitted to the BIS an initial notification of voluntary disclosure. The BIS subsequently informed us that we could continue to export while previous exports were under review. We applied for and have received a new license allowing for exports of volumes more than adequately reflecting our anticipated needs. On October 2, 2003, we submitted additional information to the BIS. At this time, we have received no indication whether the BIS intends to charge us with a violation of the EAR or, if so, what penalties would be assessed. As a result, we cannot estimate the ultimate impact of this matter.

Alfons Sperber v. Plains Resources Inc., et. al. On December 18, 2003, a putative class action lawsuit was filed in the Delaware Chancery Court, New Castle County, entitled Alfons Sperber v. Plains Resources Inc., et al. This suit, brought on behalf of a putative class of Plains All American Pipeline, L.P. common unit holders, asserts breach of fiduciary duty and breach of contract claims against the Partnership, Plains AAP, L.P., and Plains All American GP LLC and its directors, as well as breach of fiduciary duty claims against Plains Resources Inc. and its directors. The complaint seeks to enjoin or rescind a proposed acquisition of all of the outstanding stock of Plains Resources Inc., as well as declaratory relief, an accounting, disgorgement and the imposition of a constructive trust, and an award of damages, fees, expenses and costs, among other things. The Partnership intends to vigorously defend this lawsuit.

Other Litigation. We, in the ordinary course of business, are a claimant and/or a defendant in various other legal proceedings. We do not believe that the outcome of these other legal proceedings, individually and in the aggregate, will have a materially adverse effect on our financial condition, results of operations or cash flows.

Other

The occurrence of a significant event not fully insured or indemnified against, or the failure of a party to meet its indemnification obligations, could materially and adversely affect our operations and financial condition. We believe that we are adequately insured for public liability and property damage to others with respect to our operations. With respect to all of our coverage, no assurance can be given that we will be able to maintain adequate insurance in the future at rates we consider reasonable.

Note 13—Environmental Remediation

In connection with various acquisitions, we have received indemnities from the sellers for environmental exposure, subject to our prior payment of certain threshold amounts. Based on our investigations of the assets acquired in such acquisitions, we have identified several sites that exceed the threshold limitations under the various indemnities. Although we have not yet determined the total cost of remediation of these sites, we believe our indemnification arrangements should prevent such costs from having a material adverse effect on our financial condition, results of operations or cash flows.

In connection with our 1999 acquisition of Scurlock Permian LLC from MAP, we were indemnified by MAP for any environmental liabilities attributable to Scurlock's business or properties which occurred prior to the date of the closing of the acquisition. This indemnity applied to claims that exceeded $25,000 individually and $1.0 million in the aggregate. For the indemnity to apply, we were required to assert any claims on or before May 15, 2003. In conjunction with the expiration of this indemnity, we reached agreement with respect to MAP's remaining indemnity obligations. Under the terms of this agreement, MAP will continue to remain obligated for liabilities associated with two

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Superfund sites at which it is alleged that Scurlock Permian deposited waste oils. In addition, MAP paid us $4.6 million cash as satisfaction of its obligations with respect to other sites. During 2002, we had reassessed previous investigations and completed environmental studies related to environmental conditions associated with our 1999 acquisitions. As a result of that reassessment, we established an additional reserve of $1.2 million.

As of December 31, 2003, we have approximately $6.6 million reserved associated with our remediation obligations. This amount is approximately equal to the threshold amounts the partnership must incur before the sellers' indemnities take effect. Approximately $1.6 million of our environmental reserve is classified as current and $5.0 million is classified as long-term because in many cases, the actual cash expenditures may not occur for up to ten years or more.

Other assets we have acquired or will acquire in the future may have environmental remediation liabilities for which we are not indemnified. We may experience future releases of crude oil into the environment from our pipeline and storage operations, or discover releases that were previously unidentified. Although we maintain an extensive inspection program designed to prevent and, as applicable, to detect and address such releases promptly, damages and liabilities incurred due to any future environmental releases from our assets may substantially affect our business.

Note 14—Quarterly Financial Data (Unaudited):

	First Quarter		Second Quarter		Third Quarter		Fourth Quarter			Total⁽¹⁾
	(in millions, except per unit data)
*2003*
Revenues	$	3,281.9	$	2,709.2	$	3,053.7	$	3,545.0		$	12,589.8
Gross margin		46.7		44.0		38.7		41.2			170.6
Operating income		33.6		31.9		21.0		11.6			98.2
Net income (loss)		24.4		23.4		11.9		(0.2	)		59.4
Basic net income (loss) per limited partner unit		0.46		0.42		0.20		(0.03	)		1.01
Diluted net income (loss) per limited partner unit		0.46		0.42		0.19		(0.03	)		1.00
Cash distributions per common unit⁽²⁾	$	0.550	$	0.550	$	0.550	$	0.563		$	2.21
*2002*
Revenues	$	1,545.3	$	1,985.3	$	2,344.1	$	2,509.5		$	8,384.2
Gross margin		31.4		34.5		35.3		39.0			140.2
Operating income		20.8		23.4		23.8		26.7			94.6
Net income		14.3		17.0		16.3		17.7			65.3
Basic and diluted net income per limited partner unit		0.31		0.37		0.33		0.33			1.34
Cash distributions per common unit⁽²⁾	$	0.525	$	0.538	$	0.538	$	0.538		$	2.14

⁽¹⁾: The sum of the four quarters may not equal the total year due to rounding.
⁽²⁾: Represents cash distributions declared per common unit for the period indicated. Distributions were paid in the following calendar quarter.

Note 15—Operating Segments

Our operations consist of two operating segments: (1) Pipeline Operations—engages in interstate and intrastate crude oil pipeline transportation and certain related merchant activities; (2) Gathering, Marketing, Terminalling and Storage Operations—engages in purchases and resales of crude oil and LPG at various points along the distribution chain and the operation of certain terminalling and

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storage assets. We evaluate segment performance based on (i) segment profit and (ii) maintenance capital. We define segment profit as revenues less (i) purchases, (ii) field operating costs and (iii) segment general and administrative expenses. Maintenance capital consists of capital expenditures required either to maintain the existing operating capacity of partially or fully depreciated assets or to extend their useful lives. Capital expenditures made to expand our existing capacity, whether through construction or acquisition, are not considered maintenance capital expenditures. Repair and maintenance expenditures associated with existing assets that do not extend the useful life or expand the operating capacity are charged to expense as incurred. In a contango market (oil prices for future deliveries are higher than for current deliveries), we use our tankage to improve our gathering margins by storing crude oil we have purchased at lower prices in the current month for delivery at higher prices in future months. In a backwardated market (oil prices for future deliveries are lower than for current deliveries), we use and lease less storage capacity, but increased marketing margins (premiums for prompt delivery) provide an offset to this reduced cash flow. We believe that the combination of our terminalling and storage activities and gathering and marketing activities provides a counter-cyclical balance that has a stabilizing effect on our operations and cash flow. The following table reflects our results of operations for each segment for the periods indicated (note that each of the items in the following table exclude depreciation and amortization):

			Pipeline		Gathering Marketing, Terminalling & Storage		Total
			(in millions)
Twelve Months Ended December 31, 2003
Revenues:
	External Customers		$	605.1	$	11,984.7	$	12,589.8
	Intersegment^(a)			53.5		0.9		54.5

		Total revenues of reportable segments	$	658.6	$	11,985.6	$	12,644.3

Segment profit^(c)			$	81.3	$	63.1	$	144.4

Capital expenditures			$	211.9	$	21.9	$	233.8
Total assets			$	1,221.0	$	874.6	$	2,095.6
Non-cash SFAS 133 impact^(b)			$	—	$	0.4	$	0.4
Maintenance capital			$	6.4	$	1.2	$	7.6
Twelve Months Ended December 31, 2002
Revenues:
	External Customers		$	462.4	$	7,921.8	$	8,384.2
	Intersegment^(a)			23.8		—		23.8

		Total revenues of reportable segments	$	486.2	$	7,921.8	$	8,408.0

Segment profit^(c)			$	70.7	$	58.9	$	129.6

Capital expenditures			$	341.9	$	23.3	$	365.2
Total assets			$	1,030.7	$	635.9	$	1,666.6
Non-cash SFAS 133 impact^(b)			$	—	$	0.3	$	0.3
Maintenance capital			$	3.4	$	2.6	$	6.0

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Twelve Months Ended December 31, 2001
Revenues:
	External Customers		$	339.9	$	6,528.3	$	6,868.2
	Intersegment^(a)			17.5		—		17.5

		Total revenues of reportable segments	$	357.4	$	6,528.3	$	6,885.7

Segment profit^(c)			$	58.9	$	42.5	$	101.4

Capital expenditures			$	169.8	$	80.4	$	250.2
Total assets			$	472.3	$	788.9	$	1,261.2
Non-cash SFAS 133 impact^(b)			$	—	$	0.2	$	0.2
Maintenance capital			$	0.5	$	2.9	$	3.4

^(a): Intersegment sales were conducted at arms length.
^(b): Amounts related to SFAS 133 are included in revenues and impact segment profit.
^(c): The following table reconciles segment profit to consolidated net income (in millions):

	For the year ended December 31,
	2003			2002			2001
Segment profit	$	144.4		$	129.6		$	101.4
Unallocated general and administrative expenses		—			(1.0	)		(5.7	)
Depreciation and amortization		(46.8	)		(34.1	)		(24.3	)
Gain on sale of assets		0.6			—			1.0
Interest expense		(35.2	)		(29.1	)		(29.1	)
Interest income and other, net		(3.6	)		(0.1	)		0.4
Cumulative effect of accounting change		—			—			0.5

Net Income	$	59.4		$	65.3		$	44.2

Geographic Data

We have operations in the United States and Canada. Set forth below are revenues and long lived assets attributable to these geographic areas (in millions):

	For the Year Ended December 31,
Revenues	For the Year Ended December 31,
Revenues	2003		2002
United States	$	10,536.8	$	6,941.7
Canada		2,053.0		1,442.5

	$	12,589.8	$	8,384.2

	For the Year Ended December 31,
Long-Lived Assets	For the Year Ended December 31,
Long-Lived Assets	2003		2002
United States	$	1,039.8	$	866.9
Canada		316.9		194.1

	$	1,356.7	$	1,061.0

F-67

Note 16—Subsequent Events (Unaudited)

Link Acquisition. On April 1, 2004, we completed the acquisition of substantially all of the North American crude oil and pipeline operations of Link Energy LLC ("Link") for approximately $330 million, including $273 million of cash, the assumption of $49 million of liabilities and $8 million of transaction, closing and integration costs and other items. The Link crude oil business consists of approximately 7,000 miles of active crude oil pipeline and gathering systems, over 10 million barrels of crude oil storage capacity, a fleet of approximately 200 owned or leased trucks and approximately 2 million barrels of crude oil linefill and working inventory. The Link assets complement our assets in West Texas and along the Gulf Coast and allow us to expand our presence in the Rocky Mountain and Oklahoma/Kansas regions.

The acquisition was funded with cash on hand, borrowings under a new $200 million 364-day credit facility and borrowings under our existing revolving credit facilities. The new credit facility contains a twelve-month term out option, exercisable at our election, at the end of the primary term, bears interest at a rate of LIBOR plus a margin ranging from .625% to 1.25%, depending upon our credit rating, and includes essentially the same covenants as our existing credit facilities. On April 15, we completed the private placement of 3,245,700 units of Class C Common Units for $30.81 per unit to a group of institutional investors. Total proceeds from the transaction, after deducting transaction costs and including the general partner's proportionate contribution, were approximately $101 million and was used to reduce the balance outstanding under our existing revolving credit facilities. The partnership has committed to use net proceeds from future debt and equity offerings to retire or reduce the amount outstanding under the new $200 million 364-day credit facility.

On April 2, 2004, the Office of the Attorney General of Texas delivered written notice to us that it was investigating the possibility that the acquisition of Link's assets might reduce competition in one or more markets within the petroleum products industry in the State of Texas. In connection with the Link purchase, both PAA and Link completed all necessary filings required under the Hart-Scott-Rodino Act, and the required 30-day waiting period expired on March 24, 2004 without any inquiry or request for additional information from the U.S. Department of Justice or the Federal Trade Commission. Representatives from the Antitrust and Civil Medicaid Fraud Division of the Office of the Attorney General of Texas indicated their investigation was prompted by complaints received from allegedly interested industry parties regarding the potential impact on competition in the Permian Basin area of West Texas. We understand that similar complaints have been received by the Federal Trade Commission, and that, consistent with federal-state protocols for conducting joint merger investigations, appropriate federal and state antitrust authorities are coordinating their activities. We are cooperating fully with the antitrust enforcement authorities.

F-68

LINK ENERGY LLC
(A LIMITED LIABILITY COMPANY)
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(In Thousands, Except per Unit Amounts)
(Unaudited)

		Successor Company						Predecessor Company
		Three Months ended March 31, 2004			One Month ended March 31, 2003			Two Months ended February 28, 2003
					(Restated)			(Restated)
Operating Revenue		$	40,682		$	17,733		$	31,635
Cost of Sales			8,081			1,876			4,521
Operating Expenses			20,725			6,082			13,020
Depreciation and Amortization-operating			5,054			1,707			4,123

Gross Profit			6,822			8,068			9,971
Selling, General and Administrative Expenses			18,514			3,885			6,846
Depreciation and Amortization-corporate & other			6			1			519
Other (Income) Expense			(710	)		(138	)		(8	)

Operating Income (Loss)			(10,988	)		4,320			2,614
Interest Expense and Related Charges			(11,531	)		(3,301	)		(5,645	)
Interest Income			17			23			58
Other, net			(41	)		1			98

Income (Loss) from Continuing Operations Before Reorganization Items, Net Gain on Discharge of Debt, Fresh Start Adjustments and Cumulative Effect of Accounting Changes			(22,543	)		1,043			(2,875	)
Reorganization Items (Note 5)			—			—			(7,330	)
Net Gain on Discharge of Debt (Note 5)			—			—			131,560
Fresh Start Adjustments (Note 6)			—			—			(56,771	)

Income (Loss) from Continuing Operations			(22,543	)		1,043			64,584
Income (Loss) from Discontinued Operations (Note 7)			139			(6,471	)		519

Net Income (Loss) Before Cumulative Effect of Accounting Changes			(22,404	)		(5,428	)		65,103
Cumulative Effect of Accounting Changes (Note 12)			—			—			(3,976	)

Net Income (Loss)		$	(22,404	)	$	(5,428	)	$	61,127

Basic Net Income (Loss) Per Unit (Note 10) LLC Unit		$	(1.81	)	$	(0.44	)		N/A

	Common Unit	$	N/A			N/A		$	0.14

	Subordinated Unit	$	N/A			N/A		$	—

Diluted Net Income (Loss) Per Unit (Note 10)		$	(1.81	)	$	(0.44	)	$	0.10

Average Units Outstanding for Diluted Computation			12,353			12,317			27,476

The accompanying notes are an integral part of these condensed consolidated financial statements.

F-69

LINK ENERGY LLC
(A LIMITED LIABILITY COMPANY)
CONDENSED CONSOLIDATED BALANCE SHEETS
(In Thousands)
(Unaudited)

			March 31, 2004			December 31, 2003
ASSETS
Current Assets Cash and cash equivalents			$	2,929		$	2,450
	Restricted cash			3,581			6,045
	Trade and other receivables, net of allowance for doubtful accounts of $1,210 and $1,210, respectively			406,512			446,030
	Inventories			7,838			7,636
	Other			6,682			6,283
		Total current assets		427,542			468,444

Property, Plant and Equipment				277,480			278,724
	Less: Accumulated depreciation			21,114			16,214

		Net property, plant and equipment		256,366			262,510

Long-lived assets of discontinued operations				—			838
Other Assets				5,907			6,852

Total Assets			$	689,815		$	738,644

LIABILITIES AND MEMBERS' CAPITAL
	Current Liabilities Trade and other accounts payable		$	431,598		$	476,509
	Accrued taxes payable			3,964			6,700
	Term loans (Note 4)			75,000			75,000
	Commodity repurchase agreement (Note 4)			16,860			18,000
	Receivable financing (Note 4)			45,500			27,000
	Other			24,668			27,982

		Total current liabilities		597,590			631,191

Long-Term Liabilities Senior notes (Note 4)				110,052			104,451
	Other			15,607			17,399

		Total long-term liabilities		125,659			121,850

Commitments and Contingencies (Note 11)
Members' Capital (Deficit)
	Members' Capital (Deficit)			(33,434	)		(14,392	)
	Accumulated Other Comprehensive Income (Loss)			—			(5	)

	Total			(33,434	)		(14,397	)

Total Liabilities and Members' Capital			$	689,815		$	738,644

The accompanying notes are an integral part of these condensed consolidated financial statements.

F-70

LINK ENERGY LLC
(A LIMITED LIABILITY COMPANY)
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(In Thousands)
(Unaudited)

				Successor Three Months ended March 31, 2004			Company One Month ended March 31, 2003			Predecessor Company Two Months ended February 28, 2003
							(Restated)			(Restated)
CASH FLOWS FROM OPERATING ACTIVITIES
	Reconciliation of net income (loss) to net cash provided by (used in) operating activities Net income (loss)			$	(22,404	)	$	(5,428	)	$	61,127
		Depreciation and amortization			5,060			1,925			5,560
		Net unrealized change in crude oil trading activities			374			(895	)		(2,120	)
		Gains on disposal of assets			(730	)		(103	)		—
		Non-cash compensation expense			3,361			—			—
		Non-cash net gain for reorganization items and discharge of debt			—			—			(127,185	)
		Fresh start adjustments			—			—			56,771
		Changes in components of working capital—Receivables			39,518			(33,040	)		(32,177	)
			Inventories		(202	)		(5,769	)		6,757
			Other current assets		551			(3,073	)		2,428
			Trade accounts payable		(41,655	)		33,067			47,845
			Accrued taxes payable		(2,736	)		883			1,717
			Other current liabilities		827			(407	)		(320	)
		Other assets and liabilities			1,231			(1,026	)		2,530

	Net Cash Provided by (Used in) Operating Activities				(16,805	)		(13,866	)		22,933

CASH FLOWS FROM INVESTING ACTIVITIES
	Proceeds from sale of property, plant and equipment				1,614			103			—
	Release of restricted cash				2,464			—			—
	Additions to property, plant and equipment				(899	)		(259	)		(285	)

	Net Cash Provided by (Used in) Investing Activities				3,179			(156	)		(285	)

CASH FLOWS FROM FINANCING ACTIVITIES
	Increase (decrease) in receivable financing				18,500			(10,000	)		—
	Decrease in repurchase agreement				(1,140	)		—			—
	Other				(3,255	)		(2,336	)		1,655

	Net Cash Provided By (Used in) Financing Activities				14,105			(12,336	)		1,655

Increase (Decrease) in Cash and Cash Equivalents					479			(26,358	)		24,303
Cash and Cash Equivalents Beginning of Period					2,450			40,735			16,432

Cash and Cash Equivalents End of Period				$	2,929		$	14,377		$	40,735

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
	Cash Paid for Interest			$	8,231		$	2,084		$	5,599

	Cash Paid for Reorganization Items			$	—		$	1,637		$	2,867

SUPPLEMENTAL NON CASH INVESTING AND FINANCING INFORMATION
	Discharge of 11% Senior Notes, including accrued interest			$	—		$	—		$	248,481
	Cancellation of additional partnership interests			$	—		$	—		$	9,318
	Issuance of 9% Senior Notes and payment of interest in kind			$	5,460		$	—		$	104,000
	Issuance of new equity of Successor Company			$	—		$	—		$	36,687

The accompanying notes are an integral part of these condensed consolidated financial statements.

F-71

LINK ENERGY LLC
(A LIMITED LIABILITY COMPANY)
CONDENSED CONSOLIDATED STATEMENTS OF MEMBERS' CAPITAL
(In Thousands)
(Unaudited)

		Members' Capital			Accumulated Other Comprehensive Income (Loss)			Total
Members' Capital (Deficit) at December 31, 2003		$	(14,392	)	$	(5	)	$	(14,397	)
	Net Loss		(22,404	)		—			(22,404	)
	Unrealized net losses on derivative instruments arising during the period		—			—			—
	Less reclassification adjustments for net realized losses on derivative instruments included in net loss		—			5			5

	Comprehensive loss								(22,399	)

	Restricted unit compensation expense		3,361			—			3,361
	Other		1			—			1

Members' Capital (Deficit) at March 31, 2004		$	(33,434	)	$	—		$	(33,434	)

The accompanying notes are an integral part of these condensed consolidated financial statements.

F-72

LINK ENERGY LLC

(A LIMITED LIABILITY COMPANY)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

1. SALE OF CRUDE OIL BUSINESS

On April 1, 2004, Link Energy LLC ("Link LLC") sold all of its crude oil marketing, pipeline and trucking transportation business, which constitutes all of Link LLC's remaining operations, to Plains All American Pipeline, L.P. ("Plains"). As a part of such sale, we agreed to settle all outstanding litigation with Texas New Mexico Pipe Line Company, a wholly owned subsidiary of Shell Pipeline Company. The $290 million proceeds from the transaction consist of approximately $273 million in cash from Plains, plus assumption of certain obligations and approximately $17 million in cash from Texas New Mexico Pipe Line Company. Under the terms of the purchase and sale agreement, an escrow of $10 million was established to provide for post-closing adjustments related to inventory and working capital. Link LLC and Plains subsequently agreed that, subject to the satisfaction of certain conditions, there would be no post closing adjustments to inventory or working capital and Link LLC and Plains would each receive one-half of the remaining escrow balance in accordance with the terms of the purchase and sale agreement.

In conjunction with this transaction, the requisite holders of Link LLC's 9% senior notes provided the necessary consents to amend the indenture effective as of the closing of the transaction, to remove substantially all of the covenants in the indenture and to provide that Plains would not be required to assume the senior notes as otherwise required by the indenture. The holders of approximately 86% of the outstanding senior notes agreed to sell their notes to us for 100% of the principal and accrued interest at the closing of the transaction. The other holders of the senior notes have been offered the right to resell their notes on the same terms. Senior noteholders that sell their notes to us on these terms will also receive their proportionate share of up to $25 million from any funds (including funds released from the escrow) that may remain after we make provision for our outstanding liabilities, obligations and contingencies. The potential premium is in exchange for the senior noteholders' waiver and modification of certain provisions of the notes, including the right to have Plains assume the notes, and approximates the premium on the notes reflected by the estimated market value if Plains had assumed the notes.

Upon the closing of the transaction, we used the proceeds of the sale to repay and redeem approximately $249 million of long and short-term debt, which included our existing credit facilities, the majority of our 9% senior notes referenced above, and other indebtedness and accrued interest. In addition, we paid transaction expenses of approximately $4.6 million. See further discussion regarding the repayment of debt in Note 4.

As a result of the closing of the transaction, we have no further operations and will wind down over a period of time. Funds released from the escrow plus remaining funds from the transaction are being used to wind down Link LLC and make provisions for any remaining liabilities or claims, and to make the additional payments described above to redeem the remaining outstanding senior notes. See discussion regarding the offer to repurchase the remaining outstanding senior notes not tendered at the closing of the transaction in Note 4.

F-73

The following is a pro-forma summary of Link LLC's net assets on April 2, 2004 (post the closing of the Plains transaction and the repayment of debt on April 1, 2004 with the net proceeds from the Plains transaction):

		(in millions)
Assets
Cash and restricted cash		$	33
Other current assets			5

	Total Assets		38

Liabilities
Trade and other payables			11
9% Senior notes			16

	Total Liabilities		27

	Net Assets	$	11

As senior noteholders that have sold their notes to us have the right to receive their proportionate share of up to $25 million of any remaining funds as previously discussed, there will not be any liquidating or other distributions to the holders of Link LLC's units.

A Special Committee of the Board of Directors of Link LLC reviewed the transaction with its financial advisor, Petrie Parkman & Company, which rendered an opinion that the Plains transaction, as summarized in its opinion, was fair from a financial point of view.

2. BASIS OF PRESENTATION

Organization

Effective October 1, 2003, EOTT Energy, LLC ("EOTT LLC") changed its name to Link Energy LLC ("Link LLC"). Link LLC is a Delaware limited liability company that was formed on November 14, 2002 to assume and continue the business formerly directly owned by EOTT Energy Partners, L.P. (the "MLP"). The MLP emerged from bankruptcy and merged into EOTT Energy Operating Limited Partnership resulting in EOTT LLC becoming the successor registrant to the MLP on March 1, 2003, the effective date of the Third Amended Joint Chapter 11 Plan of Reorganization, as supplemented ("Restructuring Plan"). We operated principally through four affiliated operating limited partnerships, Link Energy Limited Partnership, Link Energy Canada Limited Partnership, Link Energy Pipeline Limited Partnership, and EOTT Energy Liquids, L.P. (see Note 7 for information regarding the disposition of our Liquids operations), each of which is a Delaware limited partnership. Link Energy General Partner, LLC served as the general partner for our four affiliated operating limited partnerships. Until the MLP emerged from bankruptcy, EOTT Energy Corp. (the "General Partner"), a Delaware corporation and a wholly owned subsidiary of Enron Corp. ("Enron"), served as the general partner of the MLP and owned an approximate 1.98% general partner interest in the MLP. Unless the context otherwise requires, the terms "we," "our," "us," and "Link" refer to Link Energy

F-74

LLC and its four affiliated operating limited partnerships, Link Energy Finance Corp., and Link Energy General Partner, LLC (the "Subsidiary Entities"), and for periods prior to our emergence from bankruptcy in March 2003, such terms and "EOTT" refer to EOTT Energy Partners, L.P. and its sole general partner, EOTT Energy Corp., as well as the Subsidiary Entities.

Interim Financial Statements

The financial statements presented herein have been prepared by Link LLC in accordance with generally accepted accounting principles in the United States and the rules and regulations of the Securities and Exchange Commission. The financial statements presented herein have been prepared on a going concern basis as the sale of substantially all of our assets to Plains and the winding down of Link LLC occurred subsequent to the period ended March 31, 2004. Interim results are not necessarily indicative of results for a full year. The financial information included herein has been prepared without audit. The condensed consolidated balance sheet at December 31, 2003 has been derived from, but does not include all the disclosures contained in, the audited financial statements for the year ended December 31, 2003. In the opinion of management, all of these unaudited statements include all adjustments and accruals consisting only of normal recurring adjustments, except for those relating to fresh start reporting and those more fully discussed in Notes 5 and 6, which are necessary for a fair presentation of the results of the interim periods reported herein. These condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and accompanying notes included in our Annual Report on Form 10-K as amended on June 16, 2004 for the year ended December 31, 2003.

Fresh Start Reporting

As a result of the application of fresh start reporting under the American Institute of Certified Public Accountants Statement of Position No. 90-7 ("SOP 90-7"), "Financial Reporting by Entities in Reorganization Under the Bankruptcy Code," as of February 28, 2003 (the date chosen for accounting purposes), Link LLC's financial results for the one month ended March 31, 2003, and the two months ended February 28, 2003 include two different bases of accounting and accordingly, the financial condition, operating results and cash flows of the Successor Company and the Predecessor Company have been separately disclosed. For a further discussion of fresh start reporting, see Note 6. For purposes of these financial statements, references to the "Predecessor Company" are references to us for periods through February 28, 2003 (the last day of the calendar month in which we emerged from bankruptcy) and references to the "Successor Company" are references to Link LLC for periods subsequent to February 28, 2003. The Successor Company's financial statements are not comparable to the Predecessor Company's financial statements. See further discussion in Note 6.

Partnership Status

F-75

the member's interest in us and the member will be responsible for paying the income tax applicable to such membership interest. In order for us to continue to be classified as a partnership for federal income tax purposes, at least 90% of our gross income for every taxable year must consist of "qualifying income" within the meaning of the Internal Revenue Code. In 2002 and 2003, we recognized income from our settlement with Enron and discharge of indebtedness in excess of 10% of our gross income for each of those years.

We were trying to raise additional equity and we believed that we might not be able to access the capital markets without a higher degree of certainty as to our classification for federal income tax purposes. Therefore, in January 2004, we requested a private letter ruling from the Internal Revenue Service to determine either that the income from our settlement with Enron and the debt discharge income is qualifying income or that the recognition of such income should be disregarded for purposes of the qualifying income test because it was an inadvertent result of our bankruptcy. Due to the fact that the Company is no longer trying to raise equity, we retracted the private letter ruling request from the Internal Revenue Service in April 2004.

Reclassifications

Certain reclassifications have been made to prior period amounts to conform with the current period presentation.

3. RESTATEMENT OF FINANCIAL RESULTS.

As reported in our Amendment No. 1 to our Form 10-K for the year ended December 31, 2003, we have restated our prior year financial results to reflect inventory and accounts payable reconciliation adjustments in prior periods. The restatement resulted in a decrease in our net loss for the one month ended March 31, 2003 of $1.2 million and an increase in our net income for the two months ended February 28, 2003 of $0.9 million.

F-76

A summary of the effects of the restatement on reported amounts for the one month ended March 31, 2003 and the two months ended February 28, 2003 are presented below. (Amounts in thousands, except per share amounts.)

		Successor Company One Month ended March 31, 2003			Predecessor Company Two Months ended February 28, 2003
REVENUE
	As Reported	$	17,315		$	31,979
	As Restated		17,733			31,635
GROSS PROFIT
	As Reported		8,077			9,681
	As Restated		8,068			9,971
OPERATING INCOME
	As Reported		4,329			2,324
	As Restated		4,320			2,614
NET INCOME (LOSS)
	As Reported		(6,650	)		60,267
	As Restated		(5,428	)		61,127
DILUTED EARNINGS (LOSS) PER UNIT
	As Reported		(0.54	)		0.08
	As Restated		(0.44	)		0.10

4. CREDIT RESOURCES

Summary of Exit Credit Facilities, Senior Notes, and Other Debt

The tables below provide a summary of our financing arrangements as of March 31, 2004 (in millions).

		Commitment/ Face Amount		Amount Outstanding
Exit Credit Facilities:
	Letter of Credit Facility	$	260.0	$	235.9
	Trade Receivables Agreement		100.0		45.5
	Commodity Repurchase Agreement		16.9		16.9
	Term Loans		75.0		75.0
Senior Notes			114.7		110.0	⁽¹⁾
Other Debt:
	Enron Note		5.7		6.3	⁽¹⁾
	Big Warrior Note		2.4		2.2	⁽¹⁾
	Ad Valorem Tax Liability		4.5		4.5

⁽¹⁾: These notes were adjusted to fair value pursuant to the adoption of fresh start reporting required by SOP 90-7.

F-77

On April 1, 2004, we utilized net proceeds from the sale of the crude oil business to Plains to repay the following debt outstanding and related accrued interest at March 31, 2004 (in millions):

Trade Receivables Agreement		$	45.5
Commodity Repurchase Agreement			16.9
Term Loans			75.0
Senior Notes			99.0
Enron Note			5.7
Big Warrior Note			2.4

	Total principal		244.5
	Interest		4.6

	Total principal and interest paid	$	249.1

The outstanding letters of credit and the ad valorem liability were assumed by Plains in connection with the sale of the crude oil business.

Subsequent to the sale of the crude oil business, we offered to repurchase the remaining senior notes not redeemed on April 1 (approximately $15.7 million) for 101% of the principal amount plus any accrued and unpaid interest thereon to the payment date. As of June 14, 2004, we have only $0.1 million of senior notes outstanding.

5. BANKRUPTCY PROCEEDINGS AND RESTRUCTURING PLAN

On October 8, 2002, the MLP and the Subsidiary Entities filed pre-negotiated voluntary petitions for reorganization under Chapter 11 of the United States Bankruptcy Code (the "EOTT Bankruptcy"). The filing was made in the United States Bankruptcy Court for the Southern District of Texas, Corpus Christi Division (the "EOTT Bankruptcy Court"). Additionally, the General Partner filed a voluntary petition for reorganization under Chapter 11 on October 21, 2002 in the EOTT Bankruptcy Court in order to join in the voluntary, pre-negotiated Restructuring Plan. On October 24, 2002, the EOTT Bankruptcy Court administratively consolidated, for distribution purposes, the General Partner's bankruptcy filing with the previously filed cases. The EOTT Bankruptcy Court confirmed our Restructuring Plan on February 18, 2003, and it became effective March 1, 2003. We filed a motion closing the bankruptcy case on April 14, 2004, and the order closing the case was entered on June 2, 2004.

F-78

The following reorganization items and net gain on discharge of debt, which were specifically related to the EOTT Bankruptcy, were recorded during the two months ended February 28, 2003, (in thousands):

Reorganization items—legal and professional fees		$	(7,330	)
Net gain on discharge of 11% senior notes, related accrued interest and other debt⁽¹⁾		$	131,560

⁽¹⁾: The gain on discharge of debt was recorded net of the 9% senior notes and limited liability company units issued to the creditors upon emergence from bankruptcy.

6. FRESH START REPORTING

As previously discussed, our Consolidated Financial Statements reflect the adoption of fresh start reporting required by SOP 90-7 for periods subsequent to our emergence from bankruptcy. In accordance with the principles of fresh start reporting, we have adjusted our assets and liabilities to their fair values as of February 28, 2003. The net effect of the fresh start reporting adjustments was a loss of $56.8 million, which is reflected in the results of operations of the Predecessor Company for the two months ended February 28, 2003.

F-79

The effects of the reorganization pursuant to the Restructuring Plan and the application of fresh start reporting on the Predecessor Company's consolidated balance sheet as of February 28, 2003 are as follows (in thousands):

		Predecessor Company February 28, 2003			Debt Discharge and Reclass Adjustments			Fresh Start Adjustments			Successor Company February 28, 2003
		(Restated)									(Restated)
Assets
Current Assets
Cash and cash equivalents		$	40,735		$	—		$	—		$	40,735
Trade and other receivables			439,361			—			—			439,361
Inventories			25,525			—			750(g	)		26,275
Other			12,911			—			(2,021	)^(h)		10,890

	Total current assets		518,532			—			(1,271	)		517,261

Property, Plant and Equipment, at cost			598,633			—			(267,654	)⁽ⁱ⁾		330,979
Less: Accumulated depreciation			223,188			—			(223,188	)⁽ⁱ⁾		—

	Net property, plant and equipment		375,445			—			(44,466	)		330,979

Goodwill			7,436			—			(7,436	)^(j)		—

Other Assets			10,762			—			(2,880	)^(h)		7,882

	Total Assets	$	912,175		$	—		$	(56,053	)	$	856,122

Liabilities and Members'/Partners' Capital
Current Liabilities
	Trade and other accounts payable	$	451,873		$	17,406	^(a)	$	—		$	469,279
Accrued taxes payable			13,045			(8,307	)^(b)		—			4,738
Term loans			75,000			(75,000	)^(c)		—			—
Repurchase agreement			75,000			(75,000	)^(c)		—			—
Receivable financing			50,000			—			—			50,000
Other			19,226			2,815	^(a)(b)		318	^(k)		22,359

	Total current liabilities		684,144			(138,086	)		318			546,376

Long-Term Liabilities
9% Senior Notes			—			98,800	^(d)		—			98,800
Term loans			—			75,000	^(c)		—			75,000
Repurchase agreement			—			75,000	^(c)		—			75,000
Ad valorem tax liability			—			6,992	^(b)		—			6,992
Other			17,781			—			400	^(k)		18,181

	Total long-term liabilities		17,781			255,792			400			273,973

Liabilities Subject to Compromise			284,843			(284,843	)^(a)		—			—
Additional Partnership Interests			9,318			(9,318	)^(e)		—			—
Members'/Partners' Capital (Deficit)			(83,911	)		176,455	^(f)		(56,771	)		35,773

	Total Liabilities and Members'/Partners' Capital	$	912,175		$	—		$	(56,053	)	$	856,122

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Notes:

^(a): Liabilities subject to compromise have been adjusted to reflect the settlement of the claims and discharge of the 11% senior notes and related accrued interest in connection with the Restructuring Plan.
^(b): To reclassify current and long-term amounts due to taxing authorities for accrued but unpaid ad valorem taxes in connection with the Restructuring Plan.
^(c): To reflect the refinancing on a long-term basis of amounts outstanding under the Debtor-in-Possession Financing Facilities.
^(d): To reflect the issuance of 9% senior unsecured notes (face amount of $104 million) to all former senior note holders and general unsecured creditors with allowed claims in connection with the Restructuring Plan, recorded at fair value.
^(e): To reflect the cancellation of the additional partnership interests in connection with the Restructuring Plan.
^(f): To reflect the issuance of limited liability company units pursuant to the Restructuring Plan and the net gain on extinguishment of debt.
^(g): To adjust inventory to fair value.
^(h): To reflect the elimination of deferred turnaround costs, which are included in the fair value of property, plant and equipment of the Successor Company.
⁽ⁱ⁾: To adjust property, plant, and equipment to fair value.
^(j): To reflect the elimination of goodwill resulting from the fair value allocation.
^(k): To reflect the Enron and Big Warrior notes at fair value.

7. DISCONTINUED OPERATIONS

West Coast Assets

Effective October 1, 2003, we sold all of the assets comprising our natural gas gathering, processing, natural gas liquids fractionation, storage and related trucking and distribution facilities located on the West Coast.

Revenues and results of operations for the West Coast operating segment for the three months ended March 31, 2004, the one month ended March 31, 2003 and the two months ended February 28,

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2003, are shown below (in thousands). We did not allocate any interest expense to the West Coast discontinued operations for any of the periods presented below.

	Successor Company				Predecessor Company
	Three Months ended March 31, 2004		One Month ended March 31, 2003		Two Months ended February 28, 2003
Revenues	$	—	$	2,934	$	5,571

Income (loss) from discontinued operations	$	—	$	248	$	395

Liquids Operations

Effective December 31, 2003, we sold all of our remaining natural gas liquids assets for approximately $20 million, plus inventory value. The assets included our underground salt dome storage facility and related pipeline grid near Mont Belvieu, Texas as well as our processing facility and former methyl tertiary butyl ether ("MTBE") plant at Morgan's Point, near La Porte, Texas.

Revenues and results of operations for the Liquids Operations for the three months ended March 31, 2004, the one month ended March 31, 2003 and the two months ended February 28, 2003 are shown below (in thousands). We did not allocate any interest expense to the Liquids discontinued operations for any periods presented below.

	Successor Company					Predecessor Company
	Three Months ended March 31, 2004		One Month ended March 31, 2003			Two Months ended February 28, 2003
			(Restated)			(Restated)
Revenues	$	—	$	8,525		$	40,337

Income (loss) from discontinued operations	$	139	$	(6,719	)	$	124

8. INVENTORY

In connection with the sale of the crude oil business to Plains on April 1, 2004, Link LLC personnel, accompanied by Plains representatives, completed a comprehensive physical measurement of all crude oil volumes held by Link LLC in its pipelines and storage tanks. The measurement process was completed as of March 31, 2004. The results of the measurement process identified approximately 70,000 barrels of crude oil tank bottoms that were previously classified as merchantable crude oil inventory. Storage tank bottoms include sediment, water or non-merchantable paraffin that accumulate at the bottom of the tank. A charge of $2.1 million was recorded to cost of sales in the three months ended March 31, 2004 to reflect the write-down of our inventory.

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9. CAPITAL

The following is a rollforward of LLC units and warrants outstanding:

		LLC Units	Warrants
Outstanding at December 31, 2003		13,182,889	922,432
	Exercise of warrants	26	(26	)
	Change in restricted units outstanding	25,000	—

Outstanding at March 31, 2004		13,207,915	922,406

Under the Link LLC Equity Incentive Plan ("Incentive Plan") adopted in June 2003, 1.2 million restricted units were authorized to be issued to certain key employees and directors. The Incentive Plan had a ten-year term and restricted unit awards granted thereunder typically vested over a three-year period. We have recorded non-cash compensation expense of $3.5 million related to the Incentive Plan for the three months ended March 31, 2004. The following table sets forth the Incentive Plan activity for the three months ended March 31, 2004:

		Number of Restricted Units
Outstanding at December 31, 2003		830,000
	Granted	35,000
	Forfeited	(10,000	)

Outstanding at March 31, 2004		855,000

In March 2004, the Company agreed to repurchase 105,000 restricted units for $4,000. As a result, we accelerated the recognition of non-cash compensation expense of approximately $1.0 million, which is included in the $3.5 million of total non-cash compensation expense discussed above.

In connection with the sale of our crude oil business to Plains on April 1, 2004, officers and certain key employees signed a settlement and release agreement in connection with consideration received under change in control agreements. The settlement and release agreement required, among other things, the relinquishment of the remaining 750,000 restricted units.

10. EARNINGS PER UNIT

Basic earnings per unit include the weighted average impact of outstanding units (i.e., it excludes unit equivalents). Diluted earnings per unit consider the impact of all potentially dilutive securities.

Successor Company

Basic and diluted net loss per unit for the Successor Company were $1.81 for the three months ended March 31, 2004 and $0.44 per unit (as restated) for the one month ended March 31, 2003. Outstanding warrants and restricted units were determined to be antidilutive and are not included in the computation of fully diluted earnings per unit. For the three months ended March 31, 2004, basic and diluted net loss per unit from continuing operations were $1.82 and basic and diluted net income

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per unit for discontinued operations were $0.01. For the one month ended March 31, 2003, basic and diluted net income per unit from continuing operations were $0.08 and basic and diluted net loss per unit from discontinued operations were $0.52.

Predecessor Company

Total and per unit information related to income (loss) from continuing operations, discontinued operations, the cumulative effect of an accounting change and net income (loss) for the Predecessor Company is shown in the table below. All amounts exclude amounts allocated to the General Partner (in thousands, except per unit amounts):

	Two Months ended February 28, 2003 (Restated)
	Basic⁽¹⁾
	Common				Subordinated				Diluted
	Income (Loss)		Per Unit		Income Loss		Per Unit		Income (Loss)		Per Unit
Income (Loss) from Continuing Operations	$	2,133	$	0.11	$	—	$	—	$	2,133	$	0.08
Income (Loss) from Discontinued Operations⁽²⁾		519		0.03		—		—		519		0.02
Cumulative Effect of Accounting Changes⁽³⁾		—		—		—		—		—		—

Net Income (Loss)	$	2,652	$	0.14	$	—	$	—	$	2,652	$	0.10

Weighted Average Units Outstanding				18,476				9,000				27,476

⁽¹⁾: Net income (loss), excluding the approximate two percent General Partner interest, has been apportioned to each class of unitholder based on the ownership of total units outstanding in accordance with the MLP's Partnership Agreement. Net losses are not allocated to the common and subordinated unitholders to the extent that such allocations would cause a deficit capital account balance or increase any existing deficit capital account balance. Any remaining losses are allocated to the General Partner as a result of the balances in the capital accounts of the common and subordinated unitholders. Effective with the third quarter of 2002, all losses were being allocated to the General Partner. The disproportionate allocation of 2002 net losses among the unitholders and the General Partner was recouped during the two months ended February 28, 2003.
⁽²⁾: Earnings (loss) per unit from discontinued operations has been determined based on the difference between the amount of net income (loss) allocated to each class of unitholder and the amount of income (loss) from continuing operations allocated to each class of unitholder. Earnings (loss) per unit for the two months ended February 28, 2003, have been impacted by the disproportionate allocation of income and loss discussed above.
⁽³⁾: The cumulative effect of accounting changes was allocated to the General Partner and subsequently recouped by the General Partner during the two months ended February 28, 2003.

11. COMMITMENTS AND CONTINGENCIES

Litigation. We are, in the ordinary course of business, a defendant in various lawsuits, some of which are covered in whole or in part by insurance. We believe that the ultimate resolution of litigation, individually and in the aggregate, will not have a materially adverse impact on our financial position or results of operations. Prior to and since the commencement of our bankruptcy proceedings, various legal actions arose in the ordinary course of business, of which the significant actions are discussed below.

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John H. Roam, et al. vs. Texas-New Mexico Pipe Line Company and EOTT Energy Pipeline Limited Partnership, Cause No. CV43296, In the District Court of Midland County, Texas, 238th Judicial District (Kniffen Estates Suit). The Kniffen Estates Suit was filed on March 2, 2001, by certain residents of the Kniffen Estates, a residential subdivision located outside of Midland, Texas. The allegations in the petition state that free crude oil products were discovered in water wells in the Kniffen Estates area, on or about October 3, 2000. The plaintiffs claim that the crude oil products are from a 1992 release from a pipeline then owned by the Texas-New Mexico Pipe Line Company ("Tex-New Mex"). We purchased that pipeline from Tex-New Mex in 1999. With respect to us, the plaintiffs were seeking damages arising from any contamination of the soil or groundwater since we acquired the pipeline in question. No specific amount of money damages was claimed in the Kniffen Estates Suit, but the plaintiffs did file proofs of claim in our bankruptcy proceeding totaling $62 million. In response to the Kniffen Estates Suit, we filed a cross-claim against Tex-New Mex. In the cross-claim, we claimed that, in relation to the matters alleged by the plaintiffs, Tex-New Mex breached the Purchase and Sale Agreement between the parties dated May 1, 1999, by failing to disclose the 1992 release and by failing to undertake the defense and handling of the toxic tort claims, fair market value claims, and remediation claims arising from the release. On April 5, 2002, we filed an amended cross-claim which alleged that Tex-New Mex defrauded us as part of Tex-New Mex's sale of the pipeline systems to us in 1999. The amended cross-claim also alleged that various practices employed by Tex-New Mex in the operation of its pipelines constituted gross negligence and willful misconduct and voided our obligation to indemnify Tex-New Mex for remediation of releases that occurred prior to May 1, 1999. In the Purchase and Sale Agreement, we agreed to indemnify Tex-New Mex only for certain remediation obligations that arose before May 1, 1999, unless these obligations were the result of the gross negligence or willful misconduct of Tex-New Mex prior to May 1, 1999. EOTT Energy Pipeline Limited Partnership ("PLP") and the plaintiffs agreed to a settlement during our bankruptcy proceedings. The settlement provides for the plaintiffs' release of their claims filed against PLP in this proceeding and in the bankruptcy proceedings, in exchange for an allowed general unsecured claim in our bankruptcy of $3,252,800 (as described above, the plaintiffs filed proofs of claim in our bankruptcy proceedings totaling $62 million). The allowed general unsecured claim was accrued at December 31, 2002. On April 1, 2003, we filed a second amended cross-claim in this matter. In addition to the claims filed in the previous cross-claims, we requested (i) injunctive relief for Tex-New Mex's refusal to honor its indemnity obligations; (ii) injunctive relief requiring Tex-New Mex to identify, investigate and remediate sites where the conduct alleged in our cross-claim occurred; and (iii) restitution damages of over $125,000,000. At a hearing on April 11, 2003, the court severed into a separate action EOTT's cross-claims against Tex-New Mex that extend beyond the crude oil release and groundwater contamination in the Kniffen Estates subdivision ("EOTT's Over-Arching Claim"). Developments in EOTT's Over-Arching Claim are described immediately below. The trial of EOTT's Kniffen Claims commenced on June 16, 2003, and the jury returned its verdict on July 2, 2003. The jury found that Tex-New Mex's gross negligence and willful misconduct caused the contamination in the Kniffen Estates. The jury also found that Tex-New Mex committed fraud against us with respect to the Kniffen Estates site. On November 28, 2003, the court the final judgment which provides for the award to us of (i) actual damages in the amount of $7,701,938, (ii) attorney's fees in the amount of $1,400,000, (iii) prejudgment interest in the amount of $1,044,509 and (iv) punitive damages in the amount of $18,203,876. The final judgment also contains a finding that Tex-New Mex is obligated to indemnify us for future remediation

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costs incurred at the Kniffen Estates site. On March 31, 2004, we entered into a settlement agreement with Tex-New Mex that resolves this lawsuit, EOTT's Over-Arching Claim, and the litigation with Jimmie T. Cooper and Betty P. Cooper that is described below. Pursuant to the terms of the settlement, we received cash payments totaling $25 million ($17 million from Tex-New Mex and the remainder as part of the proceeds received in the Plains transaction) on April 1, 2004, and all claims in this litigation were released. In addition, the settlement provided for the termination of all environmental indemnity obligations under the agreements governing Tex-New Mex's sale of its pipeline system to us. In accordance with the terms of the settlement, the amended judgment was vacated and this lawsuit was dismissed on April 15, 2004.

EOTT Energy Operating Limited Partnership vs. Texas-New Mexico Pipeline Company, Cause No. CV-44, 099, In the District Court of Midland County, Texas, 238th Judicial District ("EOTT's Over-Arching Claim"). As described above, the claims in this lawsuit were severed from EOTT's Kniffen Claims on April 11, 2003. In this lawsuit, we alleged that various practices employed by Tex-New Mex in the operation of its pipelines and handling of spills constitute gross negligence and willful misconduct, thus triggering Tex-New Mex's obligation to indemnify us for remediation of releases where such practices ("Non-Remediation Practices") were employed. In addition to damages, we were seeking (a) injunctive relief requiring Tex-New Mex to honor its indemnity obligations under the Purchase and Sale Agreement and (b) injunctive relief requiring Tex-New Mex to identify, investigate, and remediate sites where Tex-New Mex employed the Non-Remediation Practices. Discovery opened in EOTT's Over-Arching Claim on December 1, 2003. On March 3, 2004, we amended our petition to specifically list more than 200 contamination sites where Tex-New Mex employed the Non-Remediation Practices. The March 31, 2004 settlement agreement that provided for the resolution of the Kniffen Estates Suit also provided for the release of all claims in EOTT's Over-Arching Claim. In accordance with the terms of that settlement agreement, EOTT's Over-Arching Claim was dismissed with prejudice on April 20, 2004.

Bankruptcy Issues related to Claims Made by Texas-New Mexico Pipeline Company and its affiliates. Tex-New Mex, Shell Oil Company ("Shell") and Equilon filed proofs of claim in our bankruptcy, each filing similar claims in the amount of $112 million. In July of 2003, we entered into an agreement with Shell, Tex-New Mex and Equilon whereby all of their claims were either withdrawn, estimated or allowed, leaving the value of the claims estimated for distribution purposes at $56,924.52. In connection with the settlement of the Kniffen Estates Suit and the Over-Arching Claim, we have resolved all of our outstanding bankruptcy claims with Shell and its related entities.

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from the plaintiffs' alleged fear of exposure to carcinogens and the alleged interference with the plaintiffs' quiet enjoyment of their property. The plaintiffs are also seeking an unspecified amount of punitive damages. EOTT and the plaintiffs agreed to the terms of a settlement, whereby the plaintiffs agreed to release their claims against us and received an allowed general unsecured claim in our bankruptcy in the amount of $1,027,000. The allowed general unsecured claim was accrued at December 31, 2002. On October 21, 2003, the plaintiffs filed a motion seeking our dismissal from this lawsuit. Tex-New Mex opposed this motion, and on October 31, 2003, Tex-New Mex filed a motion for leave to file a cross-claim against us. In the proposed cross-claim, Tex-New Mex is seeking a declaratory judgment finding that we are contractually obligated to indemnify Tex-New Mex for all costs Tex-New Mex has incurred or will incur related to the defense of the plaintiffs' claims in this lawsuit. The proposed cross-claim also alleges that we failed to assume Tex-New Mex's defense of this lawsuit and failed to indemnify Tex-New Mex for the expenses Tex-New Mex has incurred in this lawsuit, and that such actions by us constitute a breach of the Purchase and Sale Agreement governing Tex-New Mex's sale of the subject pipeline to us. The March 31, 2004 settlement agreement that provided for the resolution of the Kniffen Estates Suit also provided for the release of Tex-New Mex's claims against us in this lawsuit. In accordance with the terms of that settlement agreement, this lawsuit was dismissed with prejudice on April 20, 2004.

In re EOTT Energy Partners, L.P., Case No. 02-21730, EOTT Energy Finance Corp., Case No. 02-21731, EOTT Energy General Partner, L.L.C., Case No. 02-21732, EOTT Energy Operating Limited Partnership, Case No. 02-21733, EOTT Energy Canada Limited Partnership, Case No. 02-21734, EOTT Energy Liquids, L.P., Case No. 02-21736, EOTT Energy Corp., Case No. 02-21788, Debtors (Jointly Administered under Case No. 02-21730), In the United States Bankruptcy Court for the Southern District of Texas, Corpus Christi Division. On October 8, 2002, we and all of our subsidiaries filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the Southern District of Texas (the "EOTT Bankruptcy Court") to facilitate reorganization of our business and financial affairs for the benefit of us, our creditors and other interested parties. Additionally, the General Partner filed its voluntary petition for reorganization under Chapter 11 on October 21, 2002 in the EOTT Bankruptcy Court. Our Restructuring Plan was confirmed on February 18, 2003 and became effective on March 1, 2003. Shell and Tex-New Mex filed a notice of appeal to our plan confirmation on February 24, 2003. A hearing on the appeal was held in the District Court on August 19, 2003, where the judge ruled the appeal was moot. The ruling became final on October 24, 2003. We filed a motion closing the bankruptcy case on April 14, 2004, and the order closing the case was entered on June 2, 2004.

Blackmore Partners, L.P. v. Link Energy, LLC, J. Robert Chambers, Julie H. Edwards, Thomas M. Matthews, Robert E. Ogle, James M. Tidwell, S. Wil VanLoh, Jr., and Daniel J. Zaloudek, Case No. 454-N, In the Court of Chancery of the State of Delaware in and for New Castle County, for the alleged breach of fiduciary duties to certain unitholders in connection with the anticipated distribution of proceeds resulting from the sale of substantially all of the Company's operating assets to Plain Marketing, L.P., Plains Pipeline, L.P. and Plains All American Pipeline, L.P. effective April 1, 2004 (the "Transaction"). The suit was brought by a unitholder who claims that the Company and its directors in place at the time of the Transaction favored the interests of unitholders who were also the holders of the Company's 9% Senior Notes (the "Notes") to the detriment of plaintiff and the other members of

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the class as defined by plaintiff (i.e., unitholders who do not also own a portion of the Notes). The plaintiff maintains that the Company's liquidation plan is inequitable and discriminatory since it allegedly provides a $25 million supplemental payment to the unitholders who also own the Notes. Based on management's current knowledge, we believe the allegations are without merit. We can provide no assurances regarding the outcome of this lawsuit, but will continue to gather and analyze new information as it becomes available.

EPA's Section 308 Request. In July 2001, Enron received a request for information from the EPA under Section 308 of the CWA, requesting information regarding certain spills and releases from oil pipelines owned or operated by Enron and its affiliated companies for the time period July 1, 1998 to July 11, 2001. Enron responded in January of 2002 to the EPA's Section 308 request in its capacity as the operator of the pipelines actually owned by us and on our behalf. Under the terms of the Enron Settlement Agreement dated October 8, 2002, we would be required to indemnify EOTT Energy Corp., as the prior general partner, and its affiliates including Enron Pipeline Services Company, with regard to any environmental remediation, except for claims of gross negligence and willful misconduct. While we cannot predict the outcome of the EPA's Section 308 request, the EPA could seek to impose liability for environmental cleanup on us with respect to the matters being reviewed. The outcome of the EPA's Section 308 request is not yet known, and we are unaware of any potential liability.

Environmental. Prior to the sale of all of our assets, we were subject to extensive federal, state and local laws and regulations covering the discharge of materials into the environment, or otherwise relating to the protection of the environment, and which require expenditures for remediation at various operating facilities and waste disposal sites, as well as expenditures in connection with the construction of new facilities. At the federal level, such laws include, among others, the Clean Air Act, the Clean Water Act, the Oil Pollution Act, the Resource Conservation and Recovery Act, the Comprehensive Environmental Response, Compensation and Liability Act, and the National Environmental Policy Act, as each may be amended from time to time. Failure to comply with these laws and regulations may result in the assessment of administrative, civil, and criminal penalties or the imposition of injunctive relief.

Prior to the sale of our Liquids Operations discussed further in Note 7, we produced MTBE at our Morgan's Point Facility. MTBE is used as an additive in gasoline. Due to health concerns around MTBE, there have been lawsuits filed against companies involved in the production of MTBE. We have not been named in any such actions, nor do we anticipate being included in any such actions. However, we can provide no assurances that we may not be included in such actions due to our past production of MTBE.

We have incurred spill clean up and remediation costs associated with the assets acquired from Tex-New Mex as well as in connection with other properties we own in various locations throughout the United States. We have insurance covering clean up and remediation costs that may be incurred in connection with properties not acquired from Tex-New Mex. However, no assurance can be given that the insurance will be adequate to cover any such cleanup and remediation costs.

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The following are summaries of environmental remediation expense, estimated environmental liabilities, and amounts receivable under insurance policies for the indicated periods (in thousands):

	Successor Company					Predecessor Company
	Three Months ended March 31, 2004			One Month ended March 31, 2003		Two Months ended February 28, 2003
Remediation expense	$	1,407		$	926	$	1,979
Estimated insurance recoveries		(361	)		—		(79	)

Net remediation expense	$	1,046		$	926	$	1,900

	Successor Company						Predecessor Company
	Three Months ended March 31, 2004			One Month ended March 31, 2003			Two Months ended February 28, 2003
Environmental liability at beginning of period	$	12,216		$	13,440		$	13,440
Remediation expense		1,407			926			1,979
Cash expenditures		(2,400	)		(1,176	)		(1,979	)

Environmental liability at end of period	$	11,223		$	13,190		$	13,440

	Successor Company					Predecessor Company
	Three Months ended March 31, 2004		One Month ended March 31, 2003			Two Months ended February 28, 2003
Environmental insurance receivable at beginning of period	$	3,089	$	8,837		$	8,803
Estimated recoveries		361		—			79
Cash receipts		—		(1,780	)		(45	)

Environmental insurance receivable at end of period	$	3,450	$	7,057		$	8,837

The environmental liability was classified in Other Current ($6.7 million) and Other Long-Term Liabilities ($4.5 million) and the insurance receivable was classified in Trade and Other Receivables ($3.0 million) and Other Assets ($0.4 million) at March 31, 2004.

12. NEW ACCOUNTING STANDARDS

Accounting Standards Adopted—First Quarter 2004

In December 2003, the FASB issued FASB Interpretation No. 46 (revised December 2003), "Consolidation of Variable Interest Entities—an Interpretation of ARB No.51" ("FIN 46R"). FIN 46R replaces FIN 46 which we implemented effective with the adoption of fresh start reporting on March 1, 2003. FIN 46R is required to be implemented by the end of the first reporting period beginning after

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December 15, 2003. We adopted FIN 46R effective January 1, 2004. Adoption of FIN 46R had no impact on our financial statements.

Accounting Standards Previously Adopted—Cumulative Effect of Accounting Changes

In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations." This statement required entities to record the fair value of a liability for legal obligations associated with the retirement obligations of tangible long-lived assets in the period in which it is incurred. When the liability is initially recorded, a corresponding increase in the carrying value of the related long-lived asset would be recorded. Over time, accretion of the liability is recognized each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss on settlement. We adopted the accounting principle required by the new statement effective January 1, 2003. As a result of the adoption of SFAS 143 on January 1, 2003, we recorded a liability of $1.7 million, property, plant and equipment, net of accumulated depreciation of $0.1 million and a cumulative effect of a change in accounting principle of $1.6 million.

In October 2002, the EITF reached a consensus in EITF Issue 02-03 to rescind Issue EITF 98-10, and related interpretive guidance, and preclude mark to market accounting for energy trading contracts that are not derivative instruments pursuant to SFAS 133. The consensus requires that gains and losses (realized and unrealized) on all derivative instruments held for trading purposes be shown net in the income statement, whether or not the instrument is settled physically. The consensus to rescind EITF Issue 98-10 was effective for all new contracts entered into (and physical inventory purchased) after October 25, 2002. For energy trading contracts and physical inventories that existed on or before October 25, 2002, that remained at December 31, 2002, the consensus was effective January 1, 2003 and was reported as a cumulative effect of a change in accounting principle. The cumulative effect of the accounting change at January 1, 2003 was a loss of $2.4 million.

13. BUSINESS SEGMENT INFORMATION

We have two reportable segments, which management reviews in order to make decisions about resources to be allocated and assess performance: North American Crude Oil and Pipeline Operations. The North American Crude Oil segment primarily purchases, gathers, transports and markets crude oil. The Pipeline Operations segment operates approximately 6,900 miles of active common carrier pipelines in 12 states. Effective December 31, 2003, we sold our Liquids Operations and therefore the results of operations related to these assets have been classified as discontinued operations presented herein. We sold all of our natural gas liquids assets on the West Coast on October 1, 2003 and therefore, the results of operations related to these assets previously included in the West Coast Operations segment have been reclassified to discontinued operations for all periods presented herein.

The accounting policies of the segments are the same as those described in the summary of significant accounting policies as discussed in Note 2 included in our Annual Report on Form 10-K (as amended) for the year ended December 31, 2003. We evaluate performance based on operating income (loss).

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We account for intersegment revenue for our North American Crude Oil Operations as if the sales were to third parties, that is, at current market prices. Intersegment revenues for Pipeline Operations are based on published pipeline tariffs.

FINANCIAL INFORMATION BY BUSINESS SEGMENT (IN THOUSANDS)

	North American Crude Oil			Pipeline Operations		Corporate and Other(a)			Consolidated
Three Months ended March 31, 2004 (Successor Company)
Revenue from external customers	$	29,307		$	11,375	$	—		$	40,682
Intersegment revenue(b)		(2,407	)		15,357		(12,950	)		—

Total operating revenue		26,900			26,732		(12,950	)		40,682

Gross profit (loss)		(1,621	)		8,443		—			6,822

Operating income (loss)		(4,533	)		6,266		(12,721	)		(10,988	)
Other expenses, net		—			—		(11,555	)		(11,555	)

Income (loss) from continuing operations		(4,533	)		6,266		(24,276	)		(22,543	)

Total assets		474,576			203,680		11,559			689,815

Depreciation and amortization		638			4,416		6			5,060

		North American Crude Oil			Pipeline Operations		Corporate and Other(a)			Consolidated
One Month ended March 31, 2003 (Successor Company) (Restated)
Revenue from external customers		$	16,768		$	965	$	—		$	17,733
Intersegment revenue(b)			(2,913	)		8,568		(5,655	)		—

	Total operating revenue		13,855			9,533		(5,655	)		17,733

Gross profit			3,852			4,216		—			8,068

Operating income (loss)			3,313			3,238		(2,231	)		4,320
Other expense			—			—		(3,277	)		(3,277	)

Income (loss) from continuing operations before cumulative effect of accounting changes (c)			3,313			3,238		(5,508	)		1,043

Total assets			547,962			221,766		99,884			869,612

Depreciation and amortization			376			1,331		1			1,708

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		North American Crude Oil			Pipeline Operations		Corporate and Other^(a)			Consolidated
Two Months ended February 28, 2003 (Predecessor Company) (Restated)
Revenue from external customers		$	27,213		$	4,422	$	—		$	31,635
Intersegment revenue^(b)			(1,768	)		11,828		(10,060	)		—

	Total operating revenue		25,445			16,250		(10,060	)		31,635

Gross profit (loss)			3,752			6,219		—			9,971

Operating income (loss)			2,365			4,261		(4,012	)		2,614
Other expense			—			—		(5,489	)		(5,489	)
Reorganization items, net gain on discharge of debt and fresh start adjustments^(c)			—			—		67,459			67,459

Income (loss) from continuing operations			2,365			4,261		57,958			64,584

Total assets			505,965			226,646		123,511			856,122

Depreciation and amortization			837			3,286		519			4,642

^(a): Corporate and Other also includes intersegment eliminations.
^(b): Intersegment sales for North American Crude Oil are made at prices comparable to those received from external customers. Intersegment sales for Pipeline Operations are based on published pipeline tariffs.
^(c): The two months ended February 28, 2003 include a gain from reorganization items of $7.3 million, a gain on discharge of debt of $131.6 million and a loss related to fresh start adjustments of $56.8 million. See Notes 5 and 6. 2002 includes a net gain from reorganization items of $32.8 million

F-92

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Unitholders of Link Energy LLC:

In our opinion, the accompanying consolidated balance sheet and the related consolidated statements of operations, members' capital and cash flows present fairly, in all material respects, the financial position of Link Energy LLC and its subsidiaries (Successor Company) at December 31, 2003 and the results of their operations and their cash flows for the period from March 1, 2003 to December 31, 2003 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the accompanying index present fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and the financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audit. We conducted our audit of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

As discussed in the Note 1 caption "Restatement of Financial Results" and in Note 10 to the consolidated financial statements, the Company has restated its financial results for the period from March 1, 2003 to December 31, 2003.

As discussed in Note 1 to the consolidated financial statements, the United States Bankruptcy Court for the Southern District of Texas confirmed the Company's voluntary petitions for reorganization under Chapter 11 of the U.S. Bankruptcy Code (the "plan") on February 18, 2003, to be effective on March 1, 2003. In connection with its emergence from bankruptcy, the Company adopted fresh start accounting as of February 28, 2003.

The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 3 to the consolidated financial statements, the Company has suffered recurring losses from operations and has a net capital deficiency that raises substantial doubt about its ability to continue as a going concern. Management's plans in regard to these matters are also described in Note 3. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

PRICEWATERHOUSECOOPERS LLP

Houston, Texas
March 30, 2004, except as to the matters discussed in the Note 1 caption "Restatement of Financial Results" and in Note 10 which the date is June 15, 2004

F-93

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Unitholders of Link Energy LLC:

In our opinion, the accompanying consolidated balance sheet and the related consolidated statements of operations, partners' capital and cash flows present fairly, in all material respects, the financial position of EOTT Energy Partners, L.P. and its subsidiaries (Predecessor Company) at December 31, 2002 and the results of their operations and their cash flows for the period from January 1, 2003 to February 28, 2003, and for each of the two years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the accompanying index presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and the financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note 1 to the consolidated financial statements, the Company filed a petition on October 8, 2002 with the United States Bankruptcy Court for the Southern District of Texas for reorganization under the provisions of Chapter 11 of the U.S. Bankruptcy Code. The Company's reorganization plan was confirmed on February 18, 2003, to be effective on March 1, 2003. In connection with its emergence from bankruptcy, the Company adopted fresh start accounting as of February 28, 2003.

As discussed in Note 20 to the consolidated financial statements, the Company adopted the provisions of Emerging Issues Task Force No. 02-03, "Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities," related to the rescission of Emerging Issues Task Force Issue 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities," as of January 1, 2003. As discussed in Note 20 to the consolidated financial statements, the Company changed its method of accounting for asset retirement obligations as of January 1, 2003.

PRICEWATERHOUSECOOPERS LLP

Houston, Texas
March 30, 2004, except as to the matters discussed in the Note 1 caption "Restatement of Financial Results" and in Note 10 which the date is June 15, 2004

F-94

LINK ENERGY LLC
(A LIMITED LIABILITY COMPANY)
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per unit amounts)

					Predecessor Company
		Successor Company			Predecessor Company
		Successor Company						Year ended December 31,
		Ten Months ended December 31, 2003			Two Months ended February 28, 2003			Year ended December 31,
		Ten Months ended December 31, 2003			Two Months ended February 28, 2003			2002			2001
		(Restated)			(Restated)			(Restated)			(Restated)
Operating Revenue		$	153,033		$	31,635		$	182,932		$	250,571
Cost of Sales			23,863			4,521			25,007			43,149
Operating Expenses			70,102			13,020			94,274			97,969
Depreciation and Amortization—operating			17,139			4,123			26,621			27,802

Gross Profit			41,929			9,971			37,030			81,651
Selling, General and Administrative Expenses			45,959			6,846			53,480			45,051
Depreciation and Amortization—corporate & other			22			519			3,267			3,083
Other (Income) Expense			(13,867	)		(8	)		6,710			(1,092	)
Impairment of Assets			—			—			1,168			—

Operating Income (Loss)			9,815			2,614			(27,595	)		34,609
Interest Expense and Related Charges			(32,708	)		(5,645	)		(45,876	)		(35,363	)
Interest Income			77			58			127			1,319
Other, net			115			98			(44	)		(517	)

Income (Loss) from Continuing Operations Before Reorganization Items, Net Gain on Discharge of Debt and Fresh Start Adjustments			(22,701	)		(2,875	)		(73,388	)		48
Reorganization Items			—			(7,330	)		32,847			—
Net Gain on Discharge of Debt (Note 5)			—			131,560			—			—
Fresh Start Adjustments (Note 6)			—			(56,771	)		—			—

Income (Loss) from Continuing Operations			(22,701	)		64,584			(40,541	)		48
Loss from Discontinued Operations (Note 8)			(30,214	)		519			(62,713	)		(16,605	)

Income (Loss) Before Cumulative Effect of Accounting Change			(52,915	)		65,103			(103,254	)		(16,557	)
Cumulative Effect of Accounting Change (Notes 2 & 20)			—			(3,976	)		—			1,073

Net Income (Loss)		$	(52,915	)	$	61,127		$	(103,254	)	$	(15,484	)

Basic Net Income (Loss) Per Unit (Note 12)
	LLC Unit	$	(4.29	)	$	N/A		$	N/A		$	N/A

	Common Unit	$	N/A		$	0.14		$	(0.03	)	$	(0.55	)

	Subordinated Unit	$	N/A		$	—		$	(3.23	)	$	(0.55	)

Diluted Net Income (Loss) Per Unit (Note 12)		$	(4.29	)	$	0.10		$	(1.08	)	$	(0.55	)

Distributions Per Unit		$	—		$	—		$	0.25		$	1.90

Average Units Outstanding for Diluted Computation			12,331			27,476			27,476			27,476

The accompanying notes are an integral part of these consolidated financial statements.

F-95

LINK ENERGY LLC
(A LIMITED LIABILITY COMPANY)
CONSOLIDATED BALANCE SHEETS
(in thousands)

			Successor Company			Predecessor Company
			December 31, 2003			December 31, 2002
			(Restated)
ASSETS
Current Assets
	Cash and cash equivalents		$	2,450		$	16,432
	Restricted cash (Note 8)			6,045			—
	Trade and other receivables, net of allowance for doubtful accounts of $1,210 and $1,210, respectively			446,030			407,096
	Inventories of continuing operations			7,636			15,389
	Inventories of discontinued operations			—			16,970
	Other			6,283			23,888

		Total current assets		468,444			479,775

Property, Plant and Equipment				278,724			546,410
	Less: Accumulated depreciation			16,214			205,351

		Net property, plant and equipment		262,510			341,059

Long-lived assets of discontinued operations				838			39,899
Goodwill				—			7,436
Other Assets				6,852			4,070

Total Assets			$	738,644		$	872,239

LIABILITIES AND MEMBERS'/PARTNERS' CAPITAL
Current Liabilities
	Trade and other accounts payable		$	476,509		$	389,925
	Accrued taxes payable			6,700			11,327
	Term loans (Note 4)			75,000			75,000
	Commodity repurchase agreement (Note 4)			18,000			75,000
	Receivable financing (Note 4)			27,000			50,000
	Other			27,982			23,274

		Total current liabilities		631,191			624,526

Long-Term Liabilities
	Senior notes (Note 4)			104,451			—
	Other			17,399			15,817

		Total long-term liabilities		121,850			15,817

Liabilities Subject to Compromise (Note 5)				—			292,827

Commitments and Contingencies (Note 15)
Additional Partnership Interests (Note 18)				—			9,318

Members'/Partners' Capital (Deficit)
	Partners' Capital (Deficit)			—			(70,249	)
	Members' Capital (Deficit)			(14,392	)		—
	Accumulated Other Comprehensive Income (Loss)			(5	)		—

	Total			(14,397	)		(70,249	)

Total Liabilities and Members'/Partners' Capital			$	738,644		$	872,239

The accompanying notes are an integral part of these consolidated financial statements.

F-96

LINK ENERGY LLC
(A LIMITED LIABILITY COMPANY)
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)

				Successor Company			Predecessor Company
										Year ended December 31,
				Ten Months ended December 31, 2003			Two Months ended February 28, 2003			Year ended December 31,
				Ten Months ended December 31, 2003			Two Months ended February 28, 2003			2002			2001
				(Restated)			(Restated)			(Restated)			(Restated)
CASH FLOWS FROM OPERATING ACTIVITIES
	Reconciliation of net income (loss) to net cash provided by (used in) operating activities
		Net income (loss)		$	(52,915	)	$	61,127		$	(103,254	)	$	(15,484	)
		Depreciation			19,242			5,560			35,535			33,469
		Amortization of goodwill and other			—			—			2,015			2,609
		Impairment of assets			2,751			—			77,268			29,057
		Write-down of liquids operations inventories			4,003			—			—			—
		Net unrealized change in crude oil trading activities			822			(2,120	)		(1,755	)		2,053
		(Gains) losses on disposal of assets			(2,727	)		—			984			229
		Non-cash compensation expense			2,306			—			—			—
		Non-cash net gain for reorganization items and discharge of debt			—			(127,185	)		(37,802	)		—
		Fresh start adjustments			—			56,771			—			—
		Changes in components of working capital
			Receivables		(6,475	)		(32,177	)		94,089			421,680
			Inventories		12,762			6,757			54,077			1,799
			Other current assets		3,192			2,428			7,411			(1,780	)
			Trade accounts payable		9,034			47,845			(96,934	)		(537,198	)
			Accrued taxes payable		1,962			1,717			2,481			(1,909	)
			Other current liabilities		14,500			(320	)		(98	)		19,249
		Other assets and liabilities			(8,623	)		2,530			682			4,968

	Net Cash Provided by (Used in) Operating Activities				(166	)		22,933			34,699			(41,258	)

CASH FLOWS FROM INVESTING ACTIVITIES
	Proceeds from sale of assets				62,197			—			2,390			17,209
	Increase in restricted cash				(6,045	)		—			—			—
	Acquisitions				—			—			—			(117,000	)
	Additions to property, plant and equipment				(9,153	)		(285	)		(31,238	)		(36,228	)

	Net Cash Provided by (Used in) Investing Activities				46,999			(285	)		(28,848	)		(136,019	)

CASH FLOWS FROM FINANCING ACTIVITIES
	Increase (decrease) in receivable financing				(23,000	)		—			7,500			42,500
	Increase (decrease) in short-term borrowings				—			—			(40,000	)		40,000
	Increase in term loans				—			—			75,000			—
	Increase (decrease) in repurchase agreements				(57,000	)		—			(25,000	)		100,000
	Debt issuance cost				(3,758	)		—			(750	)		—
	Distributions to unitholders				—			—			(4,712	)		(43,163	)
	Exercise of warrants				444			—			—			—
	Other				(1,804	)		1,655			(4,398	)		(13,349	)

	Net Cash Provided by (Used in) Financing Activities				(85,118	)		1,655			7,640			125,988

Increase (Decrease) in Cash and Cash Equivalents					(38,285	)		24,303			13,491			(51,289	)
Cash and Cash Equivalents Beginning of Period					40,735			16,432			2,941			54,230

Cash and Cash Equivalents End of Period				$	2,450		$	40,735		$	16,432		$	2,941

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash Paid for Interest				$	19,558		$	5,599		$	34,931		$	33,041

	Cash Paid for Reorganization Items			$	6,271		$	2,867		$	4,955		$	—

SUPPLEMENTAL NON CASH INVESTING AND FINANCING INFORMATION
	Discharge of 11% Senior Notes, including accrued interest			$	—		$	248,481		$	—		$	—

	Cancellation of additional partnership interests			$	—		$	9,318		$	—		$	—
	Issuance of 9% Senior Notes and payment of interest in kind			$	5,200		$	104,000		$	—		$	—

	Issuance of new equity of Successor Company			$	—		$	36,687		$	—		$	—

The accompanying notes are an integral part of these consolidated financial statements.

F-97

LINK ENERGY LLC
(A LIMITED LIABILITY COMPANY)
CONSOLIDATED STATEMENTS OF MEMBERS'/PARTNERS' CAPITAL
(in thousands)

		Partners Capital
		Partners Capital												Accumulated Other Comprehensive Income (Loss)
		Common Unitholders			Subordinated Unitholders			General Partner			Members' Capital			Accumulated Other Comprehensive Income (Loss)			Total
Partners' Capital (Deficit) at December 31, 2000 (Unaudited)		$	47,832		$	41,247		$	7,285		$	—		$	—		$	96,364
	Net loss (Restated)		(10,207	)		(4,973	)		(304	)		—			—			(15,484	)
	Cash distribution		(35,105	)		(7,200	)		(858	)		—			—			(43,163	)

Partners' Capital (Deficit) at December 31, 2001 (Restated)			2,520			29,074			6,123			—			—			37,717
	Net loss (Restated)		(553	)		(29,074	)		(73,627	)		—			—			(103,254	)
	Cash distribution		(4,619	)		—			(93	)		—			—			(4,712	)

Partners' Capital (Deficit) at December 31, 2002 (Restated)			(2,652	)		—			(67,597	)		—			—			(70,249	)
	Loss before reorganization items, net gain on discharge of debt and fresh start adjustments (Restated)		—			—			(6,332	)		—			—			(6,332	)
	Reorganization items and net gain on discharge of debt		17,624			35,354			80,374			35,773			—			169,125
	Fresh start adjustments		(14,972	)		(35,354	)		(6,445	)		—			—			(56,771	)

Members' Capital at February 28, 2003 (Successor Company) (Restated)		$	—		$	—		$	—		$	35,773		$	—		$	35,773

Members' Capital at March 1, 2003 (Successor Company) (Restated)		$	—		$	—		$	—		$	35,773		$	—		$	35,773
	Net loss (Restated)		—			—			—			(52,915	)		—			(52,915	)
	Unrealized net losses on derivative instruments arising during the period		—			—			—			—			(160	)
	Less reclassification adjustment for net realized losses on derivative instruments included in net loss		—			—			—			—			155			(5	)

	Comprehensive loss																	(52,920	)

	Exercise of warrants		—			—			—			444			—			444
	Issuance of restricted units		—			—			—			12,450			—			12,450
	Less unearned compensation expense		—			—			—			(10,144	)		—			(10,144	)

Members' Capital at December 31, 2003 (Successor Company)		$	—		$	—		$	—		$	(14,392	)	$	(5	)	$	(14,397	)

The accompanying notes are an integral part of these consolidated financial statements

F-98

LINK ENERGY LLC
(A LIMITED LIABILITY COMPANY)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(As Restated)

1. BASIS OF PRESENTATION

Name Change and Organization

Effective October 1, 2003, EOTT Energy LLC ("EOTT LLC") changed its name to Link Energy LLC ("Link LLC"). In connection with our name change, we also changed the names of several of our subsidiaries as listed in the table below.

New Name		Former Name
Link Energy Limited Partnership		EOTT Energy Operating Limited Partnership
Link Energy Pipeline Limited Partnership		EOTT Energy Pipeline Limited Partnership
Link Energy Canada Limited Partnership		EOTT Energy Canada Limited Partnership
Link Energy Finance Corp.		EOTT Energy Finance Corp.
Link Energy General Partner LLC		EOTT Energy General Partner, L.L.C.
Link Energy Canada, Ltd.		EOTT Energy Canada Management Ltd.

Link LLC is a Delaware limited liability company that was formed on November 14, 2002 in anticipation of assuming and continuing the business formerly directly owned by EOTT Energy Partners, L.P. (the "MLP"), which, as described in Note 5 below, filed for Chapter 11 reorganization with its wholly owned subsidiaries on October 8, 2002. The MLP emerged from bankruptcy and merged into EOTT Energy Operating Limited Partnership resulting in EOTT LLC becoming the successor registrant to the MLP on March 1, 2003, the effective date of the Third Amended Joint Chapter 11 Plan of Reorganization, as supplemented ("Restructuring Plan"). We operate principally through four affiliated operating limited partnerships, Link Energy Limited Partnership, Link Energy Canada Limited Partnership, Link Energy Pipeline Limited Partnership, and EOTT Energy Liquids, L.P. (see Note 8 for information regarding the disposition of our Liquids operations), each of which is a Delaware limited partnership. Link Energy Finance Corp. was formed in order to facilitate certain investors' ability to purchase our senior notes. Link Energy General Partner, LLC serves as the general partner for our four affiliated operating limited partnerships. Until the MLP emerged from bankruptcy, EOTT Energy Corp. (the "General Partner"), a Delaware corporation and a wholly owned subsidiary of Enron Corp. ("Enron"), served as the general partner of the MLP and owned an approximate 1.98% general partner interest in the MLP. The General Partner filed for bankruptcy on October 21, 2002. Unless the context otherwise requires, the terms "we," "our," "us," and "Link" refer to Link Energy LLC and its four affiliated operating limited partnerships, Link Energy Finance Corp., and Link Energy General Partner, LLC (the "Subsidiary Entities"), and for periods prior to our emergence from bankruptcy in March 2003, such terms and "EOTT" refer to EOTT Energy Partners, L.P. and its sole general partner, EOTT Energy Corp., as well as the Subsidiary Entities.

Restatement of Financial Results

We have restated our financial results for the ten months ended December 31, 2003, the two months ended February 28, 2003, and the years ended December 31, 2002 and 2001 as more fully discussed in Note 10. The restatement relates to control deficiencies identified with inventory and accounts payable reconciliation procedures in our pipeline and liquids operations. The restatement results in a decrease in our net loss for the ten months ended December 31, 2003 of $0.9 million, an increase in our net income for the two months ended February 28, 2003 of $0.9 million, and an

F-99

increase in our net loss for the years ended December 31, 2002 and 2001 of $1.5 million and $0.3 million respectively.

Fresh Start Reporting

As a result of the application of fresh start reporting under the American Institute of Certified Public Accountants Statement of Position No. 90-7 ("SOP 90-7"), "Financial Reporting by Entities in Reorganization Under the Bankruptcy Code," as of February 28, 2003 (the date chosen for accounting purposes), Link's financial results for the ten months ended December 31, 2003 and the two months ended February 28, 2003 include two different bases of accounting and accordingly, the financial condition, operating results and cash flows of the Successor Company and the Predecessor Company have been separately disclosed. For a further discussion of fresh start reporting, see Note 6. For purposes of these financial statements, references to the "Predecessor Company" are references to us for periods through February 28, 2003 (the last day of the calendar month in which we emerged from bankruptcy) and references to the "Successor Company" are references to Link for periods subsequent to February 28, 2003. The Successor Company's financial statements are not comparable to the Predecessor Company's financial statements. See further discussion in Note 6.

Partnership Status

As a limited liability company, we are generally treated like a partnership for federal income tax purposes and like a corporation with limited liability for state law and other non-tax purposes. In other words, for federal income tax purposes, we do not pay tax on our income or gain, nor are we entitled to a deduction for our losses, but such gains or losses are allocated to each member in accordance with the member's interest in us and the member will be responsible for paying the income tax applicable to such membership interest. Our taxable income or loss, which may vary substantially from the net income or net loss we report in our consolidated statement of operations, is includable in the federal income tax returns of our members. The aggregate difference in the basis of our net assets for financial and tax reporting purposes cannot be readily determined as we do not have access to information about each member's tax attributes in Link.

In order for us to continue to be classified as a partnership for federal income tax purposes, at least 90% of our gross income for every taxable year must consist of "qualifying income" within the meaning of the Internal Revenue Code. In 2002 and 2003, we recognized income from our settlement with Enron and discharge of indebtedness in excess of 10% of our gross income for each of those years. As disclosed in more detail in our Third Amended Joint Chapter 11 Plan which is incorporated by reference into our Annual Report on Form 10-K for the year ended December 31, 2002, we concluded that income from our settlement with Enron and our debt discharge income constituted "qualifying income," although the matter was not free from doubt. In January 2004, we requested a private letter ruling from the Internal Revenue Service to determine either that the income from our settlement with Enron and the debt discharge income is qualifying income or that the recognition of such income should be disregarded for purposes of the qualifying income test because it was an inadvertent result of our bankruptcy.

F-100

We are unable to predict how or when the Internal Revenue Service will rule. If the ruling is favorable, we will continue to be treated as a partnership for federal income tax purposes for so long as we satisfy the qualifying income test. If we are unable to obtain a favorable ruling and are unsuccessful in litigating the matter should we choose to do so, we will be taxable as a corporation for the year in which we failed to meet the qualifying income test and every year thereafter. Any classification of us as a corporation could result in a material reduction in the value of our units.

LLC Agreement

Under our Limited Liability Company Agreement (the "LLC Agreement"), our Board may, but is not required, to make distributions to each interest holder, and in any event, our exit credit facilities do not permit us to make any cash distributions so long as we have any indebtedness or other obligations outstanding under the exit credit facilities. Similar to a corporation, members do not share our liability. Under our LLC Agreement, members are also entitled to certain information about us and to vote for directors and on certain other matters. The holders of the majority of outstanding units have the right to vote on mergers and the election or removal of directors. The holders of two-thirds of the units have the right to approve additional issuances of equity and certain amendments to the LLC Agreement. Members are not entitled to participate in our management directly, but participate indirectly through the election of our directors.

Reclassifications

Certain reclassifications have been made to prior period amounts to conform with the current period presentation.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation. We own and operate our assets through our operating limited partnerships. The accompanying financial statements reflect the consolidated accounts of Link Energy LLC and the operating limited partnerships after elimination of intercompany transactions.

Nature of Operations. Through our affiliated limited partnerships, Link Energy Limited Partnership, Link Energy Canada Limited Partnership, Link Energy Pipeline Limited Partnership, and EOTT Energy Liquids, L.P., we are engaged in the purchasing, gathering, transporting, trading, storage and resale of crude oil and related activities. Prior to their disposition in 2003, we were also engaged in the operation of a hydrocarbon processing plant (the "Morgan's Point Facility"), a natural gas liquids storage facility (the "Mont Belvieu Facility") and natural gas liquids assets on the West Coast. See Note 8 for information regarding the disposition of our Morgan's Point Facility, Mont Belvieu Facility and natural gas liquids assets on the West Coast. The results of operations related to these assets have been reclassified to discontinued operations for all periods presented herein. Our remaining principal business segments are our North American Crude Oil gathering and marketing operations and our Pipeline Operations.

F-101

Use of Estimates. The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Cash Equivalents. We record as cash equivalents all highly liquid short-term investments having original maturities of three months or less.

Restricted Cash. Restricted cash represents cash which is not available for general corporate purposes. At December 31, 2003, restricted cash is comprised of amounts to be used for the settlement of certain obligations related to our Liquids Operations, which were sold on December 31, 2003. See further discussion in Note 8.

Inventory. Inventory includes crude oil inventory in our North American Crude Oil gathering and marketing operations and our Pipeline Operations. Inventory is stated at average cost for all periods presented.

Property, Plant and Equipment. Property, plant and equipment is stated at historical cost for the Predecessor Company and has been adjusted to reflect the adoption of fresh start reporting for the Successor Company. See Note 7. Normal maintenance and repairs are charged to expense as incurred while significant improvements which extend the life of the asset are capitalized. Upon retirement or sale of an asset, the asset and the related accumulated depreciation are removed from the accounts and any resulting gain or loss is reflected in the results of operations.

Impairment of Assets. We evaluate impairment of our long-lived assets in accordance with Statement of Financial Accounting Standards ("SFAS") No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," and would recognize an impairment when estimated undiscounted future cash flows associated with an asset or group of assets are less than the asset carrying amount. Long-lived assets are subject to factors which could affect future cash flows. These factors include competition, our financial condition and cost of credit which impacts our ability to maintain or increase our crude oil volumes, regulation, environmental matters, consolidation in the industry, refinery demand for specific grades of crude oil, area market price structures and continued developmental drilling in certain areas of the United States. We continuously monitor these factors and pursue alternative strategies to maintain or enhance cash flows associated with these assets; however, no assurances can be given that we can mitigate the effects, if any, on future cash flows related to any changes in these factors. See Note 8 for further discussion of asset impairments.

Depreciation. Depreciation is provided by applying the straight-line method to the basis of property, plant, and equipment over the estimated useful lives of the assets. Asset lives are 10 to 20 years for barging, terminalling, gathering and pipeline facilities, 5 to 10 years for transportation equipment, and 3 to 20 years for other buildings and equipment.

Goodwill. Effective January 1, 2002, we adopted SFAS No. 142, "Goodwill and Other Intangible Assets." SFAS No. 142 requires entities to discontinue the amortization of goodwill, allocate all existing

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goodwill among its reporting segments based on criteria set by SFAS No. 142 and perform initial impairment tests by applying a fair value-based analysis on the goodwill in each reporting segment. Goodwill is to be tested for impairment annually or more frequently if circumstances indicate a possible impairment. Goodwill was allocated to the North American Crude Oil segment and in 2002 no impairment of goodwill was required. Our reported income from continuing operations of $0.05 million ($0.00 per diluted unit) in 2001 included amortization of goodwill of $1.0 million ($0.4 per diluted unit). Our income from continuing operations in 2001, excluding the amortization of goodwill, would have been $1.0 million ($0.04 per diluted unit). In connection with the adoption of fresh start reporting (see Note 6), all remaining goodwill at February 28, 2003 was eliminated.

Pipeline Linefill. Pipeline linefill, which consists of minimum operating requirements is recorded at cost for the Predecessor Company and was adjusted to fair value in connection with the adoption of fresh start reporting for the Successor Company (See Note 6). Total minimum operating linefill requirements held in third party pipelines and our pipelines at December 31, 2003 and 2002 were 2.1 million barrels valued at $39.7 million and 2.9 million barrels valued at $50.2 million, respectively. Minimum linefill requirements held in third party pipelines at December 31, 2003 and 2002 were valued at $6.3 million and $8.8 million, respectively, and classified as Other Assets and Other Current Assets, respectively, on the balance sheet. Minimum linefill requirements held in our pipelines at December 31, 2003 and 2002, were valued at $33.4 million and $41.4 million, respectively, and classified as Property, Plant and Equipment on the balance sheet. See Note 8 for information regarding the sale of certain linefill.

Derivative and Hedging Activities. We utilize derivative instruments to minimize our exposure to commodity price fluctuations. Generally, as we purchase lease crude oil at prevailing market prices, we enter into corresponding sales transactions involving either physical deliveries of crude oil to third parties or a sale of futures contracts on the NYMEX. Price risk management strategies, including those involving price hedges using NYMEX futures contracts, are very important in managing our commodity price risk. Such hedging techniques require resources for managing both future positions and physical inventories. We effect transactions both in the futures and physical markets in order to deliver the crude oil to its highest value location or otherwise to maximize the value of the crude oil we control. Throughout the process, we seek to maintain a substantially balanced risk position at all times. We do have certain risks that cannot be completely hedged such as basis risks (the risk that price relationships between delivery points, grades of crude oil or delivery periods will change) and the risk that transportation costs will change.

Effective January 1, 1999, we began reporting energy trading contracts (as defined) at fair value in the balance sheet with changes in fair value included in earnings in accordance with Emerging Issues Task Force ("EITF") Issue 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities."

Effective January 1, 2001, we began reporting derivative activities in accordance with SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended. SFAS No. 133 requires that derivative instruments be recorded in the balance sheet as either assets or liabilities measured at fair value. Under SFAS No. 133, we are required to "mark-to-fair value" all of our

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derivative instruments at the end of each reporting period. At the date of initial adoption of SFAS No. 133, the difference between the fair value of derivative instruments and the previous carrying amount of those derivatives was recorded as the cumulative effect of a change in accounting principle. The cumulative effect of adopting SFAS No. 133 effective January 1, 2001 was a $1.3 million ($0.05 per diluted unit) increase in income. SFAS No. 133 requires that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. Qualifying criteria include, among other requirements, that we formally designate, document, and assess the effectiveness of the hedging instruments as they are established and at the end of each reporting period. Special accounting for qualifying hedges allows a derivative's gains and losses to offset related results from the hedged item in the income statement. Changes in the fair value of derivatives designated as cash flow hedges are deferred to Other Comprehensive Income (Loss) ("OCI"), a component of Members' Capital, and reclassified into earnings when the associated hedged transaction affects earnings. Deferral of derivative gains and losses through OCI is limited to the portion of the change in fair value of the derivative instrument which effectively hedges the associated hedged transaction; ineffective portions are recognized currently in earnings. Beginning in the second quarter of 2003, we designated certain of our derivative instruments as cash flow hedges of forecasted transactions. These hedges were for a maximum of two-months and had no material effect on our OCI or earnings for the ten months ended December 31, 2003. The ineffective portions of our hedged transactions were not material to our earnings for the ten months ended December 31, 2003. SFAS No. 133 requires that any cash flow hedges, for which it is probable that the original forecasted transactions will not occur by the end of the originally specified time period, be discontinued and reclassified into earnings, and that such reclassifications be recorded and separately disclosed. We had no such reclassifications for the ten months ended December 31, 2003. All unrealized derivative gains and losses included in accumulated other comprehensive income (loss) at December 31, 2003 are expected to be reclassified to net income (loss) within the next twelve months. Realized derivative gains and losses are included in Operating Revenue in our Statement of Operations.

Changes in the market value of transactions designated as energy trading activities in accordance with EITF Issue 98-10 (prior to the rescission of EITF Issue 98-10) and derivative instruments accounted for under SFAS No. 133, are recorded in revenues every period as unrealized gains or losses. The related price risk management assets and liabilities are recorded in other current or non-current assets and liabilities, as applicable, on the balance sheet. The fair value of transactions is determined primarily based on forward prices of the commodity, adjusted for certain transaction costs associated with the transactions. For the ten months ended December 31, 2003, we had net unrealized losses of $0.8 million, for the two months ended February 28, 2003, we had net unrealized gains of $4.5 million and for the years ended December 31, 2002 and 2001, we had net unrealized gains of $1.8 million and net unrealized losses of $2.5 million, respectively.

In the first quarter of 2001, we changed our method of accounting for inventories used in our energy trading activities from the average cost method to the fair value method. The cumulative effect of the change in accounting for inventories as of January 1, 2001 was $0.2 million ($0.01 per diluted unit) and is reported as a decrease in net income for 2001. The change in accounting for inventories increased reported net income in 2001 by approximately $2.6 million. The consensus to rescind EITF Issue 98-10 eliminated EOTT's basis for recognizing physical inventories at fair value. With the

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rescission of EITF Issue 98-10, inventories purchased after October 25, 2002 were valued at average cost.

In October 2002, the EITF reached a consensus in EITF Issue 02-03 "Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities." The EITF reached a consensus to rescind EITF Issue 98-10, and related interpretive guidance, and preclude mark to market accounting for energy trading contracts that are not derivative instruments pursuant to SFAS No. 133. See Note 20 for discussion of the cumulative effect of the change in accounting principle. The consensus requires that gains and losses (realized and unrealized) on all derivative instruments held for trading purposes be shown net in the income statement, whether or not the instrument is settled physically.

Revenue Recognition. Prior to the rescission of EITF Issue 98-10 in the fourth quarter of 2002, substantially all of our current gathering, marketing and trading activities were accounted for on a fair value basis with changes in fair value included in earnings. Qualifying derivative instruments are accounted for pursuant to SFAS No. 133 and energy trading activities were accounted for pursuant to EITF Issue 98-10. We recognize revenue on the accrual method, for non trading activities and non- derivative instruments, based on the right to receive payment for goods and services delivered to third parties.

Certain estimates were made in determining the fair value of contracts. We have determined these estimates using available market data and valuation methodologies. Judgment is required in interpreting market data, and the use of different market assumptions or estimation methodologies may affect the estimated fair value amounts.

Cost of Sales and Operating Expenses. Cost of sales includes the cost of purchasing crude oil and associated transportation costs. Operating expenses consist of field and pipeline expenses, including payroll and benefits, utilities, telecommunications, fuel and power, environmental expenses and property taxes.

Receivable Financing. SFAS No. 140 "Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities—A Restatement of FASB Statement No. 125" was effective March 31, 2001. Under SFAS No. 140, transfers of accounts receivable under our receivables agreement, discussed further in Note 4, are accounted for as financings. Costs associated with the transfers are classified as "Interest Expense and Related Charges" on the Consolidated Income Statement.

Foreign Currency Transactions. Canadian operations represent all of our foreign activities. The U.S. dollar is the functional currency. Foreign currency transactions are initially translated into U.S. dollars. The resulting gains and losses are included in the determination of net income (loss) in the period in which the exchange rate changes. The gain (loss) on foreign currency transactions, included in "Other, net" on the Consolidated Income Statement was a gain of $0.1 million for the ten months ended December 31, 2003 and a gain of $0.1 million for the two months ended February 28, 2003. No gain or loss was recognized for the year ended December 31, 2002 and a $0.3 million loss was recognized for the year ended December 31, 2001.

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Environmental. Expenditures for ongoing compliance with environmental regulations that relate to current operations are expensed or capitalized as appropriate. Estimated liabilities are recorded when environmental assessments indicate that remedial efforts are probable and the costs can be reasonably estimated. Estimates of the liability and insurance recovery, if any, are based upon currently available facts, existing technology and presently enacted laws and regulations and are included in the balance sheet on an undiscounted basis.

Unit Based Compensation Plans. We account for unit-based compensation using the intrinsic value recognition provisions of APB No. 25, "Accounting for Stock Issued to Employees," and related interpretations. If we had elected to recognize compensation cost based on the fair value recognition provisions of SFAS No. 123, "Accounting for Stock Based Compensation", net income (loss) and net income (loss) per unit would be unchanged for the ten months ended December 31, 2003, the two months ended February 28, 2003 and for the years ended December 31, 2002 and 2001.

3. LIQUIDITY/GOING CONCERN

General

We emerged from bankruptcy on March 1, 2003 as a highly leveraged company and have not been able to significantly reduce our debt to date. We will not be able to continue as a viable business unless we reduce our debt and attract new volumes.

Our Restructuring Plan anticipated profitable Liquids Operations and a quick return of crude oil volume growth in 2003. After incurring an operating loss of $31.0 million from our Liquids Operations since our emergence from bankruptcy, we sold our Liquids Operations in December 2003 for approximately $20 million (see Note 8). Our pre-bankruptcy customers and business partners have been less willing to do business with us than we anticipated as a result of our being highly leveraged and having shown no substantive improvement in our financial performance. Although our Restructuring Plan assumed that our marketing volumes would increase to approximately 350,000 barrels per day by the end of 2003, our actual marketing volumes were approximately 254,000 barrels per day in December 2003, and we do not anticipate an appreciable increase in volumes for the remainder of 2004.

Furthermore, as a result of our bankruptcy, we incurred higher costs in obtaining credit than we had in the past. Our trade creditors were less willing to extend credit to us on an unsecured basis and the amount of letters of credit we have been required to post for our marketing activities increased significantly. Our letters of credit outstanding at December 31, 2003 were $250 million with a maximum commitment available of $260 million.

Our cash flow from operations is not sufficient to meet our current cash requirements and, as a result, we have been borrowing under our Trade Receivables Agreement in order to fund our operations and capital needs. Absent a significant improvement in our business performance, we expect to continue to borrow to meet our cash requirements to the extent borrowed funds are available. At March 19, 2004, we have approximately $23.0 million in borrowing availability under our Trade Receivables Agreement. Based on our current cash requirements, we may exhaust our sources of available cash in the second quarter of 2004.

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We have sold substantially all of our non-strategic assets in an effort to reduce our aggregate indebtedness, which was approximately $268 million as of March 15, 2004. We will not be able to use funds from future asset sales, if any, to meet our current cash needs because the proceeds from any such sales are likely to be required to reduce our outstanding indebtedness. In addition to asset sales, we have attempted, without success, to raise additional equity and to convert indebtedness to equity.

We are in advanced discussions with a potential buyer regarding the sale of substantially all of our assets; however, there can be no assurances that we can consummate a transaction. The net proceeds of the transaction would be used to repay all of our outstanding indebtedness, as well as to satisfy other existing obligations. If the transaction were consummated, we would have no further operations and would wind down over a period of time. If we are not successful in consummating the transaction, we will continue to pursue other strategic alternatives, which include the sale of additional assets (singularly or in groups) or a voluntary filing under the U.S. Bankruptcy Code. Based on our existing level of indebtedness, it is unlikely that either a sale or bankruptcy would yield any material residual value for the Company's unitholders.

Factors Adversely Affecting Our Liquidity and Working Capital

Our ability to fund our liquidity and working capital requirements has been adversely affected by various factors, including the following:

•: Covenant Breaches under Exit Credit Facilities. During the last four months of 2003 and in January 2004, we have breached certain covenants under our exit credit facilities, which include the Letter of Credit Agreement, the Term Loan, the Trade Receivables Agreement and the Commodity Repurchase Agreement. These covenants are discussed below. We have obtained a waiver of these 2003 violations and are currently in discussions with our lenders regarding a waiver for January 2004. In addition, we have reduced the lenders' maximum commitment under the Letter of Credit Facility from $325 million to $260 million.
•: Minimum Consolidated EBIDA. We are required to maintain a minimum, rolling cumulative four month total of consolidated Earnings Before Interest Depreciation and Amortization, subject to certain adjustments, as defined ("Minimum Consolidated EBIDA"). For the rolling four-month periods ended September 30, 2003, October 31, 2003, November 30, 2003, December 31, 2003 and January 31, 2004, the required Minimum Consolidated EBIDA under our exit credit facilities and our actual consolidated EBIDA were as follows:

Rolling Four-Month Period Ended	Required Minimum Consolidated EBIDA		Actual Consolidated EBIDA
	(Restated)
September 30, 2003	$	6.6 million	$	1.2 million
October 31, 2003	$	8.7 million	$	2.9 million
November 30, 2003	$	10.4 million	$	(1.4) million
December 31, 2003	$	12.7 million	$	(2.2) million
January 31, 2004	$	16.0 million	$	1.0 million

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For the rolling four-month periods ending February 29, 2004, March 31, 2004 and April 30, 2004, we will be required to maintain Minimum Consolidated EBIDA of $15.7 million, $16.9 million and $16.5 million, respectively. Thereafter, the requirement continues to increase until it reaches $17.4 million for the four-month period ended August 31, 2004. Because this covenant becomes increasingly stringent, we expect we will not be in compliance with this covenant and thereby will be in default under our exit credit facilities for the foreseeable future.

•: Interest Coverage. We are required to maintain a minimum ratio of consolidated EBIDA to interest expense, subject to certain exclusions ("Interest Coverage Ratio"), over rolling consecutive four month periods. For the rolling four-month periods ended September 30, 2003, October 31, 2003, November 30, 2003, December 31, 2003 and January 31, 2004, the required Interest Coverage Ratio under our exit credit facilities and our actual interest coverage ratio were as follows:

Rolling Four-Month Period Ended	Required Interest Coverage Ratio	Actual Interest Coverage Ratio
	(Restated)
September 30, 2003	.62 to 1.00	.13 to 1.00
October 31, 2003	.79 to 1.00	.31 to 1.00
November 30, 2003	.93 to 1.00	(.15) to 1.00
December 31, 2003	1.11 to 1.00	(.23) to 1.00
January 31, 2004	1.36 to 1.00	.10 to 1.00

For the rolling four-month periods ending February 29, 2004, March 31, 2004 and April 30, 2004, we will be required to maintain an Interest Coverage Ratio of 1.35 to 1.00, 1.36 to 1.00 and 1.34 to 1.00, respectively. This ratio requirement continues to increase until it reaches 1.42 to 1.0 for the four-month period ended August 31, 2004. Because this covenant becomes increasingly stringent, we expect we will not be in compliance with this covenant and thereby will be in default under our exit credit facilities for the foreseeable future.

•: Minimum Consolidated Tangible Net Worth. At the end of each month, from March 31, 2003 to December 31, 2003, we were required to maintain a minimum consolidated tangible net worth, subject to certain adjustments, as defined ("Minimum Consolidated Tangible Net Worth"), of $8.5 million. Actual Minimum Consolidated Tangible Net Worth at December 31, 2003 was $12.8 million. From January 31, 2004 to August 30, 2004, we are required to maintain a Minimum Consolidated Tangible Net Worth of $10 million. Actual Minimum Consolidated Tangible Net Worth at January 31, 2004 was $9.9 million.
•: Covenant Breach relating to Borrowing Base Calculation. We are required to maintain asset values (the "Borrowing Base") at all times that exceed our aggregate outstanding letters of credit ("LC Obligations"). As of February 15, 2004, aggregate LC Obligations exceeded the Borrowing Base by approximately $1.9 million. This represented a payment default of $1.9 million under our Letter of Credit Facility which was subsequently waived. As of March 15, 2004, the Borrowing Base exceeded LC Obligations by approximately $12 million.

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•: Consequences of Covenant Breaches. Any default (covenant default or payment default, after applicable cure periods) under any of our exit credit facilities will cause a cross-default under all the other exit credit facilities. If a payment default under any of the exit credit facilities or any other debt obligation involves indebtedness of $10 million or more, or there is an acceleration of the indebtedness of $10 million or more, then the payment default under the exit credit facilities would be a default under the indenture relating to the 9% Senior Notes (the "9% Senior Notes Indenture"). A default under the 9% Senior Notes Indenture will cause a cross-default under our exit credit facilities.

Any breaches, unless waived, could severely limit our access to liquidity and credit support and result in our being required to repay all outstanding indebtedness, plus accrued and unpaid interest, under our exit credit facilities as well as the 9% Senior Note Indenture. Although our exit credit facility lenders provided a waiver for our breaches of covenants as of December 31, 2003, there can be no assurance they will provide waivers for any subsequent period, including January 31, 2004, or that any amendment to our exit credit facilities required to obtain such assurance will not adversely affect our liquidity.

•: Maturities of our Exit Facilities. In addition, we extended our Trade Receivables Agreement and Commodity Repurchase Agreement to June 1, 2004 (although we have an option to extend the maturity to August 30, 2004, subject to us being in compliance with our debt covenants) and our Term Loan and Letter of Credit Facility mature on August 30, 2004. As of March 15, 2004, we had $53.0 million of outstanding borrowings under our Trade Receivables Agreement, $16.9 million of outstanding borrowings under our Commodity Repurchase Agreement, and $75 million of borrowings under our Term Loan Agreement. Since we did not reduce Standard Chartered's exposure below $200 million by March 1, 2004, we paid a $2.5 million fee to Standard Chartered on March 15, 2004. We may not be able to repay the indebtedness under our exit credit facilities at maturity. Any replacement credit facilities, to the extent obtainable, may be at significantly greater cost to us. There can be no assurances, however, that replacement credit facilities can be obtained.
•: Covenant breach Under Enron Note. We are required to maintain at all times a letter of credit securing a promissory note payable to Enron Corp. (the "Enron Note") in the initial principal amount of $6.2 million. We failed to cause such letter of credit to be renewed at least 10 business days prior to its expiration, which resulted in an event of default under, and the automatic acceleration of, the Enron Note. As of December 31, 2003, $5.7 million was due and payable under the Enron Note. A replacement letter of credit has been issued, and we have asked Enron Corp. to waive the event of default and rescind the automatic acceleration of the note. There can be no assurance that Enron Corp. will provide the waiver or when such a waiver will be provided.

Going Concern

Our Consolidated Financial statements have been prepared assuming we will continue as a going concern which contemplates the realization of assets and settlement of liabilities in the normal course of business. The factors discussed above raise substantial doubt about our ability to continue as a going

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concern. Our Consolidated Financial statements do not include any adjustments that might result from the outcome of this uncertainty.

4. CREDIT RESOURCES

Summary of Debtor in Possession ("DIP") Financing

On October 18, 2002, we entered into agreements with Standard Chartered, SCTS, Lehman and other lending institutions for $575 million in DIP financing facilities. The DIP facilities provided (i) $500 million of credit and financing facilities through Standard Chartered and SCTS, which included up to $325 million for letters of credit through Standard Chartered and $175 million of inventory repurchase/accounts receivable financing through SCTS, and (ii) $75 million of term loans through Lehman and other lending institutions. The credit facilities were subject to a borrowing base and were secured by a first-priority lien on all, or substantially all, of our real and personal property. At December 31, 2002 we had amounts outstanding under the repurchase agreement and accounts receivable financing agreement of $75 million and $50 million, respectively, at weighted average interest rates of 4.4% and 4.7%, respectively. As of February 28, 2003, we had outstanding approximately $313 million of letters of credit, $125 million of inventory repurchase/accounts receivable financing, and $75 million of term loans. The DIP financing facilities contained certain restrictive covenants that, among other things, limited distributions, other debt, and certain asset sales. On February 28, 2003, as we emerged from bankruptcy, the DIP financing facilities were refinanced by the same institutions. The following discussion provides an overview of our post-bankruptcy debt.

Summary of exit credit facilities, Senior Notes, and other debt

Our emergence from bankruptcy, as of March 1, 2003, was financed through a combination of exit credit facilities, senior notes and other debt associated with settlement of claims during our bankruptcy proceedings. The table below provides a summary of these financing arrangements as of December 31, 2003.

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Summary of Financing Arrangements
(in millions)

		Commitment/ Face Amount		Amount Outstanding		Maturity
Exit Credit Facilities:
	Letter of Credit Facility	$	260.0	$	250.1	August 30, 2004
	Trade Receivables Agreement		100.0⁽¹⁾		27.0	March 1, 2004⁽²⁾
	Commodity Repurchase Agreement		18.0		18.0	March 1, 2004⁽²⁾
	Term Loans		75.0		75.0	August 30, 2004
Senior Notes			109.2		104.5	March 1, 2010⁽³⁾⁽⁴⁾
Other Debt:
	Enron Note		5.7		6.4	October 1, 2005⁽³⁾⁽⁵⁾
	Big Warrior Note		2.5		2.3	March 1, 2007⁽³⁾
	Ad Valorem Tax Liability		6.6		6.6	March 1, 2009

⁽¹⁾: $50 million of this commitment is unavailable ten days each month.
⁽²⁾: On March 1, 2004, we extended these arrangements for 3 months until June 1, 2004 and paid an extension fee of $0.4 million. We have an option to extend these arrangements until August 30, 2004 subject to the payment of extension fees of $0.4 million and us being in compliance with our debt covenants.
⁽³⁾: These notes were adjusted to fair value pursuant to the adoption of fresh start reporting required by SOP 90-7.
⁽⁴⁾: On September 1, 2003 and March 1, 2004, we issued an additional senior note in the amount of $5.2 million and $5.5 million, respectively, in lieu of the first and second semi-annual payment of interest on our senior notes.
⁽⁵⁾: See discussion below regarding event of default.

The following is a summary of our scheduled debt maturities at December 31, 2003 (in millions):

	2004		2005		2006		2007		2008		After 2008		Total
Senior Notes	$	—	$	—	$	—	$	—	$	—	$	109.2	$	109.2
Term Loans⁽¹⁾		75.0		—		—		—		—		—		75.0
Commodity Repurchase Agreement⁽¹⁾		18.0		—		—		—		—		—		18.0
Trade Receivables Agreement⁽¹⁾		27.0		—		—		—		—		—		27.0
Enron Note⁽²⁾		1.0		4.7		—		—		—		—		5.7
Big Warrior Note		0.3		0.4		0.4		1.4		—		—		2.5
Ad Valorem Tax Liability		2.8		0.9		1.0		1.1		0.8		—		6.6

	$	124.1	$	6.0	$	1.4	$	2.5	$	0.8	$	109.2	$	244.0

⁽¹⁾: See previous discussion of covenant violations and cross defaults.
⁽²⁾: See discussion on the following page regarding event of default.

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Exit Credit Facilities

On February 11, 2003, we entered into our exit credit facilities with the same lenders and under substantially the same terms in the DIP financing facilities. These new facilities were effective March 1, 2003 and $2.9 million of facility and extension fees were paid in connection with these new facilities. Such fees are being amortized as interest expense over the terms of the facilities.

Letter of Credit Facility

The Letter of Credit Facility, as amended, with Standard Chartered provides $260 million of financing until August 30, 2004 and is subject to defined borrowing base limitations. The borrowing base is (as of the date of determination) the sum of cash equivalents, specified percentages of eligible receivables, deliveries, fixed assets, inventory, margin deposits and undrawn product purchase letters of credit, minus (i) first purchase crude payables, other priority claims, aggregate net amounts payable by the borrowers under certain hedging contracts and certain eligible receivables arising from future crude oil obligations, (ii) the principal amount of loans outstanding and any accrued and unpaid fees and expenses under the Term Loans, and (iii) all outstanding amounts under the Amended and Restated Commodity Repurchase Agreement and the Amended and Restated Receivables Purchase Agreement ("SCTS Purchase Agreements"). Pursuant to a scheduled advance rate reduction, effective July 1, 2003, the specified percentages of eligible receivables and fixed assets in the borrowing base were reduced. As of February 15, 2004, our aggregate letter of credit obligation exceeded the borrowing base by approximately $1.9 million. We have obtained a waiver of this violation from our lenders. As of March 15, 2004, the Borrowing Base exceeded LC Obligations by approximately $12 million.

The Letter of Credit Facility required an upfront facility fee of $1.25 million that was paid at closing. Since we did not reduce Standard Chartered's exposure below $200 million by March 1, 2004, we paid a $2.5 million fee to Standard Chartered. Letter of credit fees range from 2.25% to 2.75% per annum depending on usage. The commitment fee is 0.5% per annum of the unused portion of the Letter of Credit Facility. Additionally, we agreed to a fronting fee, which is the greater of 0.25% per annum times the face amount of the letter of credit or $250. An annual arrangement fee of 1% per annum times the average daily maximum commitment amount, as defined in the Letter of Credit Facility, is payable on a monthly basis.

The exit credit facilities include various financial covenants that we must adhere to on a monthly basis as discussed in Note 3 and set forth below.

•: Current Ratio. We must maintain a ratio of consolidated current assets, subject to certain adjustments to consolidated current liabilities less funded debt, as defined, of 0.90 to 1.00 for the term of the exit credit facilities. The actual Current Ratio at December 31, 2003 was 1.00 to 1.00.

For purposes of determining the financial information used in the financial covenants set forth above and in Note 3, we are required to exclude all items directly attributable to our Liquids Operations and the West Coast natural gas liquids assets ("Designated Assets") for the first five months ended May 31, 2003, and to make "permitted adjustments" (changes due to fresh start reporting, income and expenses attributable to the Designated Assets during the first five months

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ended May 31, 2003, changes due to the cumulative affect of changes in GAAP, which are approved by the bank, gains or losses from the sales of assets or Designated Assets and any write-downs on Designated Assets), as defined.

In connection with the sale of assets in 2003 discussed in Note 8, the Letter of Credit Facility was amended to allow the net proceeds from these asset sales to be used to repay amounts outstanding under the Commodity Repurchase Agreement.

In addition, there are certain restrictive covenants that, among other things, limit other debt, certain asset sales, mergers and change in control transactions. Additionally, the exit credit facilities prohibit us from making any distributions, or purchases, acquisitions, redemptions or retirement of our LLC units so long as we have any indebtedness, liabilities or other obligations outstanding to Standard Chartered, SCTS, Lehman, or any other lenders under these facilities.

SCTS Purchase Agreements

We have an agreement with SCTS similar to our pre-bankruptcy inventory repurchase agreement, which provides for the financing of purchases of crude oil inventory utilizing a forward commodity repurchase agreement ("Commodity Repurchase Agreement"). The maximum commitment under the Commodity Repurchase Agreement was $75 million. It required an upfront facility fee of approximately $378,000 and carried an interest rate of LIBOR plus 3%. During the fourth quarter of 2003, net proceeds of $57 million from the disposition of assets were used to repay amounts outstanding under the Commodity Repurchase Agreement and the maximum commitment amount was reduced to $18 million. The Commodity Repurchase Agreement had an initial term of six months to August 30, 2003, at which time we had the option to extend for an additional twelve months. In August 2003, we amended the Commodity Repurchase Agreement to provide us the option to (1) extend the maturity date to March 1, 2004 and (2) prior to March 1, 2004, extend the maturity date to August 30, 2004. The election of each option will require the payment of an extension fee of $375,000. We elected to extend the maturity date to March 1, 2004, which required the payment of the extension fee of $375,000 and increased the interest rate to LIBOR plus 7%. We subsequently elected to extend the Commodity Repurchase Agreement to June 1, 2004, although we have an option to extend the maturity to August 30, 2004, subject to us being in compliance with our debt covenants. The election of the option required the payment of an extension fee of $0.2 million. At December 31, 2003, we had outstanding repurchase agreements of $18 million with an interest rate of 8.2%.

In addition, we also have an agreement with SCTS similar to our pre-bankruptcy trade receivables agreement, which provides for the financing of up to an aggregate amount of $100 million of certain trade receivables ("Trade Receivables Agreement") outstanding at any one time. The discount fee is LIBOR plus 3% and an upfront facility fee of approximately $504,000 was paid. The Trade Receivables Agreement had an initial term of six months to August 30, 2003, at which time we had the option to extend for an additional twelve months. In August 2003, we amended the Trade Receivables Agreement to provide us the option to (1) extend the maturity date to March 1, 2004 and (2) prior to March 1, 2004, extend the maturity date to August 30, 2004. The election of each option will require the payment of an extension fee of $0.5 million. We elected to extend the maturity date to March 1, 2004, which required the payment of an extension fee of $0.5 million and increased the interest rate to

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LIBOR plus 7%. We subsequently elected to extend the Trade Receivables Agreement to June 1, 2004, although we have an option to extend the maturity to August 30, 2004. The election of the option required the payment of an extension fee of $250,000. Receivables financed at December 31, 2003 totaled $27 million at a weighted average interest rate of 8.1%.

Term Loan Agreement

We entered into an agreement with Lehman, as Term Lender Agent, and other lenders (collectively, "Term Lenders"), which provides for term loans in the aggregate amount of $75 million (the "Term Loans"). The Term Loans mature on August 30, 2004.

The financing included two term notes. The Tier-A Term Note is for $50 million with a 9% per annum interest rate. The Tier-B Term Note is for $25 million with a 10% per annum interest rate. Interest is payable monthly on both notes. An upfront fee of $750,000 was paid and we agreed to pay a deferred financing fee in the aggregate amount of $2 million on the maturity date of the Term Loans. This latter fee was fully accrued as of February 28, 2003.

The Term Loans are collateralized and have certain repayment priorities with respect to collateral proceeds pursuant to the Intercreditor and Security Agreement that is discussed below. Under the Term Loan Agreement, term loan debt outstanding is subject to a borrowing base as defined in the Letter of Credit Agreement. Further, the Term Loan Agreement contains financial covenants that mirror those outlined above in the discussion of the Letter of Credit Facility.

Intercreditor and Security Agreement

In connection with the Letter of Credit Facility, the Term Loans and the SCTS Purchase Agreements, we entered into the Intercreditor and Security Agreement ("Intercreditor Agreement") with Standard Chartered, Lehman, SCTS and various other secured parties ("Secured Parties"). This agreement provides for the sharing of collateral among the Secured Parties and prioritizes the application of collateral proceeds which provides for repayment of the Tier-A Term Note and the Standard Chartered letter of credit exposure above $300 million prior to other secured obligations.

In addition, to the extent that drawings are made on any letters of credit, Standard Chartered, as Collateral Agent, may distribute funds from our debt service payment account to itself (as letter of credit issuer ("LC Issuer") on behalf of the letter of credit participants) as needed to allow Link LLC to reimburse Standard Chartered, as letter of credit issuer, for such drawings.

Senior Notes

On October 1, 1999, we issued to the public $235 million of 11% senior notes. The senior notes were due October 1, 2009, and interest was paid semiannually on April 1 and October 1. The senior notes were fully and unconditionally guaranteed by all of our operating limited partnerships but were otherwise unsecured. On October 1, 2002, we did not make the interest payment of $12.9 million on our 11% senior notes. These notes were cancelled effective March 1, 2003 as a result of our Restructuring Plan and the holders of these notes, along with our general unsecured creditors with allowed claims, received a pro rata share of $104 million of 9% senior unsecured notes, plus a pro rata share of 11,947,820 Link LLC units.

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Link LLC Senior Notes 2010

In February 2003, we issued $104 million of 9% senior unsecured notes to the Bank of New York, as depositary agent, which was subsequently allocated by the depositary agent to former holders of the 11% senior notes described above and our general unsecured creditors with allowed claims. The senior notes are due in March 2010, and interest will be paid semiannually on September 1 and March 1, with the first payment made on September 1, 2003. Under the terms of the indenture governing our senior notes, we are allowed to pay interest payments in kind by issuing additional senior notes on the first two interest payment dates. If we make payments in kind, we must make the payments as if interest were being charged at 10% per annum instead of 9% per annum. On September 1, 2003, we issued an additional senior note in the aggregate principal amount of $5.2 million to the Bank of New York in lieu of the first interest payment. On March 1, 2004, we issued an additional senior note in the aggregate principal amount of $5.5 million to the Bank of New York in lieu of the second interest payment. We may not optionally redeem the notes. The notes are subject to mandatory redemption or sinking fund payments if we sell assets and use the money for certain purposes or if we have a change of control. Provisions of the indenture could limit additional borrowings, sale and lease back transactions, affiliate transactions, purchases of our own equity, payments on debt subordinated to the senior notes, distributions to members, certain merger, consolidation or change in control transactions, or sale of assets if certain financial performance ratios are not met.

Other Debt

In connection with our settlement with Enron as part of the Restructuring Plan, we executed a $6.2 million note payable to Enron ("Enron Note") that is guaranteed by our subsidiaries. The Enron Note is secured by an irrevocable letter of credit and bears interest at 10% per annum. Interest is paid semiannually on April 1 and October 1, beginning on April 1, 2003 and we are allowed to pay interest payments in kind on the first two interest payment dates. Principal payments of $1 million are payable in October 2003 and October 2004, with the remaining principal balance due in October 2005. On October 1, 2003, we paid our first principal payment of $1.0 million and elected to pay our interest payment of $0.3 million in kind. We failed to cause the letter of credit to be renewed at least 10 business days prior to its expiration, which resulted in an event of default under, and the automatic acceleration of, the Enron Note. A replacement letter of credit has been issued and we have requested Enron to waive the event of default and rescind the automatic acceleration of the note. There can be no assurance that Enron will provide the waiver, and therefore, the Enron Note is recorded in Other Current Liabilities on the Consolidated Balance Sheet at December 31, 2003.

In connection with a settlement with Big Warrior Corporation ("Big Warrior") during our bankruptcy, we executed a $2.7 million note payable to Big Warrior, which is secured by a second lien position in one of our Mississippi pipelines. The four-year note is payable in quarterly installments which began June 1, 2003 based on a seven-year amortization schedule, at an interest rate of 6% per annum. A final balloon payment is due March 1, 2007. Effective July 31, 2003, Farallon Capital Partners, L.P. ("Farallon") and Tinicum Partners, L.P. ("Tinicum"), both of which are Term Lenders, purchased this note from Big Warrior.

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In conjunction with our Restructuring Plan, we agreed to pay accrued but unpaid ad valorem taxes over six years from the effective date of our Restructuring Plan. This debt bears interest at 6% with principal and interest payments due quarterly. The first payment was made on June 1, 2003. Unpaid ad valorem taxes of $2 million associated with the Liquids Operations sold on December 31, 2003 (see Note 8) were paid in January 2004.

5. BANKRUPTCY PROCEEDINGS AND RESTRUCTURING PLAN

On October 8, 2002, the MLP and the Subsidiary Entities filed pre-negotiated voluntary petitions for reorganization under Chapter 11 of the United States Bankruptcy Code (the "EOTT Bankruptcy"). The filing was made in the United States Bankruptcy Court for the Southern District of Texas, Corpus Christi Division (the "EOTT Bankruptcy Court"). Additionally, the General Partner filed a voluntary petition for reorganization under Chapter 11 on October 21, 2002 in the EOTT Bankruptcy Court in order to join in the voluntary, pre-negotiated Restructuring Plan. On October 24, 2002, the EOTT Bankruptcy Court administratively consolidated, for distribution purposes, the General Partner's bankruptcy filing with the previously filed cases. We operated as debtors-in-possession under the Bankruptcy Code, which means we continued to remain in possession of our assets and properties and continued our day-to-day operations. The EOTT Bankruptcy Court confirmed our Restructuring Plan on February 18, 2003, and it became effective March 1, 2003.

We entered into an agreement, dated October 7, 2002, with Enron, Standard Chartered Bank ("Standard Chartered"), Standard Chartered Trade Services Corporation ("SCTS"), Lehman Commercial Paper Inc. ("Lehman Commercial") and holders of approximately 66% of the outstanding principal amount of our 11% senior notes (the "Restructuring Agreement"). Under this Restructuring Agreement, Enron, Standard Chartered, SCTS, Lehman Commercial and approximately 66% of our 11% senior note holders agreed to vote in favor of the Restructuring Plan, and to refrain from taking actions not in support of the Restructuring Plan.

The Restructuring Plan, however, was subject to the approval of the EOTT Bankruptcy Court, and the Settlement Agreement with Enron ("Enron Settlement Agreement") was subject to the additional approval of the United States Bankruptcy Court for the Southern District of New York (the "Enron Bankruptcy Court"), where Enron and certain of its affiliates filed for Chapter 11 bankruptcy protection. The EOTT Bankruptcy Court approved the Enron Settlement Agreement on November 22, 2002, and the Enron Bankruptcy Court approved the Enron Settlement Agreement on December 5, 2002. The major provisions of the Restructuring Plan, which became effective March 1, 2003, are as follows:

•: Enron has no further affiliation with us. The General Partner will be liquidated as soon as reasonably possible with no material effect to us.
•: We consummated the Settlement Agreement with Enron effective December 31, 2002. In the fourth quarter of 2002, we recognized a gain of $45.5 million related to the Settlement Agreement with Enron.

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•: We converted to a limited liability company structure and EOTT LLC (subsequently renamed Link Energy LLC) became the successor registrant to the MLP. The MLP was merged into EOTT Energy Operating Limited Partnership.
•: We are now managed by a seven-member Board of Directors. One of the directors is the chief executive officer of Link LLC, and the remaining six directors were selected by the former senior note holders who signed the Restructuring Agreement.
•: We cancelled our outstanding $235 million of 11% senior unsecured notes. Our former senior unsecured note holders and holders of allowed general unsecured claims received a pro rata share of $104 million of 9% senior unsecured notes and a pro rata share of 11,947,820 limited liability company units of EOTT LLC representing 97% of the newly issued units.
•: We cancelled the MLP's publicly traded common units, and the former holders of the MLP's common units received 369,520 limited liability company units of EOTT LLC, representing 3% of newly issued units, and 957,981 warrants to purchase an additional 7% of the new units. We cancelled the MLP's subordinated units and additional partnership interests. See Note 18.
•: We were authorized to develop, and the board has subsequently approved, a management incentive plan. The incentive plan reserves 1.2 million of EOTT LLC's authorized units for issuance to certain key employees and directors. See Note 19.
•: We closed exit credit facilities with Standard Chartered, SCTS, Lehman, and other lenders on February 28, 2003. See further discussion in Note 4.

As a result of the confirmation of our Restructuring Plan, the following liabilities that were deemed subject to compromise were either discharged by the EOTT Bankruptcy Court or retained as ongoing obligations of the Successor Company. Estimated liabilities subject to compromise at December 31, 2002 were as follows (in thousands):

11% Senior Notes		$	235,000
Interest payable—11% Senior Notes			13,481
Accounts payable and suspense payable			34,876
Allowed claims for environmental settlements and contingencies			7,970
Other			1,500

	Total	$	292,827

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Reorganization items—legal and professional fees		$	(7,330	)
Net gain on discharge of 11% senior notes, related accrued interest and other debt⁽¹⁾		$	131,560

⁽¹⁾: The gain on discharge of debt was recorded net of the 9% senior notes and limited liability company units issued to the creditors upon emergence from bankruptcy.

6. FRESH START REPORTING

The enterprise value of Link on the effective date of the Restructuring Plan was determined to be approximately $363 million. The enterprise value was determined with the assistance of a third party financial advisor using discounted cash flow, comparable transaction and capital market comparison analyses, adjusted for the actual working capital as of the effective date of the Restructuring Plan. The discounted cash flow analyses were based upon five year projected financial results, including an assumption for terminal values using cash flow multiples, discounted at our estimated post-restructuring weighted-average cost of capital.

Pursuant to SOP 90-7, the reorganization value of Link on the effective date of the Restructuring Plan was determined to be approximately $856 million, which represented the enterprise value plus the fair value of current liabilities exclusive of funded debt on February 28, 2003. We have allocated the reorganization value as of February 28, 2003 to tangible and identifiable intangible assets in conformity with SFAS No. 141, "Business Combinations", using discounted cash flow and replacement cost valuation analyses, and liabilities, including debt, were recorded at their net present values. Independent third-party valuation specialists were used to determine the allocation of the reorganization value to our tangible and identifiable intangible assets and to determine the fair value of our long-term liabilities.

The valuations were based on a number of estimates and assumptions, which are inherently subject to significant uncertainties and contingencies beyond our control. Accordingly, there can be no assurance that the valuations will be realized, and actual results could vary significantly.

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		Predecessor Company February 28, 2003			Debt Discharge and Re-Class Adjustments			Fresh Start Adjustments			Successor Company February 28, 2003
		(Restated)									(Restated)
Assets Current Assets Cash and cash equivalents		$	40,735		$	—		$	—		$	40,735
Trade and other receivables			439,361			—			—			439,361
Inventories			25,525			—			750	^(g)		26,275
Other			12,911			—			(2,021	)^(h)		10,890

	Total current assets		518,532			—			(1,271	)		517,261

Property, Plant and Equipment, at cost			598,633			—			(267,654	)⁽ⁱ⁾		330,979
Less: Accumulated depreciation			223,188			—			(223,188	)⁽ⁱ⁾		—

	Net property, plant and equipment		375,445			—			(44,466	)		330,979

Goodwill			7,436			—			(7,436	)^(j)		—

Other Assets			10,762			—			(2,880	)^(h)		7,882

	Total Assets	$	912,175		$	—		$	(56,053	)	$	856,122

Liabilities and Members'/Partners' Capital Current Liabilities Trade and other accounts payable		$	451,873		$	17,406	^(a)	$	—		$	469,279
Accrued taxes payable			13,045			(8,307	)^(b)		—			4,738
Term loans			75,000			(75,000	)^(c)		—			—
Repurchase agreement			75,000			(75,000	)^(c)		—			—
Receivable financing			50,000			—			—			50,000
Other			19,226			2,815	^(a)(b)		318	^(k)		22,359

	Total current liabilities		684,144			(138,086	)		318			546,376

Long-Term Liabilities 9% Senior Notes			—			98,800	^(d)		—			98,800
Term loans			—			75,000	^(c)		—			75,000
Repurchase agreement			—			75,000	^(c)		—			75,000
Ad valorem tax liability			—			6,992	^(b)		—			6,992
Other			17,781			—			400	^(k)		18,181

	Total long-term liabilities		17,781			255,792			400			273,973

Liabilities Subject to Compromise			284,843			(284,843	)^(a)		—			—
Additional Partnership Interests			9,318			(9,318	)^(e)		—			—
Members'/Partners' Capital (Deficit)			(83,911	)		176,455	^(f)		(56,771	)		35,773

	Total Liabilities and Members'/Partners' Capital	$	912,175		$	—		$	(56,053	)	$	856,122

Notes:

^(a): Liabilities subject to compromise have been adjusted to reflect the settlement of the claims and discharge of the 11% senior notes and related accrued interest in connection with the Restructuring Plan. See further discussion in Note 5.

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^(b): To reclassify current and long-term amounts due to taxing authorities for accrued but unpaid ad valorem taxes in connection with the Restructuring Plan.
^(c): To reflect the refinancing on a long-term basis of amounts outstanding under the Debtor-in-Possession Financing Facilities.
^(d): To reflect the issuance of 9% senior unsecured notes (face amount of $104 million) to all former senior note holders and general unsecured creditors with allowed claims in connection with the Restructuring Plan, recorded at fair value.
^(e): To reflect the cancellation of the additional partnership interests in connection with the Restructuring Plan.
^(f): To reflect the issuance of limited liability company units pursuant to the Restructuring Plan and the net gain on extinguishment of debt.
^(g): To adjust inventory to fair value.
^(h): To reflect the elimination of deferred turnaround costs, which are included in the fair value of property, plant and equipment of the Successor Company.
⁽ⁱ⁾: To adjust property, plant, and equipment to fair value.
^(j): To reflect the elimination of goodwill resulting from the fair value allocation.
^(k): To reflect the Enron and Big Warrior notes at fair value.

7. PROPERTY, PLANT AND EQUIPMENT

The components of property, plant and equipment are as follows (in thousands):

	Successor Company December 31, 2003			Predecessor Company December 31, 2002
Operating PP&E, including pipelines, storage tanks, etc	$	268,866		$	477,834
Office PP&E buildings and leasehold improvements		1,717			52,621
Tractors and trailers and other vehicles		1,248			10,739
Land		6,893			5,216

Property, Plant & Equipment		278,724			546,410
Less: Accumulated depreciation		(16,214	)		(205,351	)

Net Property, Plant & Equipment	$	262,510		$	341,059

8. DISPOSITIONS OF ASSETS

Discontinued Operations—West Coast Assets

Effective June 25, 2003, we signed a definitive agreement to sell all of the assets comprising our natural gas gathering, processing, natural gas liquids fractionation, storage and related trucking and distribution facilities located on the West Coast. A sale of these assets to a third party had been one of

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the options considered by us since we emerged from bankruptcy. The sales price for the assets exclusive of inventory was $9.9 million. The proceeds from the sale of the West Coast natural gas liquids assets could be increased by up to $1.4 million depending on the operating results of the West Coast natural gas liquids assets during the twelve month period following closing. The closing occurred on October 1, 2003, and $9.0 million of the net proceeds from the sale were used to pay down amounts outstanding under the Commodity Repurchase Agreement.

Effective June 1, 2002, we sold our West Coast refined products marketing operations to Trammo Petroleum Inc. The sales price was not significant.

Effective June 30, 2001, we sold our West Coast crude oil gathering and blending operations to Pacific Marketing and Transportation LLC ("Pacific") for $14.3 million. We could have been required to repay up to $1.5 million of the sale price, subject to a two-year look-back provision regarding average operating results during the period July 1, 2001 through June 30, 2003. Such amount is reflected in Liabilities Subject to Compromise in the Consolidated Balance Sheet at December 31, 2002. In addition, we also provided customary indemnifications to Pacific with a maximum aggregate exposure of $3.7 million, whose terms were due to expire between June 2002 through June 2006. In the third quarter of 2003, we negotiated a settlement and release with Pacific of all remaining obligations related to the sale for a payment of $0.2 million.

Revenues and results of operations for the West Coast operating segment for the ten months ended December 31, 2003, the two months ended February 28, 2003, and the years ended December 31, 2002 and 2001 are shown below (in (in thousands). We did not allocate any interest expense to the West Coast discontinued operations for any of the periods presented below.

	Successor Company		Predecessor Company
	Ten Months ended December 31, 2003		Two Months ended February 28, 2003		Year ended December 31, 2002			Year ended December 31, 2001
	(Restated)		(Restated)		(Restated)
Revenues	$	20,639	$	5,571	$	68,467		$	491,091
Income (loss) from discontinued operations	$	752	$	395	$	(25,246	)	$	(4,679	)

The income (loss) from the West Coast discontinued operations includes a loss on disposal of $0.8 million for the ten months ended December 31, 2003, no gain or loss recognized for the two months ended February 28, 2003, a gain on disposal of $0.2 million and a loss on disposal of $1.3 million for the years ended December 31, 2002 and 2001, respectively. At December 31, 2002, we recorded an impairment charge of $22.9 million to reflect these assets at their estimated fair values at December 31, 2002.

Discontinued Operations—Liquids Operations

Effective December 31, 2003, we sold all of our remaining natural gas liquids assets to a subsidiary of Valero Energy Corporation ("Valero") for approximately $20 million, plus inventory value. The assets included our underground salt dome storage facility and related pipeline grid near Mont Belvieu, Texas as well as our processing facility and former methyl tertiary butyl ether ("MTBE") plant at

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Morgan's Point, near La Porte, Texas. Net proceeds of approximately $15 million from the sale were used to pay down amounts outstanding under the Commodity Repurchase Agreement.

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Net proceeds from the sale of approximately $6 million were placed in escrow for ad valorem tax liabilities associated with the assets sold, reimbursement of any costs associated with potential title defects and adjustments associated with the verification of actual inventory balances sold.

In connection with the sale, we provided indemnifications to Valero for (1) title defects for a period of two years up to a maximum amount of $2 million and (2) preclosing environmental liabilities with an indefinite term and no monetary limits. We recorded a $1.1 million liability at December 31, 2003, reflecting the estimated fair value of these obligations.

Revenues and results of operations for the Liquids Operations for the ten months ended December 31, 2003, the two months ended February 28, 2003 and the years ended December 31, 2002 and 2001 are shown below (in thousands). We did not allocate any interest expense to the Liquids discontinued operations for any periods presented below.

	Successor Company			Predecessor Company
	Ten Months ended December 31, 2003			Two Months ended February 28, 2003		Year ended December 31, 2002			Year ended December 31, 2001
	(Restated)			(Restated)		(Restated)
Revenues	$	128,684		$	40,337	$	212,670		$	48,701

Income (loss) from discontinued operations	$	(30,966	)	$	124	$	(37,467	)	$	(11,926	)

Income (loss) from the Liquids discontinued operations for the ten months ended December 31, 2003 includes a loss on disposal of $8.4 million. At December 31, 2002, we recorded impairments of $33.0 million and $20.2 million related to our Mont Belvieu and Morgan's Point facilities, respectively, to reflect these assets at their estimated fair values at December 31, 2002.

During the fourth quarter of 2003, pursuant to a previously announced plan to reduce our Liquids Operations, we began to phase out our MTBE production at the Morgan's Point Facility. The decision to cease production of MTBE and end our financial exposure to the MTBE market was made after earlier attempts to sell the Liquids Operations terminated unsuccessfully. In connection with the phase out of MTBE production, we recorded charges in September 2003 for severance costs of $1.8 million, asset impairments of $2.8 million and the write-down of our materials and supplies inventory of $2.3 million. The severance costs were accrued pursuant to our pre-existing severance plan in accordance with SFAS No. 112, "Employers' Accounting for Post Employment Benefits—an Amendment of FASB Statements No. 5 and 43". The impairment charges reflect adjustments to the carrying values of long-lived assets used in the MTBE manufacturing operations to reflect their fair values. The charge for materials and supplies represents an adjustment to the carrying values of inventory items to reflect their net realizable values. The market for surplus MTBE related materials and supplies has been severely impacted by recent plant shut downs.

Our Liquids Operations were originally acquired effective June 30, 2001. We paid $117 million in cash to Enron and State Street Bank and Trust Company of Connecticut, National Association, Trustee.

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Concurrently with the acquisition of the Liquids Operations, we entered into a ten-year tolling agreement for the conversion of feedstocks into products, on a take-or-pay basis ("Toll Conversion Agreement"), and a ten-year storage and transportation agreement for the use of a significant portion of the Mont Belvieu Facility and pipeline grid system, on a take-or-pay basis ("Storage Agreement"). Both agreements were with Enron Gas Liquids, Inc. ("EGLI"), a wholly-owned subsidiary of Enron, which is now in bankruptcy. Under these agreements EGLI retained all existing third party commodity, transportation and storage contracts associated with these facilities. These agreements were the principle basis for determining the desirability of the transaction and the purchase price of the Liquids assets.

As more fully explained in Note 18, on December 3, 2001, EGLI was included in Enron's bankruptcy filing. Due to the non-performance by EGLI under the Toll Conversion Agreement in late November 2001, we began to operate the Morgan's Point Facility as a merchant operation in the spot market. We were unable to enter into third party spot or term contracts for storage until the Storage Agreement was rejected by EGLI. On April 2, 2002, the Bankruptcy Court entered a stipulation and agreed order rejecting the Toll Conversion and Storage Agreements (the "Stipulation"), which order became final and non-appealable on April 12, 2002. Rejection of the Storage Agreement with EGLI resulted in the loss of the buyer of the fixed throughput and storage capacity at the Mont Belvieu Facility. However, the rejection allowed us to directly seek new customers and pursue long-term contracts for the Mont Belvieu Facility to replace the long-term and continuous stream of revenue we expected under the Storage Agreement with EGLI. As a result of EGLI's non-performance under these contracts, we recorded a $29.1 million impairment in the fourth quarter of 2001.

Sales of Other Assets

On October 1, 2003, we sold certain crude oil marketing and transportation assets in the Arkansas, Louisiana and Texas ("ArkLaTex") area to Plains Marketing L.P. and Plains All American Pipeline, L.P., a wholly owned subsidiary of Plains Resources, Inc. The sales price for these assets, including linefill, was approximately $17 million. Subsequent to closing, $16.2 million of the net proceeds from the sale were used to pay down amounts outstanding under the Commodity Repurchase Agreement. The gain on the sale of these assets was $11.7 million. The long-lived assets disposed of were historically presented in the North American Crude Oil and Pipeline Operations operating segments.

In the fourth quarter of 2003, we entered into a Crude Oil Joint Marketing Agreement with ChevronTexaco Global Trading, a division of Chevron U.S.A. Inc. ("ChevronTexaco"). The agreement was effective January 1, 2004 with a term of 10 years. Under the agreement, ChevronTexaco will market all of the Company's lease crude oil in West Texas and Eastern New Mexico, with the Company handling the transportation of the crude oil and related administrative functions. The agreement contains various performance factors which must be met in order for the agreement to remain in effect for the full term of the agreement and if ChevronTexaco does not achieve certain performance targets during the first year of the agreement, we have agreed to economic adjustments not to exceed $1 million. In addition, if this agreement is terminated prior to January, 2006, as a result of us (1) divesting all or substantially all of our assets within the West Texas and New Mexico area or (2) seeking the protection of bankruptcy and are no longer able to perform our obligations under this

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agreement, then we will owe ChevronTexaco a $1 million termination payment. No assets were sold pursuant to this agreement, with the exception of linefill. In December 2003, the Company sold approximately 370,000 barrels of linefill held in West Texas and New Mexico to ChevronTexaco for approximately $10 million. The Company recognized a gain of approximately $2.6 million related to the sale, which gain has been deferred (included in Other Long-Term Liabilities on the Consolidated Balance Sheet), as the agreement contains mandatory obligations for the Company to repurchase the linefill from ChevronTexaco in the event that the agreement is terminated within the first five years.

9. CHANGE IN ESTIMATE OF CRUDE OIL LINEFILL

Measuring the physical volumes of crude oil linefill in certain of the pipelines we operate in the West Texas and New Mexico area is inherently difficult. Because these pipelines are operated under very little pressure, unlike the vast majority of our other pipelines, we cannot use traditional engineering based methods to estimate the physical volumes in the system but instead have utilized certain operational assumptions and topographical information which take into consideration the measurement limitations.

As a part of our pipeline integrity management program, we are in the process of removing from service various pipelines we operate in this area, some of which were acquired from Texas-New Mexico Pipe Line Company in 1999. The actual physical volume of crude oil linefill we removed from the line we took out of service during the third quarter of 2003 was less than our estimate of linefill volume for the applicable pipeline. Following this discovery, we initiated a thorough review of our estimates for all of our pipelines which are operated under very little pressure. We also engaged the services of a third party consultant to review our methodology of estimating linefill volumes. After completing this review, we revised downward our estimates of the physical volume of crude oil linefill in certain of our pipelines by approximately 170,000 barrels. As a result, we recorded a charge of $4.6 million to reflect our change in estimate of physical linefill volumes based on September 30, 2003 market prices. The charge was recorded in cost of sales in the Consolidated Statements of Operations.

We currently estimate that we will complete the program to remove these pipelines from service in the first half of 2004. The amount of crude oil linefill we ultimately remove from the affected pipelines could differ materially from our current estimates. Therefore, additional charges could be required in the near term.

10. RESTATEMENT OF FINANCIAL RESULTS

As reported in our initial Annual Report on Form 10-K for 2003, we identified control deficiencies with inventory and accounts payable reconciliation procedures in our pipelines and liquids operations. In order to address these issues, we designed and implemented additional procedures to provide reasonable assurance that these control deficiencies did not lead to a further misstatement in our consolidated financial statements. Related to this matter, we originally recorded charges in the third and fourth quarter of 2003 of $1.8 million and $0.9 million, respectively.

We are restating prior year financial results to reflect the inventory and accounts payable reconciliation adjustments in prior periods. The restatement results in a decrease in our net loss for the

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ten months ended December 31, 2003 of $0.9 million, an increase in our net income for the two months ended February 28, 2003 of $0.9 million, and an increase in our net loss for the years ended December 31, 2002 and 2001 of $1.5 million and $0.3 million respectively.

A summary of the effects of the restatement on reported amounts for the ten months ended December 31, 2003, the two months ended February 28, 2003, and the years ended December 31,2002 and 2001 are presented below. The effects on reported amounts for the quarterly periods in the years 2003 and 2002 are presented in Note 22. (Amounts in thousands, except per share amounts).

		Successor Company			Predecessor Company
		Ten Months ended December 31, 2003			Two Months ended February 28, 2003		Year ended December 31, 2002			Year ended December 31, 2001
REVENUE
	As Reported	$	152,678		$	31,979	$	182,942		$	250,573
	As Restated		153,033			31,635		182,932			250,571
GROSS PROFIT
	As Reported		41,440			9,681		37,558			81,902
	As Restated		41,929			9,971		37,030			81,651
OPERATING INCOME
	As Reported		9,326			2,324		(27,067	)		34,860
	As Restated		9,815			2,614		(27,595	)		34,609
NET INCOME (LOSS)
	As Reported		(53,829	)		60,267		(101,731	)		(15,233	)
	As Restated		(52,915	)		61,127		(103,254	)		(15,484	)
DILUTED EARNINGS (LOSS) PER UNIT
	As Reported		(4.37	)		0.08		(1.07	)		(0.54	)
	As Restated		(4.29	)		0.10		(1.08	)		(0.55	)

11. CAPITAL

As part of the Restructuring Plan, EOTT's common units, subordinated units and additional partnership interests were canceled and 14,475,321 new limited liability company units ("LLC units") were authorized. Holders of common units received 369,520 LLC units and 957,981 warrants to purchase additional LLC units. The warrants have a five-year term, a strike price of $12.50, are exercisable after June 30, 2003 and had an estimated fair value of $0.01 per warrant as of the effective date of the Restructuring Plan. Holders of EOTT's former 11% senior notes and general unsecured creditors with allowed claims received a pro rata allocation of 11,947,820 LLC units. The Bank of New York, the depositary agent, distributed approximately 90% of the LLC units in August 2003 and the final allocation of units was completed in December 2003. Additionally, 1.2 million LLC units were reserved for a management incentive plan for issuance to certain key employees and directors. See further discussion in Note 19.

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The following is a rollforward of LLC units and warrants outstanding:

	Common Units		Subordinated Units		LLC Units	Warrants
Units Outstanding at December 31, 2002	18,476,011		9,000,000		—	—
Units Cancelled in Connection with Restructuring Plan	(18,476,011	)	(9,000,000	)	—	—
Issuance of New LLC Units and Warrants	—		—		12,317,340	957,981

LLC Units and Warrants Outstanding as of February 28, 2003	—		—		12,317,340	957,981

Exercise of Warrants	—		—		35,549	(35,549	)
Restricted Units Outstanding	—		—		830,000	—

LLC Units and Warrants Outstanding at December 31, 2003	—		—		13,182,889	922,432

The LLC units and the warrants were issued pursuant to an exemption from the registration requirements of the Securities Act of 1933, as amended and applicable state law, pursuant to the exemptions afforded under Section 1145, Title 11 of the U.S. Bankruptcy Code. The LLC units and the warrants have been registered pursuant to the Securities Exchange Act of 1934, as amended (the "Exchange Act") pursuant to Section 12(g) and we are therefore a reporting company under the Exchange Act. Neither the LLC units nor the warrants are traded on any national exchange or pursuant to an automated quotation system administered by the National Association of Securities Dealers, Inc. ("NASD").

The LLC units issued pursuant to the Restructuring Plan are subject to the terms of a Registration Rights Agreement effective March 1, 2003 (the "Registration Rights Agreement"). Following completion of the audit of our financial statements for the year ending December 31, 2003, any holders of 10% or more of the securities eligible for registration under the terms of the Registration Rights Agreement will be entitled to demand registration of their LLC units, subject to certain conditions. The Registration Rights Agreement also provides for customary piggyback registration rights entitling holders of LLC units to include their units in any registration in which we may engage, subject to certain conditions. We will be required to pay all registration expenses in connection with any such registrations.

The LLC units are subject to the terms of an LLC Agreement, which currently, among other things, restricts the issuance of additional equity interests in Link without the approval of holders of at least two-thirds of the outstanding units.

12. EARNINGS PER UNIT

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Successor Company

Basic and diluted net loss per unit for the Successor Company were $4.29 for the ten months ended December 31, 2003. Outstanding stock warrants and contingently issuable restricted units were determined to be antidilutive and are not included in the computation of fully diluted earnings per unit. Basic and diluted net loss per unit from continuing operations were $1.84 for the ten months ended December 31, 2003. Basic and diluted net loss per unit from discontinued operations were $2.45 for the ten months ended December 31, 2003.

Predecessor Company

Total and per unit information related to income (loss) from continuing operations, discontinued operations, the cumulative effect of an accounting change and net income (loss) for the Predecessor

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Company is shown in the tables below. All amounts exclude amounts allocated to the General Partner (in thousands, except per unit amounts):

	Two Months ended February 28, 2003 (Restated)
	Basic⁽¹⁾
	Common				Subordinated				Diluted⁽²⁾
	Income (Loss)		Per Unit		Income (Loss)		Per Unit		Income (Loss)		Per Unit
Income (Loss) from Continuing Operations	$	2,133	$	0.11	$	—	$	—	$	2,133	$	0.08
Income (Loss) from Discontinued Operations⁽³⁾		519		0.03		—		—		519		0.02
Cumulative Effect of Accounting Changes⁽⁴⁾		—		—		—		—		—		—

Net Income (Loss)	$	2,652	$	0.14	$	—	$	—	$	2,652	$	0.10

Weighted Average Units Outstanding				18,476				9,000				27,476

	Year ended December 31, 2002 (Restated)
	Basic⁽¹⁾
	Common						Subordinated						Diluted⁽²⁾
	Income (Loss)			Per Unit			Income (Loss)			Per Unit			Income (Loss)			Per Unit
Income (Loss) from Continuing Operations	$	(1,017	)	$	(0.06	)	$	(29,074	)	$	(3.23	)	$	(30,091	)	$	(1.10	)
Income (Loss) from Discontinued Operations⁽³⁾		464			0.03			—			—			464			0.02

Net Income (Loss)	$	(553	)	$	(0.03	)	$	(29,074	)	$	(3.23	)	$	(29,627	)	$	(1.08	)

Weighted Average Units Outstanding					18,476						9,000						27,476

	Year ended December 31, 2001 (Restated)
	Basic⁽¹⁾
	Common						Subordinated						Diluted⁽²⁾
	Income (Loss)			Per Unit			Income (Loss)			Per Unit			Income (Loss)			Per Unit
Income (Loss) from Continuing Operations	$	31		$	—		$	14		$	—		$	45		$	—
Income (Loss) from Discontinued Operations⁽³⁾		(10,945	)		(0.59	)		(5,331	)		(0.59	)		(16,276	)		(0.59	)
Cumulative Effect of Accounting Changes		707			0.04			344			0.04			1,051			0.04

Net Income (Loss)	$	(10,207	)	$	(0.55	)	$	(4,973	)	$	(0.55	)	$	(15,180	)	$	(0.55	)

Weighted Average Units Outstanding					18,476						9,000						27,476

⁽¹⁾: Net income (loss), excluding the approximate two percent General Partner interest, has been apportioned to each class of unitholder based on the ownership of total units outstanding in accordance with the MLP's Partnership Agreement. Net losses are not allocated to the common and subordinated unitholders to the extent that such allocations would cause a deficit capital account balance or increase any existing deficit capital account balance. Any remaining losses are allocated to the General Partner as a result of the balances in the capital accounts of the common and subordinated unitholders. Effective with the third quarter of 2002, all losses were being allocated to the General Partner. The disproportionate allocation of

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2002 net losses among the unitholders and the General Partner was recouped during the two months ended February 28, 2003.

⁽²⁾: The diluted earnings (loss) per unit calculation assumes the conversion of subordinated units into common units.
⁽³⁾: Earnings (loss) per unit from discontinued operations has been determined based on the difference between the amount of net income (loss) allocated to each class of unitholder and the amount of income (loss) from continuing operations allocated to each class of unitholder. Earnings (loss) per unit for the two months ended February 28, 2003, have been impacted by the disproportionate allocation of income and loss discussed above.
⁽⁴⁾: The cumulative effect of accounting changes was allocated to the General Partner and subsequently recouped by the General Partner during the two months ended February 28, 2003.

13. OPERATING REVENUES

In connection with adopting EITF Issue 02-03, revenues and cost of sales related to our crude oil marketing and trading activities have been presented on a net basis. Gross revenues and purchase costs that have been netted are as follows (in thousands):

			Predecessor Company
	Successor Company		Predecessor Company
	Successor Company				Year ended December 31,
	Ten Months ended December 31, 2003		Two Months ended February 28, 2003		Year ended December 31,
	Ten Months ended December 31, 2003		Two Months ended February 28, 2003		2002		2001
	(Restated)		(Restated)		(Restated)		(Restated)
Gross revenue	$	4,260,719	$	831,187	$	4,541,591	$	8,081,536
Purchase costs reclassified		4,124,451		803,974		4,386,983		7,854,972

Operating revenues for marketing and trading operations, net		136,268		27,213		154,608		226,564
Gross revenue from other operations		16,765		4,422		28,324		24,007

Operating revenue	$	153,033	$	31,635	$	182,932	$	250,571

Consistent with standard crude oil industry practice, we utilize "buy/sell" contracts to facilitate our delivery obligations and to limit our overall risk. We utilize buy/sell contracts to price the relative values of crude oil that we seek to exchange between locations. The economic objective is to exchange one barrel of crude oil for another barrel of crude oil that has a different attribute such as, but not limited to, quality, location or delivery period. The primary objective of pricing both sides of a buy/sell contract at prices reflective of the crude oil's relative values is to allow for volume variances which occur between the estimated scheduled volumes and actual deliveries. If all volumes on these crude oil purchase contracts were exactly as forecast each month, such contracts could be handled by exchange contracts, with simply a location and quality differential. However, volumes are frequently (almost always in the case of lease production) different than scheduled. Both parties to the transaction are protected against volume variances by using the current month's market price for each grade, location or delivery period associated with the different barrels of crude oil.

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The following amounts have been recorded for buy/sell contracts in Operating Revenue in the Consolidated Statements of Operations (in millions):

			Predecessor Company
	Successor Company				Year ended December 31,
	Ten Months ended December 31, 2003		Two Months ended February 28, 2003		Year ended December 31,
	Ten Months ended December 31, 2003		Two Months ended February 28, 2003		2002		2001
Gross revenues	$	2,735	$	502	$	2,568	$	5,075
Purchase costs		2,625		481		2,474		5,013

Net operating revenue	$	110	$	21	$	94	$	62

14. OTHER (INCOME) EXPENSE.

The components of other (income) expense are as follows (in thousands):

					Predecessor Company
		Successor Company						Year ended December 31,
		Ten Months ended December 31, 2003			Two Months ended February 28, 2003			Year ended December 31,
		Ten Months ended December 31, 2003			Two Months ended February 28, 2003			2002			2001
(Gain) loss on disposal of fixed assets		$	(11,885	)	$	—		$	1,184		$	(1,108	)
Litigation settlements and provisions			(1,171	)		—			7,970			528
Gain on sale of NYMEX seats			—			—			(1,297	)		—
Other income			(811	)		(8	)		(1,147	)		(512	)

	Total	$	(13,867	)	$	(8	)	$	6,710		$	(1,092	)

15. COMMITMENTS AND CONTINGENCIES

Operating Leases. We lease certain real property, equipment, and operating facilities under various operating leases. Future non-cancelable commitments related to these items at December 31, 2003, are as follows (in millions): years ending December 31, 2004—$5.3; 2005—$4.2; 2006—$3.3; 2007—$1.0; 2008—$0.3; thereafter—$0.4.

Total lease expense incurred was $5.9 million for the ten months ended December 31, 2003, $1.2 million for the two months ended February 28, 2003 and $7.7 million and $8.3 million for the years ended December 31, 2002 and 2001, respectively.

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Indemnities. In November 2002, the Financial Accounting Standards Board ("FASB") issued Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others" ("FIN 45"). FIN 45 requires disclosures to be made by a guarantor in its financial statements about its obligations under certain guarantees it has issued and that a guarantor recognize, at the inception of a guarantee, a liability for the fair value of the obligation under the guarantee. We are a party to various contracts entered into in the ordinary course of business that contain indemnity provisions. Our obligations under the indemnities are contingent upon the occurrence of events or circumstances specified in the contracts. No such events or circumstances have occurred to date and we do not consider our liability under the indemnities to be material to our financial position or results of operations.

Litigation. We are, in the ordinary course of business, a defendant in various lawsuits, some of which are covered in whole or in part by insurance. We believe that the ultimate resolution of litigation, individually and in the aggregate, will not have a materially adverse impact on our financial position or results of operations. Several litigation claims were settled during the course of the bankruptcy proceedings or are still being negotiated post confirmation. How each matter was or is being handled is set forth in the summary of each case below. For matters where the parties negotiated a settlement during our bankruptcy proceedings, the settlement amount was recorded at December 31, 2002 as an allowed general unsecured claim in "Other Income (Expense)" in our Consolidated Statement of Operations. In connection with our Restructuring Plan, general unsecured creditors with allowed claims received a pro rata share of $104 million of 9% senior unsecured notes and a pro rata share of 11,947,820 Link LLC units. See further discussion in Notes 4 and 11. Prior to and since the commencement of our bankruptcy proceedings, various legal actions arose in the ordinary course of business, of which the significant actions are discussed below.

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us as part of Tex-New Mex's sale of the pipeline systems to us in 1999. The amended cross-claim also alleged that various practices employed by Tex-New Mex in the operation of its pipelines constituted gross negligence and willful misconduct and voided our obligation to indemnify Tex-New Mex for remediation of releases that occurred prior to May 1, 1999. In the Purchase and Sale Agreement, we agreed to indemnify Tex-New Mex only for certain remediation obligations that arose before May 1, 1999, unless these obligations were the result of the gross negligence or willful misconduct of Tex-New Mex prior to May 1, 1999. EOTT Energy Pipeline Limited Partnership ("PLP") and the plaintiffs agreed to a settlement during our bankruptcy proceedings. The settlement provides for the plaintiffs' release of their claims filed against PLP in this proceeding and in the bankruptcy proceedings, in exchange for an allowed general unsecured claim in our bankruptcy of $3,252,800 (as described above, the plaintiffs filed proofs of claim in our bankruptcy proceedings totaling $62 million). The allowed general unsecured claim was accrued at December 31, 2002. On April 1, 2003, we filed a second amended cross-claim in this matter. In addition to the claims filed in the previous cross-claims, we requested (i) injunctive relief for Tex-New Mex's refusal to honor its indemnity obligations; (ii) injunctive relief requiring Tex-New Mex to identify, investigate and remediate sites where the conduct alleged in our cross-claim occurred; and (iii) restitution damages of over $125,000,000. Tex-New Mex filed a motion to compel arbitration of these issues. The motion to compel arbitration was denied at a hearing held on April 11, 2003. At the April 11, 2003 hearing, the court also severed into a separate action EOTT's cross-claims against Tex-New Mex that extend beyond the crude oil release and groundwater contamination in the Kniffen Estates subdivision ("EOTT's Over-Arching Claim"). Developments in EOTT's Over-Arching Claim are described immediately below. Prior to the trial of the plaintiff's claims against Tex-New Mex and EOTT's original cross-claim against Tex-New Mex arising from the crude oil release and groundwater contamination in the Kniffen Estates subdivision ("EOTT's Kniffen Claims"), Tex-New Mex reached a settlement with the plaintiffs that provided for the release of the plaintiffs' claims. The trial of EOTT's Kniffen Claims commenced on June 16, 2003, and the jury returned its verdict on July 2, 2003. The jury found that Tex-New Mex's gross negligence and willful misconduct caused the contamination in the Kniffen Estates. The jury also found that Tex-New Mex committed fraud against us with respect to the Kniffen Estates site. The jury awarded us actual damages equal to the expenses we have incurred to date in remediating the Kniffen Estates site (approximately $6.1 million) and punitive damages in the amount of $50 million. On November 28, 2003, the court entered an amended judgment based on the jury verdict. The final judgment provides for the award to us of (i) actual damages in the amount of $7,701,938, (ii) attorney's fees in the amount of $1,400,000, (iii) prejudgment interest in the amount of $1,044,509 and (iv) punitive damages in the amount of $18,203,876. The punitive damages were reduced from the jury's award of $50 million in accordance with Texas' statutory caps on punitive damages awards. The final judgment also contains a finding that Tex-New Mex is obligated to indemnify us for future remediation costs incurred at the Kniffen Estates site. Tex-New Mex filed a motion for new trial that was overruled by operation of law on February 11, 2004. Tex-New Mex has indicated its intent to appeal the amended judgment by posting a supersedeas bond in the amount of $10,665,419 on February 12, 2004. We cannot predict the outcome of Tex-New Mex's appellate efforts.

EOTT Energy Operating Limited Partnership vs. Texas-New Mexico Pipeline Company, Cause No. CV-44, 099, In the District Court of Midland County, Texas, 238th Judicial District ("EOTT's

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Over-Arching Claim"). As described above, the claims in this lawsuit were severed from EOTT's Kniffen Claims on April 11, 2003. In this lawsuit, we allege that various practices employed by Tex-New Mex in the operation of its pipelines and handling of spills constitute gross negligence and willful misconduct, thus triggering Tex-New Mex's obligation to indemnify us for remediation of releases where such practices ("Non-Remediation Practices") were employed. In addition to damages, we are seeking (a) injunctive relief requiring Tex-New Mex to honor its indemnity obligations under the Purchase and Sale Agreement and (b) injunctive relief requiring Tex-New Mex to identify, investigate, and remediate sites where Tex-New Mex employed the Non-Remediation Practices. Discovery opened in EOTT's Over-Arching Claim on December 1, 2003. The court conducted a scheduling conference for this case on January 12, 2004, and set a trial date of September 19, 2005. On March 3, 2004, we amended our petition to specifically list more than 200 contamination sites where Tex-New Mex employed the Non-Remediation Practices.

Bankruptcy Issues related to Claims Made by Texas-New Mexico Pipeline Company and its affiliates. Tex-New Mex, Shell Oil Company ("Shell") and Equilon filed proofs of claim in our bankruptcy, each filing similar claims in the amount of $112 million. In July of 2003, we entered into an agreement with Shell, Tex-New Mex and Equilon whereby all of their claims were either withdrawn, estimated or allowed, leaving the value of the claims estimated for distribution purposes at $56,924.52. We are currently working to fully resolve these claims in the bankruptcy claims resolution process.

Jimmie T. Cooper and Betty P. Cooper vs. Texas-New Mexico Pipeline Company, Inc., EOTT Energy Pipeline Limited Partnership, and EOTT Energy Corp., Case No. CIV-03-0035 JB/LAM, In the United States District Court for the District of New Mexico. This lawsuit was filed on October 1, 2002. The plaintiffs in this lawsuit are surface interest owners of certain property located in Lea County, New Mexico. The plaintiffs alleged that aquifers underlying their property and water wells located on their property were contaminated as a result of spills and leaks from a pipeline running across their property that is or was owned by Tex-New Mex and us. The plaintiffs did not specify when the alleged spills and leaks occurred. The plaintiffs are seeking payment of costs that would be incurred in investigating and remediating the alleged crude oil releases and replacing water supplies from aquifers that had allegedly been contaminated. The plaintiffs sought damages in an unspecified amount arising from the plaintiffs' alleged fear of exposure to carcinogens and the alleged interference with the plaintiffs' quiet enjoyment of their property. The plaintiffs are also seeking an unspecified amount of punitive damages. EOTT and the plaintiffs agreed to the terms of a settlement, whereby the plaintiffs agreed to release their claims against us and received an allowed general unsecured claim in our bankruptcy in the amount of $1,027,000. The allowed general unsecured claim was accrued at December 31, 2002. The settlement documents have been finalized. On October 21, 2003, the plaintiffs filed a motion seeking our dismissal from this lawsuit. Tex-New Mex opposed this motion, and on October 31, 2003, Tex-New Mex filed a motion for leave to file a cross-claim against us. In the proposed cross-claim, Tex-New Mex is seeking a declaratory judgment finding that we are contractually obligated to indemnify Tex-New Mex for all costs Tex-New Mex has incurred or will incur related to the defense of the plaintiffs' claims in this lawsuit. The proposed cross-claim also alleges that we failed to assume Tex-New Mex's defense of this lawsuit and failed to indemnify Tex-New Mex for the expenses Tex-New Mex has incurred in this lawsuit, and that such actions by us constitute a breach of the Purchase and Sale Agreement governing Tex-New Mex's sale of the subject pipeline to us. On December 4, 2003, we filed a motion in our

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bankruptcy proceeding seeking a determination that Tex-New Mex's proposed cross-claim had been waived, barred, and discharged in our bankruptcy proceeding. A hearing on that motion (the "Zero Claim Motion") was held on February 18, 2004 and the bankruptcy court took the Zero Claim Motion under advisement. We have asked the court to delay ruling on Tex-New Mex's motion for leave to file cross-claim until the bankruptcy court rules on our Zero Claim Motion. At the settlement conference held on February 27, 2004, the plaintiffs and Tex-New Mex reached a settlement. Tex-New Mex has agreed to pay the plaintiffs $1,350,000 for a release of the plaintiffs' claims.

In re EOTT Energy Partners, L.P., Case No. 02-21730, EOTT Energy Finance Corp., Case No. 02-21731, EOTT Energy General Partner, L.L.C., Case No. 02-21732, EOTT Energy Operating Limited Partnership, Case No. 02-21733, EOTT Energy Canada Limited Partnership, Case No. 02-21734, EOTT Energy Liquids, L.P., Case No. 02-21736, EOTT Energy Corp., Case No. 02-21788, Debtors (Jointly Administered under Case No. 02-21730), In the United States Bankruptcy Court for the Southern District of Texas, Corpus Christi Division. On October 8, 2002, we and all of our subsidiaries filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the Southern District of Texas (the "EOTT Bankruptcy Court") to facilitate reorganization of our business and financial affairs for the benefit of us, our creditors and other interested parties. Additionally, the General Partner filed its voluntary petition for reorganization under Chapter 11 on October 21, 2002 in the EOTT Bankruptcy Court. Our Restructuring Plan was confirmed on February 18, 2003 and became effective on March 1, 2003. The provisions of the Restructuring Plan are further described in Note 5. Shell and Tex-New Mex filed a notice of appeal to our plan confirmation on February 24, 2003. A hearing on the appeal was held in the District Court on August 19, 2003, where the judge ruled the appeal was moot. The ruling became final on October 24, 2003. The bankruptcy remains open while we resolve all of the outstanding claims. We expect to close the bankruptcy in early 2004.

EPA Section 308 Request. In July 2001, Enron received a request for information from the Environmental Protection Agency ("EPA") under Section 308 of the Clean Water Act, requesting information regarding certain spills and releases from oil pipelines owned or operated by Enron and its affiliated companies for the time period July 1, 1998 to July 11, 2001. Enron responded in January of 2002 to the EPA's Section 308 request in its capacity as the operator of the pipelines actually owned by us and on our behalf. Under the terms of the Enron Settlement Agreement dated October 8, 2002, we would be required to indemnify EOTT Energy Corp., as the prior general partner, and its affiliates including Enron Pipeline Services Company, with regard to any environmental remediation, except for claims of gross negligence and willful misconduct. While we cannot predict the outcome of the EPA's Section 308 request, the EPA could seek to impose liability for environmental cleanup on us with respect to the matters being reviewed. The outcome of the EPA Section 308 request is not yet known, and we are unaware of any potential liability of Enron, its affiliates, or us. It is possible that our bankruptcy proceedings did not relieve us from certain potential environmental remediation liability.

Environmental. We are subject to extensive federal, state and local laws and regulations covering the discharge of materials into the environment, or otherwise relating to the protection of the environment, and which require expenditures for remediation at various operating facilities and waste disposal sites, as well as expenditures in connection with the construction of new facilities. At the

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federal level, such laws include, among others, the Clean Air Act, the Clean Water Act, the Oil Pollution Act, the Resource Conservation and Recovery Act, the Comprehensive Environmental Response, Compensation and Liability Act, and the National Environmental Policy Act, as each may be amended from time to time. Failure to comply with these laws and regulations may result in the assessment of administrative, civil, and criminal penalties or the imposition of injunctive relief.

Prior to the sale of our Liquids Operations discussed further in Note 8, we produced MTBE at our Morgan's Point Facility. MTBE is used as an additive in gasoline. Due to health concerns around MTBE, there have been lawsuits filed against companies involved in the production of MTBE. We have not been named in any such actions, nor do we anticipate being included in any such actions. However, we can provide no assurances that we may not be included in such actions due to our past production of MTBE.

In 2001, expenses incurred for spill clean up and remediation costs related to the assets purchased from Tex-New Mex increased significantly. Based on our experience with these assets, we filed an amended cross-claim against Tex-New Mex alleging contingent claims for potential remediation issues not yet known to us. We allege that Tex-New Mex failed to report spills, underreported spills, failed to properly respond to leaks in the pipeline and engaged in other activities with regard to the pipeline that may result in future remediation liabilities. We obtained $20 million in insurance coverage in connection with the acquisition from Tex-New Mex believing that amount would be sufficient to cover our remediation requirements along the pipeline for a ten-year period. However, after four years into the term of the insurance policy, we have made claims in excess of the amount of insurance coverage.

In addition to costs associated with the assets acquired from Tex-New Mex, we have also incurred spill clean up and remediation costs in connection with other properties we own in various locations throughout the United States. We also have insurance covering clean up and remediation costs that may be incurred in connection with properties not acquired from Tex-New Mex. However, no assurance can be given that the insurance will be adequate to cover any such cleanup and remediation costs.

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The following are summaries of environmental remediation expense, estimated environmental liabilities, and amounts receivable under insurance policies for the indicated periods (in thousands):

	Successor Company			Predecessor Company
	Ten Months ended December 31, 2003			Two Months ended February 28, 2003			Twelve Months ended December 31, 2002			Twelve Months ended December 31, 2001
Remediation expense	$	9,107		$	1,979		$	14,819		$	25,372
Estimated insurance recoveries		(1,325	)		(79	)		(1,316	)		(13,576	)

Net remediation expense	$	7,782		$	1,900		$	13,503		$	11,796

	Successor Company			Predecessor Company
	Ten Months ended December 31, 2003			Two Months ended February 28, 2003			Year ended December 31, 2002
Environmental liability at beginning of period	$	13,440		$	13,440		$	12,075
Remediation expense		9,107			1,979			14,819
Cash expenditures		(10,331	)		(1,979	)		(13,454	)

Environmental liability at end of period	$	12,216		$	13,440		$	13,440

	Successor Company			Predecessor Company
	Ten Months ended December 31, 2003			Two Months ended February 28, 2003			Year ended December 31, 2002
Environmental insurance receivable at beginning of period	$	8,837		$	8,803		$	14,344
Estimated recoveries		1,325			79			1,316
Cash receipts		(7,073	)		(45	)		(6,857	)

Environmental insurance receivable at end of period	$	3,089		$	8,837		$	8,803

The environmental liability was classified in Other Current ($6.4 million) and Other Long-Term Liabilities ($5.8 million) and the insurance receivable was classified in Trade and Other Receivables ($2.5 million) and Other Assets ($0.5 million) at December 31, 2003.

We may experience future releases of crude oil into the environment or discover releases that were previously unidentified. While an inspection program is maintained on our pipelines to prevent and detect such releases, and operational safeguards and contingency plans are in place for the operation of our processing facilities, damages and liabilities incurred due to any future environmental releases could affect our business. We believe that our operations and facilities are in substantial compliance with applicable environmental laws and regulations and that there are no outstanding potential liabilities or claims relating to safety and environmental matters of which we are currently aware, the resolution of which, individually or in the aggregate, would have a materially adverse effect on our

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financial position or results of operations. However, we could be significantly adversely impacted by additional repair or remediation costs related to the pipeline assets we acquired from Tex-New Mex if the need for any additional repairs or remediation arises and we do not obtain reimbursement for any such costs as a result of the pending litigation concerning those assets. Our environmental expenditures include amounts spent on permitting, compliance and response plans, monitoring and spill cleanup and other remediation costs. In addition, we could be required to spend substantial sums to ensure the integrity of our pipeline systems, and in some cases, we may take pipelines out of service if we believe the costs of upgrades will exceed the value of the pipelines.

No assurance can be given as to the amount or timing of future expenditures for environmental remediation or compliance, and actual future expenditures may be different from the amounts currently estimated. In the event of future increases in costs, we may be unable to pass on those increases to our customers.

Tax Status

For information regarding our continued qualification as a partnership for federal income tax purposes, see Note 1.

16. FAIR VALUE OF FINANCIAL INSTRUMENTS

Fair Value. Fair value represents the amount at which a financial instrument could be exchanged in a current transaction between willing parties. We have determined the estimated fair value amounts using available market data and valuation methodologies. Judgment is required in interpreting market data and the use of different market assumptions or estimation methodologies may affect the estimated fair value amounts.

As of December 31, 2003 and 2002, the carrying amounts of items comprising current assets and current liabilities approximate fair value due to the short-term maturities of these instruments. The carrying amounts of the variable rate instruments in our credit facilities approximate fair value because the interest rates fluctuate with prevailing market rates. The carrying amount of our derivative instruments and energy trading activities approximate fair value as these contracts are recorded on the balance sheet at their fair value.

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The carrying amount and fair values of our financial instruments are as follows (in millions):

		Successor Company December 31, 2003				Predecessor Company December 31, 2002
		Carrying Amount		Fair Value		Carrying Amount			Fair Value
NYMEX futures		$	—	$	—	$	0.2		$	0.2
Forward contracts		$	0.5	$	0.5	$	(1.0	)	$	(1.0	)
Short-term debt		$	45.0	$	45.0	$	125.0		$	125.0
Term loans		$	75.0	$	75.0	$	75.0		$	75.0
Enron Note		$	6.4	$	6.5	$	6.2		$	7.2
Long-term
	9% Notes	$	104.5	$	101.4	$	6.2		$	7.2
	11% Notes	$	—	$	—	$	235.0		$	N/A
Long-term debt—other		$	2.3	$	2.4	$	2.7		$	2.4

As of December 31, 2002, it was not practicable to determine the fair value of our 11% senior unsecured notes since we were not yet able to determine the fair value of the consideration the senior unsecured noteholders would receive under the Restructuring Plan. Under the terms of our Restructuring Plan, we cancelled our 11% senior notes and the former senior unsecured noteholders and holders of allowed general unsecured claims received a pro rata share of $104 million of 9% senior unsecured notes and a pro rata share of 11,947,820 Link LLC units. Excluding amounts included in Liabilities Subject to Compromise at December 31, 2002, we believe that the carrying amounts of other financial instruments are a reasonable estimate of their fair value, unless otherwise noted.

Generally, as we purchase crude oil, we enter into corresponding sales transactions involving physical delivery of crude oil to third party users or corresponding sales transactions on the NYMEX. This process enables us to minimize our exposure to price risk until we take physical delivery of the crude oil. In 2002, substantially all of our crude oil marketing and trading operations are accounted for on a fair value basis pursuant to SFAS No. 133 or EITF Issue 98-10. Effective January 1, 2003, energy trading contracts that are not derivative instruments pursuant to SFAS No. 133 are no longer accounted for at fair value. See further discussion of our accounting policies in Note 2.

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The following table indicates fair values and changes in fair value of our energy trading and derivative transactions (in thousands):

	Successor Company			Predecessor Company
	Ten Months ended December 31, 2003			Two Months ended February 28, 2003			Year ended December 31, 2002
Fair value of contracts at beginning of period	$	1,254		$	(844	)	$	(5,597	)
Cumulative effect of accounting change		—			(2,389	)		—
Change in realized and unrealized value		(2,401	)		4,114			3,814
Fair value of new contracts entered into during year.		1,673			373			939

Fair value of contracts at end of period	$	526		$	1,254		$	(844	)

Fair Value of Contracts at December 31, 2003

Source of Fair Value	Maturity of 90 Days or Less		Maturity Greater than 90 Days but Less than One Year			Total Fair Value
Prices Actively Quoted	$	677	$	(162	)	$	515
*Prices Provided by Other External Source		13		(2	)		11

Total	$	690	$	(164	)	$	526

*: In determining the fair value of certain contracts, adjustments may be made to published posting data, for location differentials and quality basis adjustments.

Credit Risk. In the normal course of business, we extend credit to various companies in the energy industry. Within this industry, certain elements of credit risk exist and may, to varying degrees, exceed amounts recognized in the accompanying consolidated financial statements, which may be affected by changes in economic or other external conditions and may accordingly impact our overall exposure to credit risk. Our exposure to credit loss in the event of nonperformance is limited to the book value of the trade commitments included in the accompanying Consolidated Balance Sheets. We manage our exposure to credit risk through credit analysis, credit approvals, credit limits and monitoring procedures. Further, we believe that our portfolio of receivables is well diversified and that the allowance for doubtful accounts is adequate to absorb any potential losses. We require collateral in the form of letters of credit for certain of our receivables.

During the ten months ended December 31, 2003, the two months ended February 28, 2003 and the years ended December 31, 2002, and 2001 sales to Koch Supply & Trading L.P. accounted for approximately 19%, 19%, 17%, and 12% of our consolidated gross revenues, respectively.

Market Risk. Our trading and non-trading transactions give rise to market risk, which represents the potential loss that can be caused by a change in the market value of a particular commitment. We closely monitor and manage our exposure to market risk to ensure compliance with our stated risk

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management policies which are regularly assessed to ensure their appropriateness given our objectives, strategies and current market conditions.

We enter into forward, futures and other contracts to hedge the impact of market fluctuations on assets, lease crude oil purchases or other contractual commitments. Changes in the market value of transactions designated as energy trading activities (prior to the rescission of EITF Issue 98-10) or derivatives under SFAS 133 are recorded every period as mark-to-market gains or losses.

17. SUMMARY OF OUR SETTLEMENT AGREEMENT WITH ENRON

The General Partner and EOTT entered into a settlement agreement dated October 8, 2002 (the "Enron Settlement Agreement") with Enron, Enron North America Corp., Enron Energy Services, Inc., Enron Pipeline Services Company ("EPSC"), EGP Fuels Company ("EGP Fuels") and Enron Gas Liquids, Inc. ("EGLI") (collectively, the "Enron Parties"). As part of the Settlement Agreement, Enron consented to the filing of our bankruptcy in the Southern District of Texas, and Enron waived its rights of first refusal with respect to the sale of the Morgan's Point Facility, Mont Belvieu Facility and other assets we purchased pursuant to the Purchase and Sale Agreement dated June 29, 2001 between Enron and us. The EOTT Bankruptcy Court approved the Enron Settlement Agreement on November 22, 2002, and the Enron Bankruptcy Court approved the Enron Settlement Agreement on December 5, 2002. The Enron Settlement Agreement was consummated on December 31, 2002. The following is a summary of the significant terms of the settlement:

•: We entered into an Employee Transition Agreement with EPSC, which provided for the transfer to us of certain employees of subsidiaries of Enron which performed pipeline operations services for us, effective January 1, 2003.
•: The Enron Parties and us entered into a Termination Agreement on October 8, 2002, which provided for the termination of various agreements among the parties.
•: At December 31, 2002, we executed a promissory note payable to Enron in the initial principal amount of $6.2 million that is guaranteed by our subsidiaries. The Enron Note is secured by an irrevocable letter of credit and bears interest at 10% per annum.
•: As additional consideration and as a compromise of certain claims, we paid Enron $1,250,000 (the "Cash Payment") on the effective date of our Restructuring Plan.
•: We agreed, among other things, to assume obligations in our bankruptcy cases and cure defaults under the Operation and Service Agreement with EPSC whereby EPSC provided certain pipeline operation services to us. We also agreed to indemnify EPSC against claims arising from the General Partner's failure to perform its duties under the Operation and Services Agreement or the General Partner's refusal to approve EPSC recommended items or modifications in the budgets.
•: We and the Enron Parties also mutually released each other for any and all claims except those expressly reserved in the Enron Settlement Agreement.

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The following is a summary of the net Enron Settlement amount recorded in Reorganization Items in the Consolidated Statement of Operations (in millions) as discussed in Note 5:

Forgiveness of payable to Enron and affiliates		$	38.5
Forgiveness of performance collateral from Enron			15.8
Note issued to Enron			(6.2	)
Cash Payment to Enron for certain claims			(1.2	)
Final contribution to Enron Cash Balance Plan			(1.4	)
	Total	$	45.5

18. IMPACT OF ENRON BANKRUPTCY AND TRANSACTIONS WITH ENRON AND RELATED PARTIES

IMPACT OF ENRON BANKRUPTCY

Beginning on December 2, 2001, Enron, along with certain of its subsidiaries, filed bankruptcy proceedings under Chapter 11 of the Federal Bankruptcy Code. Because of our contractual relationships with Enron and certain of its subsidiaries, the bankruptcy significantly impacted us in various ways. In connection with the Enron Settlement Agreement discussed above, the following claims were released:

Rejection of Agreements; Claims Against Enron's Bankruptcy Estate. We were adversely impacted as a result of the inclusion of EGLI in Enron's bankruptcy. We had in place ten-year Toll Conversion and Storage Agreements with EGLI. As a result of EGLI's non-performance under these agreements, we recorded a $29.1 million non-cash impairment, which was our remaining investment in these long-term contracts, at December 31, 2001. We had a monetary damage claim against EGLI and Enron as a result of the rejection of the agreements under the Stipulation. Accordingly, we filed claims against EGLI in the Enron Bankruptcy Court on May 12, 2002, resulting from EGLI's rejection of the Toll Conversion and Storage Agreements, in the amount of $540.5 million. In addition, Enron guaranteed EGLI's performance under the EGLI agreements; however, its guarantee was limited to $50 million under the Toll Conversion Agreement and $25 million under the Storage Agreement. Accordingly, we filed a claim against Enron in the Enron Bankruptcy Court resulting from EGLI's rejection of the agreements in the amount of $75 million. We filed additional claims against numerous Enron affiliates on October 15, 2002 totaling $213.5 million. Under the terms of the Enron Settlement Agreement, we withdrew all claims filed by us in the Enron Bankruptcy Court upon the effective date of our Restructuring Plan.

Performance Collateral from Enron. As discussed above, Enron guaranteed payments under the Toll Conversion and Storage Agreements. In addition, EGLI owed us approximately $9 million under the Toll Conversion and Storage Agreements prior to filing for bankruptcy. Pursuant to the Toll Conversion and Storage Agreements, if Enron's credit rating dropped below certain defined levels specified in these agreements, we could request within five days of this occurrence for EGLI to post letters of credit. The letters of credit could be drawn upon if EGLI failed to pay any amount owed to us under these agreements. The Toll Conversion Agreement provided that the letter of credit would be in an amount reasonably requested by us, not to exceed $25 million. The Storage Agreement provided

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that the letter of credit would be in an amount as reasonably requested, but no amount is specified. In late November 2001, Enron's credit rating fell below the ratings specified in these agreements. Accordingly, on November 27, 2001, we requested that EGLI post two $25 million letters of credit. In lieu of posting letters of credit, we received a $25 million deposit/performance collateral from EGLI/Enron, against which we recouped the $9 million of outstanding invoices. We applied the remaining sum, approximately $16 million, to recoup or offset a portion of our damages as a result of EGLI's rejection of the Toll Conversion and Storage Agreements. Our Restructuring Plan resulted in a release by Enron of any claim to the $25 million deposit/performance collateral.

Tax and Environmental Indemnities. We also had indemnities from Enron for certain ad valorem taxes, possible environmental expenditures and title defects relating to the Morgan's Point Facility and the Mont Belvieu Facility. The total indemnity amount provided for under the Purchase Agreement was $25 million and we had made no claims under the indemnities through December 31, 2002. Under the terms of the Enron Settlement Agreement, we released Enron from these indemnities.

Pension Plan Underfunding Issues. The Enron Settlement Agreement provided that we withdraw from the defined benefit pension plan known as the Enron Corp. Cash Balance Plan (the "Cash Balance Plan") on December 31, 2002. The PBGC filed proofs of claim in our bankruptcy proceedings to address concerns about the Cash Balance Plan, and also an objection to our Restructuring Plan ("PBGC Claim").

To address the issues raised by the PBGC, as well as the objections we filed to the PBGC's proofs of claim, a Stipulation and Order Regarding EOTT Chapter 11 Proceedings and Settlement Among the Enron Parties, us and the PBGC (the "PBGC Stipulation") was executed and entered by the Enron Bankruptcy Court on February 27, 2003.

The PBGC Stipulation set forth that Enron will continue to hold, subject to the terms of the PBGC Stipulation, the Enron Note, the letter of credit securing the Enron Note, any payments thereunder, and the Cash Payment (collectively, the "Settlement Proceeds") on behalf of the Enron Parties. Any claim of the PBGC against us for liabilities (if any) arising from the Cash Balance Plan will attach to the Settlement Proceeds with the same effect (if any) that such claim (if any) now has as against us and such claim will be subject to the claims and defenses of the Enron Parties and the Enron Creditors' Committee with respect thereto. The PBGC's rights regarding the Settlement Proceeds will constitute the sole basis for the PBGC to seek to enforce its claims (if any) against us for the PBGC Claims.

TRANSACTIONS WITH ENRON AND RELATED PARTIES

At December 31, 2002, we had current payables to Enron of $3.6 million, which was primarily comprised of certain amounts owed to Enron under the Enron Settlement Agreement. In addition, we had $5.2 million of long-term liabilities owed to Enron at December 31, 2002, which is the long-term portion of the note issued in connection with the Enron Settlement Agreement.

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The agreements described below were terminated and the amounts due under these agreements were forgiven effective December 31, 2002 under the terms of the Enron Settlement Agreement. See further discussion in Note 17.

Operations and General and Administrative Services. As is commonly the case with publicly traded partnerships, we did not directly employ any persons responsible for managing or operating EOTT or for providing services relating to day-to-day business affairs prior to January 1, 2003. The General Partner provided such services or obtained such services from third parties and we were responsible for reimbursing the General Partner for substantially all of its direct and indirect costs and expenses. The General Partner, through the MLP Partnership Agreement, provided services to us under a Corporate Services Agreement which included liability and casualty insurance and certain data processing services and employee benefits. Those costs were $1.9 million, and $2.5 million, for the years ended December 31, 2002 and 2001, respectively.

Operation and Services Agreement with EPSC. EPSC agreed to provide certain operating and administrative services to the General Partner, effective October 1, 2000 and the agreement provided that the General Partner would reimburse EPSC for its costs and expenses in rendering the services. The General Partner would in turn be reimbursed by us. EOTT LLC took over these services effective January 1, 2003. The costs incurred related to these services for the years ended December 31, 2002 and 2001 were $24.6 million, and $56.7 million respectively.

Transition Services Agreement with EGP Fuels. The General Partner entered into an agreement for EGP Fuels to provide transition services through December 31, 2001 for the processing of invoices and payments to third parties related to the Morgan's Point Facility and Mont Belvieu Facility. The agreement provided that the General Partner would reimburse EGP Fuels for these direct costs and we would reimburse the General Partner. Costs related to these services were $12.3 million for the six months ended December 31, 2001.

Credit Facility. We had a credit facility with Enron to provide credit support in the form of guarantees, letters of credit and working capital loans through December 31, 2001.

Purchase and Sale Agreement. We acquired certain liquids processing, storage and transportation assets in June 2001 from Enron. See further discussion in Note 8.

Additional Partnership Interests. On May 14, 1999 and February 14, 2000, Enron paid $2.5 million and $6.8 million, respectively, in support of our first and fourth quarter 1999 distributions to our common unitholders and received APIs. APIs have no voting rights and do not receive distributions. In connection with the Restructuring Plan, the API's were cancelled.

19. EMPLOYEE BENEFIT AND RETIREMENT PLANS

Successor Company

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March 2003 for all employees. Total benefit costs for the ten months ended December 31, 2003 were $4.6 million, including $4.3 million in costs attributable to health and welfare benefit plans.

In 2003, we adopted the Link Energy Annual Incentive Plan, a variable pay plan, based on our earnings before depreciation adjusted for restructuring costs. No bonuses were paid out under this plan for 2003.

We provide no postretirement medical, life insurance and dental benefits to employees who retire. The Company provides unemployment, severance and disability-related benefits or continuation of benefits such as health care and life insurance and other postemployment benefits. SFAS No. 112 requires the cost of those benefits to be accrued over the service lives of the employees expected to receive such benefits. At December 31, 2003, the liability accrued was $0.9 million.

The Compensation Committee recommended to the Board of Directors the adoption of the Link Energy Equity Incentive Plan ("Incentive Plan") effective June 2003. The Incentive Plan is designed to promote individual performance by relating executive compensation directly to the creation of unitholder wealth. Under the Incentive Plan, the Committee is authorized to grant awards of restricted units to executive officers and other key employees. In June 2003, 1.2 million restricted stock units were authorized to be issued to certain key employees and directors. The Incentive Plan has a ten-year term and restricted unit awards granted thereunder typically vest over a three-year period. Outstanding awards have a vesting schedule of 50% vested on June 1, 2004; 25% vested on June 1, 2005 and 25% vested on June 1, 2006. We have recorded compensation expense of $2.3 million for the ten months ended December 31, 2003.

The following table sets forth the Equity Incentive Plan activity for the ten months ended December 31, 2003:

		Number of Restricted Units
Outstanding at March 1, 2003		—
	Granted	875,000
	Forfeited	(45,000	)

Outstanding at December 31, 2003		830,000
Available for grant at December 31, 2003		370,000

Predecessor Company

We adopted welfare benefit plans providing medical, dental, life, accidental death and dismemberment and long-term disability coverage to employees, with all related premiums and costs not offset by employee contributions being incurred by us. Total benefit costs for the two months ended February 28, 2003 were $1.3 million, including $1.1 million in costs attributable to health and welfare benefit plans. Total benefit costs for 2002 were $8.9 million, including $6.3 million in costs attributable to health and welfare benefit plans. Total benefit costs for 2001 were $6.7 million, including $4.6 million in cost attributable to health and welfare benefit plans. Through December 31, 2002, employees of the Company were covered by various retirement, stock purchase and other benefit plans of Enron.

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In 2002, we accrued $2.1 million in connection with guaranteed bonuses and retention payments. In 2001, the Company maintained a variable pay plan based on our earnings before interest and depreciation and amortization pursuant to which $3.6 million was recorded.

As discussed in Note 18, we were a participating employer in the Cash Balance Plan until the consummation of the Enron Settlement Agreement on December 31, 2002. See Note 18 for further discussion regarding issues raised by the PBGC concerning this plan and an agreed stipulation executed between the PBGC, the Enron Parties and us.

Prior to December 31, 2002, we provided certain postretirement medical, life insurance and dental benefits to eligible employees who retired after January 1, 1994. Benefits were provided under the provisions of contributory defined dollar benefit plans for eligible employees and their dependents. We terminated our participation in this plan effective December 31, 2002. These postretirement benefit costs were accrued over the service lives of employees expected to be eligible to receive such benefits. Enron retained liability for former employees of the Company who retired prior to January 1, 1994. In connection with the termination, curtailment and settlement gains of $1.5 million were recorded in 2002.

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The following table sets forth information related to changes in the benefit obligations, changes in plan assets, and components of the expense recognized related to postretirement benefits provided by the Company (in thousands):

		2002
CHANGE IN BENEFIT OBLIGATION
Benefit obligation at January 1		$	1,103
	Service cost		144
	Interest cost		137
	Plan participants' contributions		76
	Plan amendments		7
	Actuarial loss (gain)		895
	Effect of curtailments		(1,815	)
	Effect of settlements		(380	)
	Benefits paid		(167	)
	Benefit obligation at December 31	$	—
CHANGE IN PLAN ASSETS
Fair value of plan assets at January 1		$	—
	Company contributions		91
	Plan participants' contributions		76
	Benefits paid		(167	)
	Fair value of plan assets at December 31	$	—

		2002			2001
Service cost		$	144		$	99
Interest cost			137			73
Amortization of prior service cost			24			24
Recognized net actuarial gain			5			(29	)

Net periodic postretirement benefit cost			310			167
Effect of curtailments			(1,160	)		—
Effect of settlements			(380	)		—
	Total benefit cost (credit)	$	(1,230	)	$	167

We provided unemployment, severance and disability-related benefits or continuation of benefits such as health care and life insurance and other postemployment benefits. SFAS No. 112 requires the cost of those benefits to be accrued over the service lives of the employees expected to receive such benefits. At December 31, 2002, the liability accrued was $1.2 million.

EOTT Energy Corp. Unit Option Plan. In February 1994, the Board of Directors adopted the 1994 EOTT Energy Corp. Unit Option Plan (the "Unit Option Plan"), which was a variable compensatory plan. To date, no compensation expense has been recognized under the Unit Option Plan. Under the Unit Option Plan, selected employees were granted options to purchase subordinate units at a price of $15.00 per unit as determined by the Compensation Committee of the Board of Directors. Options

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granted under the Unit Option Plan vested to the employees over a five-year period and expired on the tenth anniversary of the date of grant. Under the Restructuring Plan, the Unit Option Plan was terminated on February 28, 2003.

Unit Option Plan activity for the years ended December 31, 2001 and 2002, and the two months ended February 28, 2003, consisted of forfeitures of 5,000 shares, 240,000 shares and 215,000 shares, respectively. No shares were outstanding or available for grant at February 28, 2003.

EOTT Energy Corp. Long-Term Incentive Plan. In October 1997, the Board of Directors adopted the EOTT Energy Corp. Long-Term Incentive Plan ("Plan"), which was a variable compensatory plan. Under the Plan, selected key employees were awarded Phantom Appreciation Rights ("PAR"). Each PAR was a right to receive cash based on our performance prior to the time the PAR was redeemed. Our performance was measured primarily by calculating the change in the average of Earnings Before Interest on Debt related to acquisitions, Depreciation and Amortization ("EBIDA"), for each of the three consecutive fiscal years immediately preceding the grant date of the PAR and the exercise date of the PAR. The Plan had a five-year term beginning January 1, 1997, and PAR awards vested in 25% increments in the four-year period following the grant year. Under the Restructuring Plan, the Long-Term Incentive Plan was terminated on February 28, 2003.

The following table sets forth the Long-Term Incentive Plan activity for the two months ended February 28, 2003 and the years ended December 31, 2002 and 2001:

		Number Of PARs
		Two Months Ended February 28, 2003	Year Ended December 31,
		Two Months Ended February 28, 2003	2002	2001
Outstanding beginning of period		274,394	1,067,375	939,975
	Granted	—	—	332,000
	Exercised	—	684,831	106,250
	Forfeited	274,394	108,150	98,350

Outstanding at end of period		—	274,394	1,067,375

Available for grant at end of period		—	—	—

Note: PARs were not available for grant after December 31, 2001 as the term of the plan expired December 31, 2001.

20. NEW ACCOUNTING STANDARDS

Accounting Standards Adopted

In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations." This statement requires entities to record the fair value of a liability for legal obligations associated with the retirement obligations of tangible long-lived assets in the period in which it is incurred. When the liability is initially recorded, a corresponding increase in the carrying value of the related long-lived asset would be recorded. Over time, accretion of the liability is recognized each period, and the

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capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss on settlement. We adopted the accounting principle required by the new statement effective January 1, 2003. Determination of the fair value of the retirement obligation is based on numerous estimates and assumptions including estimated future third-party costs, future inflation rates and the future timing of settlement of the obligations.

At the time of adoption of the new standard, our long-lived assets consisted primarily of our crude oil gathering and transmission pipelines and associated field storage tanks, our liquids processing and handling facilities at Morgan's Point, our underground storage facility and associated pipeline grid system, and transportation facilities at Mont Belvieu and our gas processing and fractionation plant and related storage and distribution facilities on the West Coast. Since our initial adoption of this standard, a number of these assets have been sold.

We identified asset retirement obligations that are within the scope of the new statement, including contractual obligations included in certain right-of-way agreements, easements and surface leases associated with our crude oil gathering, transportation and storage assets and obligations pertaining to closure and/or removal of facilities and other assets associated with our Morgan's Point, Mont Belvieu and West Coast facilities. We have estimated the fair value of asset retirement obligations based on contractual requirements where the settlement date is reasonably determinable. We could not make reasonable estimates of the fair values of certain retirement obligations, principally those associated with certain right-of-way agreements and easements for our pipelines, our Morgan's Point, Mont Belvieu and West Coast facilities, because the settlement dates for the retirement obligations cannot be reasonably determined. We will record retirement obligations associated with these assets in the period in which sufficient information exists to reasonably estimate the settlement dates of the respective retirement obligations.

As a result of the adoption of SFAS 143 on January 1, 2003, we recorded a liability of $1.7 million, property, plant and equipment, net of accumulated depreciation of $0.1 million and a cumulative effect of a change in accounting principle of $1.6 million. The effect of adoption of the new accounting principle was not material to the results of operations for the two months ended February 28, 2003, nor would it have had a material impact on our net income for the years ended December 31, 2002 or 2001. The asset retirement obligation as of January 1, 2002 was not material.

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In September 2003, we recorded additional asset retirement obligations resulting from the planned reduction in our operations at the Morgan's Point Facility to phase out the production of MTBE. Such obligations have been settled at December 31, 2003. The following is a roll-forward of our asset retirement obligations for the two months ended February 28, 2003 and for the ten months ended December 31,2003:

	Successor Company			Predecessor Company
	Ten Months ended December 31, 2003			Two Months ended February 28, 2003
Balance at beginning of period	$	1,678		$	—
Additions to liability		1,525			1,675
Accretion expense		13			3
Liabilities settled		(1,403	)		—
Revisions to estimates		—			—

Balance at end of period	$	1,813		$	1,678

In October 2002, the EITF reached a consensus in EITF Issue 02-03 to rescind Issue EITF 98-10, and related interpretive guidance, and preclude mark to market accounting for energy trading contracts that are not derivative instruments pursuant to SFAS 133. The consensus requires that gains and losses (realized and unrealized) on all derivative instruments held for trading purposes be shown net in the income statement, whether or not the instrument is settled physically. The consensus to rescind EITF Issue 98-10 eliminated our basis for recognizing physical inventories at fair value. The consensus to rescind EITF Issue 98-10 was effective for all new contracts entered into (and physical inventory purchased) after October 25, 2002. For energy trading contracts and physical inventories that existed on or before October 25, 2002, that remained at December 31, 2002, the consensus was effective January 1, 2003 and was reported as a cumulative effect of a change in accounting principle. The cumulative effect of the accounting change on January 1, 2003 was a loss of $2.4 million. With the rescission of EITF Issue 98-10, inventories purchased after October 25, 2002 have been valued at average cost.

In January 2003, the FASB issued FASB Interpretation No. 46, "Consolidation of Variable Interest Entities—an Interpretation of ARB No. 51" ("FIN 46"). FIN 46 is an interpretation of Accounting Research Bulletin 51, "Consolidated Financial Statements", and addresses consolidation by business enterprises of variable interest entities ("VIE"). FIN 46 requires an enterprise to consolidate a VIE if that enterprise has a variable interest that will absorb a majority of the entity's expected losses if they occur, receive a majority of the entity's expected residual returns if they occur, or both. This guidance applies immediately to VIE's created after January 31, 2003, and to VIE's in which an enterprise obtains an interest after that date. We implemented FIN 46 effective with the adoption of fresh start reporting on March 1, 2003. This statement did not have any impact on our financial statements.

In April 2003, the FASB issued SFAS 149, "Amendment of Statement 133 on Derivative Instrument and Hedging Activities." The statement amends and clarifies accounting for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging

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activities under SFAS 133. The new statement is effective for contracts entered into or modified after June 30, 2003 (with certain exceptions) and for hedging relationships designated after June 30, 2003. The accounting guidance in the new statement is to be applied prospectively. We implemented SFAS 149 effective with the adoption of fresh start reporting on March 1, 2003. This statement did not have any impact on our financial statements.

In May 2003, the FASB issued SFAS 150, "Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity." This statement establishes standards for how a company classifies and measures certain financial instruments with characteristics of both liabilities and equity. This statement is effective for financial instruments entered into or modified after May 31, 2003 and otherwise is effective at the beginning of the first interim period beginning after June 15, 2003. The statement will be implemented by reporting the cumulative effect of a change in accounting principle for financial instruments created before the issuance date of the statement and still existing at the beginning of the period of adoption. We implemented SFAS 150 effective with the adoption of fresh start reporting on March 1, 2003. The adoption of this statement did not have any impact on our financial statements.

Accounting Standards Not Yet Adopted

In December 2003, the FASB issued FASB Interpretation No. 46 (revised December 2003), "Consolidation of Variable Interest Entities—an Interpretation of ARB No.51" ("FIN 46R"). FIN 46R replaces FIN 46 (discussed above) which we implemented effective with the adoption of fresh start reporting on March 1, 2003. FIN 46R is required to be implemented by the end of the first reporting period beginning after December 15, 2003. We plan to adopt FIN 46R effective January 1, 2004. Adoption of FIN 46R will not have an impact on our financial statements.

21. BUSINESS SEGMENT INFORMATION

We have two reportable segments, which management reviews in order to make decisions about resources to be allocated and assess performance: North American Crude Oil and Pipeline Operations. The North American Crude Oil segment primarily purchases, gathers, transports and markets crude oil. The Pipeline Operations segment operates approximately 6,900 miles of active common carrier pipelines in 12 states. Effective December 31, 2003, we sold our Liquids Operations and therefore the results of operations related to these assets have been reclassified to discontinued operations for all periods presented herein. Effective June 30, 2001, we sold our West Coast crude oil gathering and marketing operations. Effective June 1, 2002, we sold our West Coast refined products marketing operations. Effective June 25, 2003, we signed a definitive agreement to sell all of our natural gas liquids assets on the West Coast, which subsequently closed on October 1, 2003. The results of operations related to these assets previously included in the West Coast Operations segment have been reclassified to discontinued operations for all periods presented herein.

The accounting policies of the segments are the same as those described in the summary of significant accounting policies as discussed in Note 2. We evaluate performance based on operating income (loss).

F-151

FINANCIAL INFORMATION BY BUSINESS SEGMENT (IN THOUSANDS)

		North American Crude Oil			Pipeline Operations		Corporate and Other(a)			Consolidated
TEN MONTHS ENDED DECEMBER 31, 2003 (SUCCESSOR COMPANY) (RESTATED)
Revenue from external customers		$	136,268		$	16,765	$	—		$	153,033
Intersegment revenue(b)			(17,731	)		71,605		(53,874	)		—
	Total operating revenue(c)		118,537			88,370		(53,874	)		153,033

Gross profit (loss)			13,231			28,698		—			41,929

Operating income (loss)			5,001			30,504		(25,690	)		9,815
Other expenses, net			—			—		(32,516	)		(32,516	)

Income (loss) from continuing operations			5,001			30,504		(58,206	)		(22,701	)

Long-lived assets of continuing operations.			62,530			199,719		261			262,510

Total assets			516,849			206,773		15,022			738,644

Additions to long-lived assets-continuing operations			858			7,265		175			8,298

Depreciation and amortization			2,150			14,989		22			17,161

		North American Crude Oil			Pipeline Operations		Corporate and Other(a)			Consolidated
TWO MONTHS ENDED FEBRUARY 28, 2003 (PREDECESSOR COMPANY) (RESTATED)
Revenue from external customers		$	27,213		$	4,422	$	—		$	31,635
Intersegment revenue(b)			(1,768	)		11,828		(10,060	)		—

	Total operating revenue(c)		25,445			16,250		(10,060	)		31,635

Gross profit (loss)			3,752			6,219		—			9,971

Operating income (loss)			2,365			4,261		(4,012	)		2,614
Other income, net			—			—		(5,489	)		(5,489	)
Reorganization items, net gain on discharge of debt and fresh start adjustments(d)			—			—		67,459			67,459

Income (loss) from continuing operations			2,365			4,261		57,958			64,584

Long-lived assets of continuing operations			75,046			209,476		476			284,998

Total assets			505,965			226,646		123,511			856,122

Additions to long-lived assets-continuing operations			8			108		—			116

Depreciation and amortization			837			3,286		519			4,642

F-152

		North American Crude Oil			Pipeline Operations		Corporate and Other^(a)			Consolidated
YEAR ENDED DECEMBER 31, 2002 (PREDECESSOR COMPANY) (RESTATED)
Revenue from external customers		$	154,608		$	28,324	$	—		$	182,932
Intersegment revenue^(b)			(11,320	)		79,008		(67,688	)		—

	Total operating revenue^(c)		143,288			107,332		(67,688	)		182,932

Gross profits			3,396			33,634		—			37,030

Operating income (loss)			(13,861	)		14,797		(28,531	)		(27,595	)
Other expense			—			—		(45,793	)		(45,793	)
Reorganization items^(d)			—			—		32,847			32,847

Income (loss) from continuing operations before cumulative effect of accounting changes^(d)			(13,861	)		14,797		(41,477	)		(40,541	)

Long-lived assets of continuing operations			71,282			261,975		7,802			341,059

Total assets			475,889			285,990		110,360			872,239

Additions to long-lived assets-continuing operations			1,158			15,494		136			16,788

Depreciation and amortization			5,740			20,881		3,267			29,888

		North American Crude Oil			Pipeline Operations		Corporate and Other^(a)			Consolidated
YEAR ENDED DECEMBER 31, 2001 (PREDECESSOR COMPANY) (RESTATED)
Revenue from external customers		$	226,564		$	24,007	$	—		$	250,571
Intersegment revenue^(b)			(15,673	)		103,515		(87,842	)		—

	Total operating revenue^(c)		210,891			127,522		(87,842	)		250,571

Gross profits			25,213			56,438		—			81,651

Operating income (loss)			9,742			49,715		(24,848	)		34,609
Other expense			—			—		(34,561	)		(34,561	)

Income (loss) from continuing operations before cumulative effect of accounting changes^(d)			9,742			49,715		(59,409	)		48

Long-lived assets of continuing operations			75,703			266,806		11,544			354,053

Total assets			629,199			295,793		180,506			1,105,498

Additions to long-lived assets-continuing operations			3,844			16,500		2,140			22,484

Depreciation and amortization			6,010			21,792		3,083			30,885

^(a): Corporate and Other also includes intersegment eliminations.

F-153

^(b): Intersegment sales for North American Crude Oil are made at prices comparable to those received from external customers. Intersegment sales for Pipeline Operations are based on published pipeline tariffs.
^(c): In connection with the adoption of EITF Issue 02-03, we have presented all purchase and sale transactions related to our crude oil marketing and trading activities on a net basis.
^(d): The two months ended February 28, 2003 include a gain from reorganization items of $7.3 million, a gain on discharge of debt of $131.6 million and a loss related to fresh start adjustments of $56.8 million. See Notes 5 and 6. 2002 includes a net gain from reorganization items of $32.8 million

22. QUARTERLY FINANCIAL DATA (UNAUDITED) (In Thousands, Except Per Unit Amounts)

As discussed in Note 10, the following quarterly financial data has been restated.

Successor Company	First Quarter(1)		Second Quarter			Third Quarter			Fourth Quarter			Total
2003 (RESTATED)
Operating revenue	$	17,733	$	44,477		$	44,759		$	46,064		$	153,033
Gross profit		8,068		15,804			7,316			10,741			41,929
Operating income (loss)		4,320		2,972			(4,609	)		7,132			9,815
Net income (loss) from continuing operations		1,043		(6,704	)		(14,163	)		(2,877	)		(22,701	)
Basic net income (loss) per Unit		0.09		(0.54	)		(1.15	)		(0.23	)		(1.84	)
Diluted net income (loss) per Unit		0.09		(0.54	)		(1.15	)		(0.23	)		(1.84	)
Cash distributions per Unit		—		—			—			—			—

	First Quarter(1)		Second Quarter			Third Quarter			Fourth Quarter			Total
2003 (REPORTED)
Operating revenue	$	17,315	$	43,956		$	45,341		$	46,064		$	152,676
Gross profit		8,077		15,732			7,792			9,839			41,440
Operating income (loss)		4,329		2,900			(4,133	)		6,230			9,326
Net income (loss) from continuing operations.		1,052		(6,776	)		(13,687	)		(3,779	)		(23,190	)
Basic net income (loss) per Unit		0.09		(0.55	)		(1.11	)		(0.31	)		(1.88	)
Diluted net income (loss) per Unit		0.09		(0.55	)		(1.11	)		(0.31	)		(1.88	)
Cash distributions per Unit		—		—			—			—			—

F-154

Predecessor Company		First Quarter(2)		Second Quarter		Third Quarter		Fourth Quarter		Total
2003 (RESTATED)
Operating revenue		$	31,635	$	—	$	—	$	—	$	31,635
Gross profit			9,971		—		—		—		9,971
Operating income			2,614		—		—		—		2,614
Net income (loss) from continuing operations⁽³⁾			64,584		—		—		—		64,584
Basic net income (loss) per Unit⁽⁴⁾
	Common		0.11		—		—		—		0.11
	Subordinated		—		—		—		—		—
Diluted net income (loss) per Unit			0.08		—		—		—		0.08
Cash distributions per Common Unit			—		—		—		—		—

		First Quarter(2)		Second Quarter		Third Quarter		Fourth Quarter		Total
2003 (REPORTED)
Operating revenue		$	31,979	$	—	$	—	$	—	$	31,979
Gross profit			9,681		—		—		—		9,681
Operating income			2,324		—		—		—		2,324
Net income (loss) from continuing operations⁽³⁾			64,294		—		—		—		64,294
Basic net income (loss) per Unit⁽⁴⁾
	Common		0.16		—		—		—		0.16
	Subordinated		—		—		—		—		—
Diluted net income (loss) per Unit			0.11		—		—		—		0.11
Cash distributions per Common Unit			—		—		—		—		—

		First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Total
2002 (RESTATED)
Operating revenue		$	54,960		$	47,630		$	42,776		$	37,566		$	182,932
Gross profit			16,993			12,515			4,321			3,201			37,030
Operating income (loss)			5,293			(1,350	)		(12,327	)		(19,211	)		(27,595	)
Net income (loss) from continuing operations⁽³⁾			(5,856	)		(13,579	)		(25,372	)		4,266			(40,541	)
Basic net income (loss) per Unit⁽⁴⁾
	Common		(0.06	)		—			—			—			(0.06	)
	Subordinated		(0.51	)		(1.42	)		(1.30	)		—			(3.23	)
Diluted net income (loss) per Unit			(0.20	)		(0.46	)		(0.44	)		—			(1.10	)
Cash distributions per Common Unit⁽⁵⁾			0.25			—			—			—			0.25

F-155

		First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Total
2002 (REPORTED)
Operating revenue		$	54,960		$	47,630		$	42,814		$	37,538		$	182,942
Gross profit			17,131			12,484			3,579			4,364			37,558
Operating income (loss)			5,431			(1,381	)		(13,069	)		(18,048	)		(27,067	)
Net income (loss) from continuing operations⁽³⁾			(5,718	)		(13,610	)		(26,114	)		5,429			(40,013	)
Basic net income (loss) per Unit⁽⁴⁾
	Common		(0.05	)		—			—			—			(0.05	)
	Subordinated		(0.49	)		(1.43	)		(1.32	)		—			(3.24	)
Diluted net income (loss) per Unit			(0.20	)		(0.46	)		(0.44	)		—			(1.10	)
Cash distributions per Common Unit⁽⁵⁾			0.25			—			—			—			0.25

⁽¹⁾: For the period March 1, 2003 through March 31, 2003.
⁽²⁾: For the period January 1, 2003 through February 28, 2003.
⁽³⁾: The two months ended February 28, 2003 include a $7.3 million gain on reorganization items, a $131.6 million gain on the discharge of debt and a $56.8 million loss from fresh start adjustments. Fourth quarter 2002 amounts include a net gain on reorganization items of $32.8 million.
⁽⁴⁾: See Note 12 for discussion regarding the allocation of net income (loss) to unitholders.
⁽⁵⁾: Cash distributions are shown in the quarter paid and are based on the prior quarter's earnings.

F-156

LINK ENERGY LLC
(A LIMITED LIABILITY COMPANY)

SCHEDULE II

VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
FOR THE TEN MONTHS ENDED DECEMBER 31, 2003, TWO MONTHS
ENDED FEBRUARY 28, 2003, AND
FOR THE YEARS ENDED DECEMBER 31, 2002 AND 2001

(In Thousands)

		Balance at Beginning of Period		Charges to Costs and Expenses		Deductions and Other			Balance at End of Period
Successor Company
Ten Months Ended December 31, 2003
	Allowance for Doubtful Accounts	$	1,210	$	—	$	—		$	1,210
	Litigation Provisions	$	1,605	$	—	$	(1,146	)	$	459
	Safety and Environmental	$	13,440	$	9,107	$	(10,331	)	$	12,216
Predecessor Company
Two Months Ended February 28, 2003
	Allowance for Doubtful Accounts	$	1,210	$	—	$	—		$	1,210
	Litigation Provisions	$	8,376	$	—	$	(6,771	)	$	1,605
	Safety and Environmental	$	13,440	$	1,979	$	(1,979	)	$	13,440
Year ended December 31, 2002
	Allowance for Doubtful Accounts	$	1,225	$	—	$	(15	)	$	1,210
	Litigation Provisions	$	315	$	8,163	$	(102	)	$	8,376
	Safety and Environmental	$	12,075	$	14,819	$	(13,454	)	$	13,440
Year ended December 31, 2001
	Allowance for Doubtful Accounts	$	1,827	$	—	$	(602	)	$	1,225
	Litigation Provisions	$	1,000	$	315	$	(1,000	)	$	315
	Safety and Environmental	$	6,412	$	25,372	$	(19,709	)	$	12,075

F-157

Report of Independent Auditors

To the Board of Directors of
Shell Pipeline Company LP

In our opinion, the accompanying combined balance sheets and the related combined statements of income and owner's net investment and cash flows of the Capline Pipe Line Business, Capwood Pipe Line Business and Patoka Pipe Line Business ("the Businesses") present fairly, in all material respects, the financial position of the Businesses at December 31, 2003 and 2002, and the results of their operations and their cash flows for the year ended December 31, 2003, and for the periods February 14, 2002, through December 31, 2002, and January 1, 2002, through February 13, 2002, in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of Shell Pipeline Company L.P.'s management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As described in Note 6, the Businesses were sold on March 1, 2004, to Plains All American Pipeline L.P.

PricewaterhouseCoopers LLP

Houston, Texas
March 12, 2004

F-158

Capline Pipe Line Business, Capwood Pipe Line Business and Patoka Pipe Line Business
Combined Balance Sheets
December 31, 2003 and 2002

(dollars in thousands)			2003		2002
Assets
Current assets
	Accounts receivable		$	421	$	679
	Allowance oil inventory			4,853		8,192
	Materials and supplies			357		372
	Other			116		41

				5,747		9,284
Property and equipment, net				93,857		98,428

		Total assets	$	99,604	$	107,712

Liabilities and Owner's Net Investment
Current liabilities
	Property tax payable		$	343	$	91
	Other			—		48

		Total current liabilities		343		139
Owner's net investment				99,261		107,573

		Total liabilities and owner's net investment	$	99,604	$	107,712

The accompanying notes are an integral part of these financial statements.

F-159

Capline Pipe Line Business, Capwood Pipe Line Business and Patoka Pipe Line Business
Combined Statements of Income and Owner's Net Investment

(dollars in thousands)		Year Ended December 31, 2003			February 14 through December 31, 2002			January 1 through February 13, 2002
Revenue
Transportation and allowance oil revenue		$	34,363		$	43,974		$	6,028
Other revenue			1,492			746			102

	Total revenue		35,855			44,720			6,130

Costs and expenses
Power and fuel			5,535			7,298			1,000
Outside services			2,271			1,995			273
Salary and wages			1,769			1,346			184
Depreciation			5,264			4,589			64
Taxes other than taxes on income			657			570			78
Materials and supplies			342			460			63
Management fees			528			457			63
Pension and benefits			421			287			39
Other			326			299			40

	Total costs and expense		17,113			17,301			1,804

Net income			18,742			27,419			4,326
Deemed distributions to parent company			(27,054	)		(31,967	)		(4,382	)
Purchase price allocation			—			93,730			—
Owner's net investment
Beginning of period			107,573			18,391			18,447

End of period		$	99,261		$	107,573		$	18,391

The accompanying notes are an integral part of these financial statements.
The post-acquisition financial statements reflect a new basis of accounting, and the pre-acquisition and post-acquisition period financial statements are presented but are not comparable (See Note 1 in the Notes to Combined Financial Statements).

F-160

Capline Pipe Line Business, Capwood Pipe Line Business and Patoka Pipe Line Business
Combined Statements of Cash Flows

(dollars in thousands)				Year Ended December 31, 2003			February 14 through December 31, 2002			January 1 through February 13, 2002
Cash flows provided by operating activities
Net income				$	18,742		$	27,419		$	4,326

Adjustments to reconcile net income to net cash provided by operating activities
	Depreciation				5,264			4,589			64
	(Increase) decrease in working capital
		Receivables			258			237			32
		Allowance oil inventory			3,339			662			90
		Materials and supplies			15			33			5
		Property tax payable			252			(32	)		(5	)
		Other			(123	)		48			6

					9,005			5,537			192

			Net cash provided by operating activities		27,747			32,956			4,518

Cash flows used for investing activities
Capital expenditures					(693	)		(989	)		(136	)

			Net cash used for investing activities		(693	)		(989	)		(136	)

Cash flows used for financing activities
Deemed distributions to parent company					(27,054	)		(31,967	)		(4,382	)

			Net cash used for financing activities		(27,054	)		(31,967	)		(4,382	)

			Net increase in cash and cash equivalents		—			—			—
Cash and cash equivalents
Beginning of period					—			—			—

End of period					—			—			—

Nonmonetary activities
Purchase price allocation				$	—		$	93,730		$	—

F-161

Capline Pipe Line Business, Capwood Pipe Line Business and Patoka Pipe Line Business

Notes to Combined Financial Statements

1. Organization and Basis of Presentation

The accompanying combined financial statements present, in conformity with accounting principles generally accepted in the United States of America, the assets, liabilities, revenues and expenses of the historical operations of the transportation businesses comprised of the Capline Pipe Line Business, Capwood Pipe Line Business and Patoka Pipe Line Business (collectively the "Businesses") owned by Shell Pipeline Company LP ("Shell Pipeline"), formerly Equilon Pipeline Company LLC. Throughout the period covered by the financial statements, Shell Pipeline owned and managed the Businesses' operations.

Effective January 1, 1998, Shell Oil Company ("Shell Oil") and Texaco, Inc. ("Texaco") formed Equilon Enterprises LLC ("Equilon Enterprises") with 56 percent and 44 percent membership interests, respectively. Shell Pipeline is a wholly owned subsidiary of Equilon Enterprises.

In connection with the 2002 merger of Chevron Corporation and Texaco, Inc., the Federal Trade Commission required Texaco to divest its interest in Equilon Enterprises, and in early 2002 Shell Oil acquired Texaco's 44 percent interest in Equilon Enterprises, making Shell Oil the 100 percent owner of Equilon Enterprises. The acquisition by Shell Oil was accounted for using the purchase method of accounting in accordance with generally accepted accounting principles, with Shell Pipeline allocating the purchase price paid by Shell Oil to Shell Pipeline's net assets as of the acquisition date. Accordingly, the post-acquisition financial statements reflect a new basis of accounting, and the pre-acquisition period and post-acquisition period financial statements are presented but are not comparable.

The Capline Pipe Line Business ("Capline") is an undivided interest in a pipeline system consisting of 667 miles of 40-inch pipe from St. James, Louisiana to Patoka, Illinois. The Capwood Pipe Line Business ("Capwood") is an undivided interest in a pipeline system consisting of 57 miles of 20-inch pipe from Patoka, Illinois to Wood River, Illinois. The Patoka Pipe Line Business is a wholly owned pipeline system consisting of 1.2 miles of 22-inch pipe connecting Capline to storage locations in Patoka. Shell Pipeline's ownership percentages of each of the pipelines mentioned above are 22 percent, 76 percent and 100 percent, respectively. The combined financial statements include the Businesses' pro rata share of the assets, liabilities, revenues and expenses, because the undivided interests are not subject to joint control and the Businesses are only responsible for their pro rata share of direct costs.

The accompanying combined financial statements are presented on a carve-out basis to include the historical operations of the Businesses owned by Shell Pipeline viewed from a nonoperator perspective. In this context, a direct relationship existed between the carve-out operations and the operator, Shell Pipeline. Shell Pipeline's net investment in the Businesses (owner's net investment) is shown in lieu of stockholder's equity in the combined financial statements.

The combined statement of income and owner's net investment includes the pro rata share of the annual management fee charged to the undivided interests by the operator. The results of operations also include pro-rata allocations in accordance with the terms of the operating agreement, generally based on direct payroll and benefit costs.

Throughout the period covered by the combined financial statements, Shell Pipeline has provided cash management services to the Businesses through a centralized treasury function. As a result, all charges and cost allocations for the Businesses were deemed to have been paid by the Businesses to Shell Pipeline, in cash, during the period in which the cost was recorded in the combined financial statements.

F-162

All of the allocations and estimates in the combined financial statements were based on assumptions that Shell Pipeline management believes were reasonable under the circumstances. These allocations and estimates are not necessarily indicative of the costs and expenses that would have resulted if the Businesses had been operated as a separate entity.

2. Significant Accounting Policies

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosures of contingent assets and liabilities. Although Shell Pipeline's management believes these estimates are reasonable, actual results could differ from these estimates.

Revenue Recognition

Revenues for the transportation of crude are recognized (1) based upon regulated tariff rates and the related transportation volumes and (2) when the delivery of crude is made to the shipper or another common carrier pipeline. Allowance oil revenue is recognized when the Businesses receive the allowance oil volumes, which are valued at current market value. Any allowance oil sold is recorded in revenue as a net amount based on the selling price less its weighted average cost. Other revenue consists of additional charges in accordance with the tariff agreement based on the viscosity of the crude oil.

Property and Equipment

Crude oil pipeline and gathering assets are carried at cost. Costs subject to depreciation are net of expected salvage values and deprecation is calculated on a straight-line basis over the estimated useful lives of the respective assets as follows:

Line pipe		20-25 years
Equipment and other pipeline assets		20-25 years
Oil tanks		20-25 years
Other		5-25 years

Acquisitions and expenditures for renewals and betterments are capitalized, while maintenance and repairs, which do not improve or extend asset life, are expensed as incurred.

Impairment of Long-Lived Assets

The Businesses have adopted Statement of Financial Accounting Standards ("SFAS") No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, effective January 1, 2002. SFAS No. 144 retains the fundamental provisions of existing generally accepted accounting principles in the United States of America ("GAAP") with respect to the recognition and measurement of long-lived asset impairment contained in SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of. However, SFAS No. 144 provides new guidance intended to address certain significant implementation issues associated with SFAS No. 121, including expanded guidance with respect to appropriate cash flows to be used to determine whether recognition of any long-lived asset impairment is required, and if required how to measure the amount of the impairment. SFAS No. 144 also requires that any net assets to be disposed of by sale be reported at the lower of

F-163

carrying value or fair value less cost to sell, and expands the reporting of discontinued operations to include any component of any entity.

Accounts Receivable

Accounts receivable are valued at historical cost less an allowance for doubtful accounts.

Allowance Oil

A loss allowance factor of 0.2 percent on average, by volume, is incorporated into crude oil tariffs to offset evaporation and other losses in transit. The net excess of allowance quantities, calculated in accordance with the tariffs, over actual losses is valued at the average market value at the time the excess occurred and the result is recorded as allowance oil revenue. Inventories of allowance oil are carried at the lower of such value (cost) or market value with cost being determined on an average-cost basis. Gains or losses on sales of allowance oil barrels are included in transportation and allowance oil revenue.

Materials and Supplies

Inventories of materials and supplies are carried at lower of historical cost or market.

Environmental and Other Accrued Liabilities

The Businesses accrue for environmental remediation and other accrued liabilities when it is probable that such liabilities exist, based on past events or known conditions, and the amount of such liability can be reasonably estimated. If the Businesses can only estimate a range of probable liabilities, the minimum future undiscounted expenditure necessary to satisfy the Businesses' future obligation is accrued.

Concentration of Credit and Other Risks

A significant portion of the Businesses' revenues and receivables are from oil and gas companies. Although collection of these receivables could be influenced by economic factors affecting the oil and gas industry, management believes the risk of significant loss is considered remote.

One customer individually represents 53, 64 and 64 percent of sales for the fiscal year ended December 31, 2003, and for the periods February 14, 2002, to December 31, 2002, and January 1, 2002, to February 13, 2002, respectively. Another customer individually represents 14 percent of sales for the fiscal year ended December 31, 2003.

Development and production of crude oil in the service area of the pipelines is subject to among other factors, prices of crude oil and federal and state energy policy, none of which are within the Businesses' control.

Income Taxes

The Businesses have not historically incurred income tax expense as the Businesses were in partnerships, which, in accordance with the provisions of the Internal Revenue Code, are not subject to U.S. Federal income taxes. Rather, each partner includes its allocated share of the partnership's income or loss in its own federal and state income tax returns.

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New Accounting Standards

Statement of Financial Accounting Standards No. 146, Accounting for Costs Associated with Exit or Disposal Activities—SFAS No. 146, issued in June 2002, addresses financial accounting and reporting for costs associated with exit or disposal activities and nullifies EITF 94-3, Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring). In accordance with the requirements of the standard, the Businesses have adopted SFAS No. 146 for exit and disposal activities initiated after December 31, 2002. The Businesses did not have exit or disposal activities and accordingly, the adoption of SFAS No. 146 did not have an effect on the Businesses' financial position, results of operations or liquidity.

FASB Interpretation No. 45 Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others—FIN No. 45, issued in November 2002, elaborates on the disclosures to be made by a guarantor in its financial statements about its obligations under certain guarantees that it has provided. It also clarifies that a guarantor is required to recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. The Businesses have adopted FIN No. 45 and new guarantees, except those specifically excluded from the scope of the interpretation, issued after December 31, 2002, have been recognized at their fair value as a liability in accordance with the requirements of the interpretation. There were no guarantees in respect to the Businesses and accordingly, the adoption of FIN No. 45 did not have an effect on the Businesses' financial position, results of operations or liquidity.

3. Property, Plant and Equipment

Property, plant and equipment consisted of the following at December 31, 2003 and 2002:

	2003		2002
Land	$	533	$	533
Right of way		615		615
Line pipe		65,557		65,314
Equipment and other pipeline assets		25,070		24,442
Oil tanks		11,610		11,078
Construction work-in-progress		325		1,035

		103,710		103,017
Accumulated depreciation		9,853		4,589

Net property, plant and equipment	$	93,857	$	98,428

As described in Note 1, on February 13, 2002, Shell Oil acquired Texaco's 44 percent interest in Equilon Enterprises, making Shell Oil the 100 percent owner of Equilon Enterprises. The acquisition was accounted for using the purchase method of accounting in accordance with generally accepted accounting principles. Shell Oil's property, plant and equipment including the Capline, Capwood and Patoka Pipe Line Businesses was adjusted to estimated fair market value on February 14, 2002, and depreciated based on revised estimated remaining useful lives. The Businesses' accumulated depreciation balance at February 14, 2002, was eliminated pursuant to the purchase method of accounting.

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4. Related Party Transactions

The Businesses have entered into transactions with Shell Oil including its affiliates. Such transactions are in the ordinary course of business, include the transportation of crude oil and petroleum products and approximate market value.

The aggregate amounts of such transactions for the year ended December 31, 2003, and for the periods ended December 31, 2002, and February 13, 2002, consisted of pipeline tariff revenues totaling approximately $781,000, $287,000 and $39,000, respectively.

The Businesses have no employees and rely on the operator, Shell Pipeline, to provide personnel to perform daily operating and administrative duties on behalf of the Businesses. Accordingly, in accordance with the terms of the operating agreement, the operator has charged the Businesses for management fees aggregating approximately $528,000, $427,000 and $63,000 for the year ended December 31, 2003, and for the periods ended December 31, 2002, and February 13, 2002, respectively.

Certain of those personnel participate in the Alliance Pension Plan (a defined benefit plan) and the Alliance Savings Plan (a defined contribution plan). Also, certain of those personnel participate in Shell sponsored benefit plans that provide pensions and other postretirement benefits. A portion of these plans are unfunded, and the costs are shared by Shell Oil and its employees. The Businesses' allocated expense related to these plans was approximately $421,000, $288,000 and $39,000 for the year ended December 31, 2003, and for the periods ended December 31, 2002, and February 13, 2002, respectively.

In addition, as described in Note 1, the results of operations also include allocations of salary and wages. Such allocations totaled approximately $1,769,000, $1,346,000 and $184,000 for the year ended December 31, 2003, and for the periods ended December 31, 2002, and February 13, 2002, respectively.

5. Commitments and Contingencies

The Businesses lease certain real property, equipment and operating facilities under various operating leases. The Businesses also incur costs associated with leased land, rights-of-way, permits and regulatory fees, the contracts for which generally extend beyond one year but can be cancelled at any time should they not be required for operations. Future noncancellable commitments related to these items at December 31, 2003 were not significant.

Total lease expense incurred for the year ended December 31, 2003, and for the periods ended December 31, 2002, and February 13, 2002, was approximately $136,000, $106,000 and $15,000, respectively.

The Businesses are subject to possible loss contingencies including actions or claims based on environmental laws, federal regulations, and other matters.

The Businesses may be obligated to take remedial action as a result of the enactment of laws or the issuance of new regulations or to correct for the effects of the Businesses' actions on the environment. The Businesses have not accrued for any liability at December 31, 2003 or 2002, for planned environmental remediation activities. In management's opinion, this is appropriate based on existing facts and circumstances.

6. Subsequent Event

On December 16, 2003, Shell Pipeline entered into a purchase and sale agreement with Plains All American Pipeline L.P. committing to sell the Businesses for approximately $158 million excluding transaction costs and crude oil inventory and linefill requirements. The transaction closed on March 1, 2004.

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PLAINS AAP, L.P. BALANCE SHEET (in thousands)

		June 30, 2004
		(unaudited)
ASSETS
Cash		$	8
Investment in Plains All American Pipeline, L.P.			63,491
	Total Assets	$	63,499
LIABILITIES AND PARTNERS' CAPITAL
LIABILITIES
Performance Options Obligation		$	1,577
COMMITMENTS AND CONTINGENCIES
PARTNERS' CAPITAL
Limited Partners			61,436
General Partner			486
	Total Partners' Capital		61,922
	Total Liabilities and Partners' Capital	$	63,499

The accompanying notes are an integral part of this financial statement.

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PLAINS AAP, L.P.

Notes to the Financial Statement

Note 1—Organization

Plains AAP, L.P. (the "Partnership") is a Delaware limited partnership, which was formed on May 21, 2001 and, through a series of transactions, was capitalized on June 8, 2001. Through this series of transactions, Plains Holdings II Inc. conveyed to the Partnership its general partner interest in Plains All American Pipeline, L.P. ("PAA") and subsequently sold a portion of its interest in the newly formed partnership to certain investors. The ownership interests in the Partnership (collectively, the "Partners") at June 30, 2004, are comprised of a 1% general partner interest held by Plains All American GP LLC (the "General Partner") and the following limited partner interests:

•: Plains Holdings II Inc.—43.560%
•: Sable Investments, L.P.—19.800%
•: KAFU Holdings, L.P.—16.253%
•: E-Holdings III, L.P.—8.910%
•: Mark E. Strome—2.113%
•: PAA Management L.P.—3.960%
•: Strome Hedgecap Fund, L.P.—1.055%
•: Wachovia Investors, Inc.—3.349%

As of June 30, 2004, we own a 2% general partner interest in PAA, the ownership of which entitles us to receive incentive distributions if the amount that PAA distributes with respect to any quarter exceeds levels specified in the PAA partnership agreement. We also own a limited partner interest consisting of 446,875 common units (see Note 4). PAA is a publicly traded Delaware limited partnership, formed in 1998 and 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 (collectively, "LPG"), primarily in Texas, California, Oklahoma, Louisiana, Kansas, and the Canadian provinces of Alberta and Saskatchewan. PAA's operations can be categorized into two primary business activities:

Crude Oil Pipeline Transportation Operations. As of June 30, 2004, PAA owned approximately 15,000 miles of gathering and mainline crude oil pipelines located throughout the United States and Canada. Its activities from pipeline operations generally consist of transporting crude oil for a fee, third party leases of pipeline capacity, barrel exchanges and buy/sell arrangements.

Gathering, Marketing, Terminalling and Storage Operations. As of June 30, 2004, PAA owned approximately 37 million barrels of above-ground crude oil terminalling and storage facilities, including tankage associated with its pipeline systems. These facilities include a crude oil terminalling and storage facility at Cushing, Oklahoma. Cushing is one of the largest crude oil market hubs in the United States and the designated delivery point for NYMEX crude oil futures contracts. PAA utilizes its storage tanks to counter-cyclically balance its gathering and marketing operations and to execute various hedging strategies to stabilize profits and reduce the negative impact of crude oil market volatility. PAA's terminalling and storage operations also generate revenue at the Cushing Interchange and our other locations through a combination of storage and throughput charges to third parties. PAA's gathering and marketing operations include: the purchase of crude oil at the wellhead and the bulk purchase of crude oil at pipeline and terminal facilities; the transportation of crude oil on trucks, barges and pipelines; the subsequent resale or exchange of crude oil at various points along the crude oil distribution chain; and the purchase of LPG from producers, refiners and other marketers, and the sale of LPG to wholesalers, retailers and industrial end users.

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Note 2—Summary of Significant Accounting Policies

Use of Estimates

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the balance sheet. These estimates include those made in determining the value of the vested options under our Performance Option Plan (see Note 6). Although management believes these estimates are reasonable, actual results could differ, and may differ materially from these estimates.

Investment in PAA

Management has determined that PAA is not a variable interest entity as defined by FASB Interpretation No. 46 "Consolidation of Variable Interest Entities." Accordingly, we account for our ownership investment in PAA in accordance with Accounting Principles Board Opinion No. 18, "The Equity Method of Accounting for Investments in Common Stock." We have the ability to exercise significant influence over PAA, but not control; and therefore, we account for the investment under the equity method (see Note 5). Changes in our ownership interest due to PAA's issuance of additional capital or other capital transactions that alter our ownership investment are recorded directly to partners' capital.

Stock-Based Compensation

The recipients of the options issued under the Performance Option Plan are employees of the General Partner. The options are options to purchase units of PAA. Thus, the accounting models prescribed by both Statement of Financial Accounting Standards ("SFAS") No. 123, "Accounting for Stock-Based Compensation," as amended by SFAS No. 148 "Accounting for Stock-Based Compensation—Transition and Disclosure" and Accounting Principles Board Opinion No. 25 "Accounting for Stock Issued to Employees" are not appropriate. We account for the options using an approach based on when the options will vest. Once the options vest, we adjust the accrual each period based on their fair market value as calculated using the "Black-Scholes Model" (see Note 6).

Income Taxes

No liability for U.S. Federal or Canadian income taxes related to our operations is included in the accompanying financial statement because, as a partnership, we are not subject to Federal, State or Provincial income tax; and the tax effect of our activities accrues to the Partners. The Partners may be required to file U.S. Federal and State, as well as Canadian Federal and Provincial, income tax returns.

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Note 3—Investment in PAA

Our investment in PAA at June 30, 2004, is approximately $63.5 million. The summarized financial information of PAA at June 30, 2004, is presented below (in thousands):

Current assets	$	829,449
Non-current assets	$	1,852,455
Current liabilities	$	855,646
Long-term debt and other long-term liabilities	$	960,739
Partners' capital	$	865,519

At the date of inception, our investment in PAA exceeded our share of the underlying equity in the net assets of PAA by approximately $44.5 million. This excess is related to the fair value of PAA's crude oil pipelines and other assets at the time of inception and is amortized on a straight-line basis over their estimated useful life of 30 years. At June 30, 2004, the unamortized portion of this excess was approximately $36.5 million.

Note 4—Contribution of Subordinated Units

On June 8, 2001, certain of our limited partners contributed to us an aggregate of 450,000 subordinated units of PAA. In November 2003, 25% of these subordinated units converted into common units, and the remaining 75% converted into common units in February 2004. These 450,000 units (the "Option Units") are intended for use in connection with an option plan pursuant to which certain members of the management of our general partner will, subject to the satisfaction of vesting criteria, have a right to purchase a portion of such Option Units. During 2003, options for 3,125 Option Units were exercised (see Note 6). Until the exercise of the remainder of such options, we will continue to own and receive any distributions paid by PAA with respect to the Option Units. Any distributions we make as a result of the receipt of distributions on the Option Units will be paid to our limited partners in proportion to the original contribution of the Option Units.

The conversion of the remaining 75% of the subordinated units resulted in an increase in our investment of approximately $1.5 million for the Partnership. This change of interest gain was non-cash and has been reflected in our partners' capital.

Note 5—Partners' Capital

We distribute all of our available cash, less reserves established by management, on a quarterly basis. Except as described in Note 4, distributions are paid to the partners in proportion to their percentage interest in the Partnership. Included in partners' capital is accumulated other comprehensive income of approximately $5.1 million related to our share of PAA's accumulated other comprehensive income (loss). Other comprehensive income (loss) is allocated based on each partner's ownership interest.

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management of litigation. The General Partner (or, in the case of PAA's Canadian operations, PMC (Nova Scotia) Company) employs all officers and personnel involved in the operation and management of PAA and its subsidiaries. PAA reimburses the General Partner for all expenses, including compensation expenses, related to such operation and management. The Partnership has no commitment or intent to fund cash flow deficits or furnish other financial assistance to PAA.

Note 6—Performance Option Plan

In June 2001, the Performance Option Plan (the "Plan") was approved by the General Partner to grant options to purchase up to 450,000 Option Units of PAA to employees of the General Partner. See Note 4. Options to purchase 375,000 units have been issued under the Plan. The options were granted with a per unit exercise price of $22, less 80% of any per unit distribution on an Option Unit from June 2001, until the date of exercise. As of July 21, 2004, the exercise price has been reduced to $16.39 for distributions made since June 2001.

The options have a ten-year term and vest in 25% increments upon PAA achieving quarterly distribution levels as follows:

Vesting %	Quarterly Distribution Level		Annual Distribution Level
25%	$	0.525	$	2.10
50%	$	0.575	$	2.30
75%	$	0.625	$	2.50
100%	$	0.675	$	2.70

These options are considered performance awards and are accounted for at fair value upon vesting and are revalued at each financial statement date based on the "Black-Scholes Model." At June 30, 2004, an estimated fair value of $17.40 per unit resulted in a cumulative reduction of the Partners' capital accounts and corresponding increase in the Performance Options Obligation of approximately $1.6 million. No options expired or were forfeited during the period. Future grants may include different vesting criteria.

The facts and assumptions used in the "Black-Scholes Model" at June 30, 2004, were as follows:

						Assumptions
Options Outstanding		Percent Vested		Options Vested		Weighted Average Interest Rate		Weighted Average Expected Life		Weighted Average Expected Volatility		Weighted Average Expected Dividend Yield⁽¹⁾
371,875		25	%	90,625		3.85	%	4.2		29.50	%	1.89	%

⁽¹⁾: Reflects 20% of anticipated dividend yield. The adjustment is to provide for the reduction in the exercise price of the options equal to 80% of distributions.

Note 7—Subsequent Event

Distribution

PAA declared cash distributions to the Partnership of $3.0 million ($0.8 million for its general partner interest and $2.2 million for its incentive distribution interest) for the second quarter of 2004. The distribution, which was declared on July 21, 2004, was received on August 15, 2004. With the payment of this distribution of $0.5775 per unit, the vesting requirements have been met for the next 25% increment of options.

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Report of Independent Registered Public Accounting Firm

To the Board of Directors of Plains AAP, L.P.:

In our opinion, the accompanying balance sheet presents fairly, in all material respects, the financial position of Plains AAP, L.P. at December 31, 2003 in conformity with accounting principles generally accepted in the United States of America. This financial statement is the responsibility of Plains AAP, L.P.'s management. Our responsibility is to express an opinion on this financial statement based on our audit. We conducted our audit of this statement in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the balance sheet is free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the balance sheet, assessing the accounting principles used and significant estimates made by management, and evaluating the overall balance sheet presentation. We believe that our audit of the balance sheet provides a reasonable basis for our opinion.

PricewaterhouseCoopers LLP

Houston, Texas
April 13, 2004

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PLAINS AAP, L.P.
BALANCE SHEET
(in thousands)

			December 31, 2003
ASSETS
Cash			$	8
Investment in Plains All American Pipeline, L.P.				59,986

	Total Assets		$	59,994

LIABILITIES AND PARTNERS' CAPITAL
LIABILITIES
Performance Options Obligation			$	1,445
COMMITMENTS AND CONTINGENCIES
PARTNERS' CAPITAL
Limited Partners				58,102
General Partner				447

	Total Partners' Capital			58,549

		Total Liabilities and Partners' Capital	$	59,994

The accompanying notes are an integral part of this financial statement.

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PLAINS AAP, L.P.
Notes to the Financial Statement

Note 1—Organization

Plains AAP, L.P. (the "Partnership") is a Delaware limited partnership, which was formed on May 21, 2001, and, through a series of transactions, was capitalized on June 8, 2001. Through this series of transactions Plains Holdings II Inc. conveyed to the Partnership its general partner interest in Plains All American Pipeline, L.P. ("PAA") and subsequently sold a portion of its interest in the newly formed partnership to certain investors. The ownership interests in the Partnership (collectively, the "Partners") at December 31, 2003, are comprised of a 1% general partner interest held by Plains All American GP LLC (the "General Partner") and the following limited partner interests:

•: Plains Holdings II Inc. — 43.560%
•: Sable Investments, L.P. — 19.800%
•: KAFU Holdings, L.P. — 16.253%
•: E-Holdings III, L.P. — 8.910%
•: Mark E. Strome — 2.113%
•: PAA Management L.P. — 3.960%
•: Strome Hedgecap Fund, L.P. — 1.055%
•: Wachovia Investors, Inc. — 3.349%

As of December 31, 2003, we own a 2% general partner interest in PAA and a limited partner interest consisting of 446,875 common and subordinated units (see Note 4). PAA is a publicly traded Delaware limited partnership, formed in 1998 and 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, primarily in Texas, California, Oklahoma, Louisiana and the Canadian Provinces of Alberta and Saskatchewan. PAA's operations can be categorized into two primary business activities:

Crude Oil Pipeline Transportation Operations. PAA owns and operates approximately 7,000 miles of gathering and mainline crude oil pipelines located throughout the United States and Canada. Its activities from pipeline operations generally consist of transporting crude oil for a fee, third party leases of pipeline capacity, barrel exchanges and buy/sell arrangements.

Gathering, Marketing, Terminalling and Storage Operations. PAA owns and operates approximately 24.0 million barrels of above-ground crude oil terminalling and storage facilities, including tankage associated with its pipeline systems. These facilities include a crude oil terminalling and storage facility at Cushing, Oklahoma. Cushing is one of the largest crude oil market hubs in the United States and the designated delivery point for NYMEX crude oil futures contracts. PAA utilizes its storage tanks to counter-cyclically balance its gathering and marketing operations and to execute various hedging strategies to stabilize profits and reduce the negative impact of crude oil market volatility. PAA's terminalling and storage operations also generate revenue at the Cushing Interchange and our other locations through a combination of storage and throughput charges to third parties. PAA's gathering and marketing operations include:

•: the purchase of crude oil at the wellhead and the bulk purchase of crude oil at pipeline and terminal facilities;
•: the transportation of crude oil on trucks, barges and pipelines;

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•: the subsequent resale or exchange of crude oil at various points along the crude oil distribution chain; and
•: the purchase of liquefied petroleum gas and other petroleum products (collectively "LPG") from producers, refiners and other marketers, and the sale of LPG to wholesalers, retailers and industrial end users.

Note 2—Summary of Significant Accounting Policies

Use of Estimates

Investment in PAA

We account for our ownership investment in PAA in accordance with Accounting Principles Board Opinion No. 18, "The Equity Method of Accounting for Investments in Common Stock." We have the ability to exercise significant influence over PAA, but not control; and therefore, we account for the investment under the equity method (see Note 5). Changes in our ownership interest due to PAA's issuance of additional capital or other capital transactions which alter our ownership investment are recorded directly to partners' capital.

Stock-Based Compensation

The recipients of the options issued under the Performance Option Plan are employees of the General Partner. The options are for units of PAA. Thus, the accounting models prescribed by both Statement of Financial Accounting Standards ("SFAS") No. 123, "Accounting for Stock-Based Compensation," as amended by SFAS No. 148 "Accounting for Stock-Based Compensation—Transition and Disclosure" and Accounting Principles Board Opinion No. 25 "Accounting for Stock Issued to Employees" are not appropriate. We account for the options using a probability approach based on when the options will vest. Once the options vest, we adjust the accrual each period based on their fair market value as calculated using the "Black-Scholes Model" (see Note 6).

Income Taxes

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Note 3—Investment in PAA

Our investment in PAA at December 31, 2003, is approximately $60.0 million. The summarized financial information of PAA at December 31, 2003, is presented below (in thousands):

Current assets	$	732,974
Non-current assets	$	1,362,657
Current liabilities	$	801,919
Long-term debt and other long-term liabilities	$	546,985
Partners' capital	$	746,727

At the date of inception, our investment in PAA exceeded our share of the underlying equity in the net assets of PAA by approximately $44.5 million. This excess is related to the fair value of PAA's crude oil pipelines and other assets and is amortized on a straight-line basis over their estimated useful life of 30 years. At December 31, 2003, the unamortized portion of this excess was approximately $39.7 million.

Note 4—Contribution of Subordinated Units

On June 8, 2001, certain of our limited partners contributed to us an aggregate of 450,000 subordinated units of PAA. In November 2003, 25% of these subordinated units converted into common units, and the remaining 75% converted in February 2004. These 450,000 units (the "Option Units") are intended for use in connection with an option plan pursuant to which certain members of the management of our general partner will, subject to the satisfaction of vesting criteria, have a right to purchase a portion of such Option Units. During September 2003, options for 3,125 Option Units were exercised (see Note 6). Until the exercise of the remainder of such options, we will continue to own and receive any distributions paid by PAA with respect to the Option Units. Any distributions we make as a result of the receipt of distributions on the Option Units will be paid to our limited partners in proportion to the original contribution of the Option Units.

The conversion of 25% of the subordinated units resulted in an increase in our investment of approximately $0.7 million for the Partnership. This change of interest gain was non-cash and has been reflected in our partners' capital.

Note 5—Partners' Capital

We distribute all of our available cash, less reserves established by management, on a quarterly basis. Except as described in Note 4, distributions are paid to the partners in proportion to their percentage interest in the Partnership. Included in partners' capital is accumulated other comprehensive income of approximately $4.7 million related to our share of PAA's accumulated other comprehensive income (loss). Other comprehensive income (loss) is allocated based on each partner's ownership interest.

The General Partner manages the business and affairs of the Partnership. Except for situations in which the approval of the limited partners is expressly required by the Partnership agreement, or by nonwaivable provisions of applicable law, the General Partner has full and complete authority, power and discretion to manage and control the business, affairs and property of the Partnership, to make all decisions regarding those matters and to perform any and all other acts or activities customary or incident to the management of the Partnership's business, including the execution of contracts and management of litigation. The General Partner (or, in the case of PAA's Canadian operations, PMC (Nova Scotia) Company) employs all officers and personnel involved in the operation and management of PAA and its subsidiaries. PAA reimburses the General Partner for all expenses, including compensation expenses, related to such operation and management. The Partnership has no commitment or intent to fund cash flow deficits or furnish other financial assistance to PAA.

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During December 2003, PAA completed the issuance and sale of 2,840,800 Common Units at a public offering price of $31.94 per unit. In conjunction with that offering, we received additional investments from the Partners and made a contribution to PAA totaling approximately $1.8 million. The December 2003 PAA offering was the first offering completed following the conversion of 25% of the subordinated units. Now that we hold PAA common units, we recognize a change of interest gain or a loss at the time of each offering if the offering price is more or less than our average carrying amount per unit. Such gains or losses reflect the change in the book value of our equity in PAA compared to our proportionate share of the change in the underlying net assets of PAA due to the sale of the additional units. We recognized a gain of $0.1 million in our partners' capital at the time of the offering.

During September 2003, PAA completed the issuance and sale of 3,250,000 Common Units at a public offering price of $30.91 per unit. In conjunction with that offering, we received additional investments from the Partners and made a contribution to PAA totaling approximately $2.1 million.

During March 2003, PAA completed the issuance and sale of 2,645,000 Common Units at a public offering price of $24.80 per unit. In conjunction with that offering, we received additional investments from the Partners and made a contribution to PAA totaling approximately $1.3 million.

Note 6—Performance Option Plan

In June 2001, the Performance Option Plan (the "Plan") was approved by the General Partner to grant options to purchase up to 450,000 Option Units of PAA to employees of the General Partner. See Note 4. Options to purchase 375,000 units have been issued under the Plan. The options were granted with a per unit exercise price of $22, less 80% of any per unit distribution on an Option Unit from June 2001, until the date of exercise. As of February 13, 2004, the exercise price has been reduced to $17.30 for distributions made since June 2001.

The options have a ten-year term and vest in 25% increments upon PAA achieving quarterly distribution levels as follows:

Vesting %	Quarterly Distribution Level		Annual Distribution Level
25%	$	0.525	$	2.10
50%	$	0.575	$	2.30
75%	$	0.625	$	2.50
100%	$	0.675	$	2.70

In April 2002, upon declaration of the first quarter 2002 distribution, PAA attained the distribution level necessary for 25% or 93,750 of the options to vest. On September 30, 2003, 3,125 options were exercised at a weighted average exercise price of $18.19. No options expired or were forfeited during the year. Future grants may include different vesting criteria.

These options are considered performance awards and are accounted for at fair value when vesting is probable and are revalued at each financial statement date based on the "Black-Scholes Model." At December 31, 2003, an estimated fair value of $15.95 per unit resulted in a cumulative reduction of the Partners' capital accounts and corresponding increase in the Performance Options Obligation of approximately $1.4 million.

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The facts and assumptions used in the "Black-Scholes Model" at December 31, 2003, were as follows:

		Assumptions
Options Outstanding		Percent Vested		Options Vested		Weighted Average Interest Rate		Weighted Average Expected Life		Weighted Average Expected Volatility		Weighted Average Expected Dividend Yield⁽¹⁾
371,875		25	%	90,625		3.77	%	4.6		29.50	%	1.93	%

⁽¹⁾: Reflects 20% of anticipated dividend yield. The adjustment is to provide for the reduction in the exercise price of the options equal to 80% of distributions.

Note 7—Subsequent Event

PAA declared cash distributions to the Partnership of $2.3 million ($0.7 million for its general partner interest and $1.6 million for its incentive distribution interest) for the fourth quarter of 2003. The distribution, which was declared on January 22, 2004, was received on February 13, 2004.

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Item 20. Indemnification of Officers and Members of Our Board of Directors

Section 17-108 of the Delaware Revised Limited Partnership Act empowers a Delaware limited partnership to indemnify and hold harmless any partner or other person from and against all claims and demands whatsoever. The partnership agreement of Plains All American Pipeline provides that Plains All American Pipeline will indemnify the general partner, any departing partner, any person who is or was an affiliate of the general partner or any departing partner, and any person who is or was a member, partner, officer, director, employee, agent or trustee of the general partner or any departing partner or any affiliate of the general partner or any departing partner, or any person who is or was serving at the request of the general partner or any departing partner or any affiliate of the general partner or any departing partner as an officer, director, employee, member, partner, agent, fiduciary or trustee of another person (each, an "Indemnitee"), to the fullest extent permitted by law, from and against any and all losses, claims, damages, liabilities (joint and several), expenses (including, without limitation, legal fees and expenses), judgments, fines, penalties, interest, settlements and other amounts arising from any and all claims, demands, actions, suits or proceedings, whether civil, criminal, administrative or investigative, in which any Indemnitee may be involved, or is threatened to be involved, as a party or otherwise, by reason of its status as any of the foregoing; provided that in each case the Indemnitee acted in good faith and in a manner that such Indemnitee reasonably believed to be in or not opposed to the best interests of Plains All American Pipeline and, with respect to any criminal proceeding, had no reasonable cause to believe its conduct was unlawful. Any indemnification under these provisions will be only out of the assets of Plains All American Pipeline, and the general partner shall not be personally liable for, or have any obligation to contribute or loan funds or assets to Plains All American Pipeline to enable it to effectuate, such indemnification. Plains All American Pipeline is authorized to purchase (or to reimburse the general partner or its affiliates for the cost of) insurance against liabilities asserted against and expenses incurred by such persons in connection with Plains All American Pipeline's activities, regardless of whether Plains All American Pipeline would have the power to indemnify such person against such liabilities under the provisions described above.

The underwriting agreements that we may enter into with respect to the offer and sale of securities covered by this registration statement will contain certain provisions for the indemnification of directors and officers and the underwriters or sales agent, as applicable, against civil liabilities under the Securities Act.

Item 21. Exhibits and Financial Statement Schedules

(a): Exhibits

3.1	—	Third Amended and Restated Agreement of Limited Partnership of Plains All American Pipeline, L.P., dated as of June 27, 2001 (incorporated by reference to Exhibit 3.1 to Form 8-K filed August 27, 2001) as amended by Amendment No. 1 to the Third Amended and Restated Agreement of Limited Partnership of Plains All American Pipeline, L.P., dated as of April 15, 2004 (incorporated by reference to Exhibit 3.1 to the Quarterly Report on Form 10-Q for the period ended March 31, 2004)
3.2	—	Third Amended and Restated Agreement of Limited Partnership of Plains Marketing, L.P. dated as of April 1, 2004 (incorporated by reference to Exhibit 3.2 to the Quarterly Report on Form 10-Q for the period ended March 31, 2004)
3.3	—	Third Amended and Restated Agreement of Limited Partnership of Plains Pipeline, L.P. dated as of April 1, 2004 (incorporated by reference to Exhibit 3.3 to the Quarterly Report on Form 10-Q for the period ended March 31, 2004)

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3.4	—	Second Amendment dated as of July 23, 2004 to Amended and Restated Limited Liability Company Agreement of Plains All American GP LLC (incorporated by reference to Exhibit 3.1 to the Partnership's Current Report on Form 8-K filed July 27, 2004)
3.5	—	Amended and Restated Limited Partnership Agreement of Plains AAP, L.P. (incorporated by reference to Exhibit 3.1 to Plains All American Pipeline, L.P.'s Current Report on Form 8-K filed on June 11, 2001)
3.6	—	Certificate of Incorporation of PAA Finance Corp. (incorporated by reference to Exhibit 3.6 to Plains All American Pipeline, L.P.'s Registration Statement on Form S-3 filed on August 27, 2001)
3.7	—	Bylaws of PAA Finance Corp. (incorporated by reference to Exhibit 3.7 to the Plains All American Pipeline, L.P.'s Registration Statement on Form S-3 filed on August 27, 2001)
4.1	—	Indenture dated September 25, 2002 among Plains All American Pipeline, L.P., PAA Finance Corp. and Wachovia Bank, National Association (incorporated by reference to Exhibit 4.1 to Quarterly Report on Form 10-Q for the quarter ended September 30, 2002)
4.2	—	First Supplemental Indenture dated as of September 25, 2002 (incorporated by reference to Exhibit 4.2 to Quarterly Report on Form 10-Q for the Quarter ended September 30, 2002).
4.3	—	Second Supplemental Indenture dated as of December 10, 2003. (incorporated by reference to Exhibit 4.4 to Annual Report on Form 10-K for the Year Ended December 31,2003).
4.4*	—	Third Supplemental Indenture (Series A and Series B 4.750% Senior Notes due 2009) dated August 12, 2004 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and Wachovia, National Association
4.5*	—	Fourth Supplemental Indenture (Series A and Series B 5.875% Senior Notes due 2009) dated August 12, 2004 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and Wachovia, National Association
4.6*	—	Exchange and Registration Rights Agreement (4.750% Senior Notes due 2009) dated August 12, 2004 among Plains All American Pipeline, L.P., PAA Finance Corp., the Guarantors named therein and the Initial Purchasers named therein
4.7*	—	Exchange and Registration Rights Agreement (5.875% Senior Notes due 20016) dated August 12, 2004 among Plains All American Pipeline, L.P., PAA Finance Corp., the Guarantors named therein and the Initial Purchasers named therein
4.8	—	Class C Common Unit Purchase Agreement by and among Plains All American Pipeline, L.P., Kayne Anderson Energy Fund II, L.P., KAFU Holdings, L.P., Kayne Anderson Capital Income Partners, L.P., Kayne Anderson MLP Fund, L.L.P., Tortoise Energy Infrastructure Corporation and Vulcan Energy II Inc. dated March 31, 2004 (incorporated by reference to Exhibit 4.1 to the quarterly report on Form 10-Q for the period ended March 31, 2004)
4.9	—	Registration Rights Agreement by and among Plains All American Pipeline, L.P., Kayne Anderson Energy Fund II, L.P., KAFU Holdings, L.P., Kayne Anderson Capital Income Partners (QP), L.P., Kayne Anderson MLP Fund, L.P., Tortoise Energy Infrastructure Corporation and Vulcan Energy II Inc. dated April 15, 2004 (incorporated by reference to Exhibit 4.2 to the Quarterly Report on Form 10-Q for the period ended March 31, 2004)
5.1*	—	Opinion of Vinson & Elkins L.L.P. as to the legality of the securities being registered

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10.1	—	Credit Agreement dated November 2, 2004 among Plains All American Pipeline, L.P. (as US Borrower), PMC (Nova Scotia) Company and Plains Marketing Canada, L.P. (as Canadian Borrowers), and Bank of America, N.A. (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for the period ended September 30, 2004)
10.2	—	Restated Credit Facility (Uncommitted Senior Secured Discretionary Contango Facility) dated November 19, 2004 among Plains Marketing, L.P. and the lenders named therein (incorporated by reference to Exhibit 10.1 to Form 8-K filed November 24, 2004
10.3	—	Amended and Restated Marketing Agreement, dated as of July 23, 2004, among Plains Resources Inc., Calumet Florida Inc. and Plains Marketing, L.P. (incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q for the period ended June 30, 2004)
10.4	—	Amended and Restated Omnibus Agreement, dated as of July 23, 2004, among Plains Resources Inc., Plains All American Pipeline, L.P., Plains Marketing, L.P., Plains Pipeline, L.P. and Plains All American GP LLC. (incorporated by reference to Exhibit 10.3 to the Quarterly Report on Form 10-Q for the period ended June 30, 2004)
10.5	—	Contribution, Assignment and Amendment Agreement, dated as of June 27, 2001, among Plains All American Pipeline, L.P., Plains Marketing, L.P., All American Pipeline, L.P., Plains AAP, L.P., Plains All American GP LLC and Plains Marketing GP Inc. (incorporated by reference to Exhibit 10.1 to Form 8-K filed June 27, 2001)
10.6	—	Contribution, Assignment and Amendment Agreement, dated as of June 8, 2001, among Plains All American Inc., Plains AAP, L.P. and Plains All American GP LLC (incorporated by reference to Exhibit 10.1 to Form 8-K filed June 11, 2001)
10.7	—	Separation Agreement, dated as of June 8, 2001 among Plains Resources Inc., Plains All American Inc., Plains All American GP LLC, Plains AAP, L.P. and Plains All American Pipeline, L.P. (incorporated by reference to Exhibit 10.2 to Form 8-K filed June 11, 2001)
10.8	—	Pension and Employee Benefits Assumption and Transition Agreement, dated as of June 8, 2001 among Plains Resources Inc., Plains All American Inc. and Plains All American GP LLC (incorporated by reference to Exhibit 10.3 to Form 8-K filed June 11, 2001)
10.9	—	Plains All American GP LLC 1998 Long-Term Incentive Plan (incorporated by reference to Exhibit 99.1 to Registration Statement on Form S-8, File No. 333-74920) as amended June 27, 2003 (incorporated by reference to Exhibit 10.1 to Form 10-Q filed June 30, 2003)
10.10	—	Plains All American 2001 Performance Option Plan (incorporated by reference to Exhibit 99.2 to Registration Statement on Form S-8, File No. 333-74920)
10.11	—	Amended and Restated Employment Agreement between Plains All American GP LLC and Greg L. Armstrong dated as of June 30, 2001 (incorporated by reference to Exhibit 10.3 to Quarterly Report on Form 10-Q for the Quarter Ended September 30, 2001)
10.12	—	Amended and Restated Employment Agreement between Plains All American GP LLC and Harry N. Pefanis dated as of June 30, 2001 (incorporated by reference to Exhibit 10.4 to Quarterly Report on Form 10-Q for the Quarter Ended September 30, 2001)
10.13	—	Asset Purchase and Sale Agreement between Murphy Oil Company Ltd. And Plains Marketing Canada, L.P. (incorporated by reference to Form 8-K filed May 10, 2001)
10.14	—	Transportation Agreement dated July 30, 1993, between All American Pipeline Company and Exxon Company, U.S.A. (incorporated by reference to Exhibit 10.9 to Registration Statement, File No. 333-64107)

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10.15	—	Transportation Agreement dated August 2, 1993, between All American Pipeline Company and Texaco Trading and Transportation Inc., Chevron U.S.A. and Sun Operating Limited Partnership (incorporated by reference to Exhibit 10.10 to Registration Statement, File No. 333-64107)
10.16	—	First Amendment to Contribution, Conveyance and Assumption Agreement dated as of December 15, 1998 (incorporated by reference to Exhibit 10.13 to Annual Report on Form 10-K for the Year Ended December 31, 1998)
10.17	—	Agreement for Purchase and Sale of Membership Interest in Scurlock Permian LLC between Marathon Ashland LLC and Plains Marketing, L.P. dated as of March 17, 1999 (incorporated by reference to Exhibit 10.16 to Annual Report on Form 10-K for the Year Ended December 31, 1998)
12.1*	—	Statement of Computation of Ratio of Earnings to Fixed Charges
21.1	—	List of Subsidiaries of Plains All American Pipeline, L.P. (incorporated by reference to Exhibit 21.1 to Registration Statement on Form S-1, File No. 333-119738)
23.1*	—	Consent of PricewaterhouseCoopers LLP
23.2*	—	Consent of PricewaterhouseCoopers LLP
23.3*	—	Consent of PricewaterhouseCoopers LLP
23.4*	—	Consent of Vinson & Elkins L.L.P. (contained in Exhibit 5.1)
24.1*	—	Powers of Attorney (included on the signature page)
25.1*	—	Form T-1 Statement of Eligibility and Qualification under the Trust Indenture Act of 1939 of the trustee under the Indenture with respect to the 4.750% Senior Notes due 2009 and the 5.875% Senior Notes due 2016
99.1*	—	Letter of Transmittal (2009 Notes)
99.2*	—	Letter of Transmittal (2016 Notes)

*

Filed herewith.

(b): Financial Statement Schedules

See index of financial statements beginning on page F-1 of this prospectus.

Item 22. Undertakings

Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers and controlling persons of any registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by any registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction of the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.

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Each undersigned registrant hereby undertakes:

(1) to file, during any period in which offers or sales are being made, a post-effective amendment to this registration statement:

(i) to include any prospectus required by Section 10(a)(3) of the Securities Act of 1933;

(ii) to reflect in the prospectus any facts or events arising after the effective date of the registration statement (or the most recent post-effective amendment thereof) which, individually or in the aggregate, represents a fundamental change in the information set forth in the registration statement. Notwithstanding the foregoing, any increase or decrease in volume of securities offered (if the total dollar value of securities offered would not exceed that which was registered) and any deviation from the low or high end of the estimated maximum offering range may be reflected in the form of prospectus filed with the Securities and Exchange Commission pursuant to Rule 424(b) if, in the aggregate, the changes in volume and price represent no more than a 20 percent change in the maximum aggregate offering price set forth in the "Calculation of Registration Fee" table in the effective registration statement; and

(iii) to include any material information with respect to the plan of distribution not previously disclosed in the registration statement or any material change to such information in the registration statement.

(2) That, for the purpose of determining any liability under the Securities Act of 1933, each such post-effective amendment shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

(3) To remove from registration by means of a post-effective amendment any of the securities being registered which remain unsold at the termination of the offering.

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SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, the Registrant has duly caused this Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Houston, State of Texas on December 10, 2004.

PLAINS ALL AMERICAN PIPELINE, L.P.
By:	Plains AAP, L.P., its general partner
By:	Plains All American GP LLC, its general partner
By:	/s/ GREG L. ARMSTRONG
	Name:	Greg L. Armstrong
	Title:	Chairman of the Board and Chief Executive Officer
PLAINS MARKETING, L.P.
By:	Plains Marketing GP Inc., its general partner
By:	/s/ GREG L. ARMSTRONG
	Name:	Greg L. Armstrong
	Title:	Chief Executive Officer
PLAINS PIPELINE, L.P.
By:	Plains Marketing GP Inc., its general partner
By:	/s/ GREG L. ARMSTRONG
	Name:	Greg L. Armstrong
	Title:	Chief Executive Officer
PAA FINANCE CORP.
By:	/s/ GREG L. ARMSTRONG
	Name:	Greg L. Armstrong
	Title:	President

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PLAINS MARKETING GP INC.
By:	/s/ GREG L. ARMSTRONG
	Name:	Greg L. Armstrong
	Title:	Chief Executive Officer
PLAINS MARKETING CANADA LLC
By:	Plains Marketing, L.P., it sole member
By:	Plains Marketing GP Inc., its general partner
By:	/s/ GREG L. ARMSTRONG
	Name:	Greg L. Armstrong
	Title:	Chief Executive Officer
PLAINS MARKETING CANADA, L.P.
By:	PMC (Nova Scotia) Company, its general partner
By:	/s/ PHIL KRAMER
	Name:	Phil Kramer
	Title:	Executive Vice President
PMC (NOVA SCOTIA) COMPANY
By:	/s/ PHIL KRAMER
	Name:	Phil Kramer
	Title:	Executive Vice President
BASIN HOLDINGS GP LLC
By:	/s/ HARRY N. PEFANIS
	Name:	Harry N. Pefanis
	Title:	President

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BASIN PIPELINE HOLDINGS, L.P.
By:	Basin Holdings GP LLC, its general partner
By:	/s/ HARRY N. PEFANIS
	Name:	Harry N. Pefanis
	Title:	President
RANCHO HOLDINGS GP LLC
By:	/s/ HARRY N. PEFANIS
	Name:	Harry N. Pefanis
	Title:	President
RANCHO PIPELINE HOLDINGS, L.P.
By:	Rancho Holdings GP LLC, its general partner
By:	/s/ HARRY N. PEFANIS
	Name:	Harry N. Pefanis
	Title:	President

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POWER OF ATTORNEY

We, the undersigned directors and officers, do hereby constitute and appoint Phil Kramer and Tim Moore and each of them our true and lawful attorneys-in-fact and agents, to do any and all acts and things in our names and on our behalf in our capacities as directors and officers and to execute any and all instruments for us and in our name in the capacities indicated below, which said attorneys and agents may deem necessary or advisable to enable said corporation to comply with the Securities Act of 1933 and any rules, regulations and requirements of the Securities and Exchange Commission, in connection with this Registration Statement, or any registration statement for this offering that is to be effective upon filing pursuant to Rule 462(b) under the Securities Act of 1933, including specifically, but without limitation, power and authority to sign for us or any of us in names in the capacities indicated below, any and all amendments (including post-effective amendments) hereto; and we do hereby ratify and confirm all that said attorneys and agents shall do or cause to be done by virtue thereof.

Pursuant to the requirements of the Securities Act of 1933, as amended, this registration statement has been signed below by the following persons in the capacities and on the dates indicated below.

PLAINS ALL AMERICAN GP LLC, for itself and as the general partner of PLAINS AAP, L.P., as the general partner of PLAINS ALL AMERICAN PIPELINE, L.P.

SIGNATURE	TITLE	DATE

/s/ GREG L. ARMSTRONG Greg L. Armstrong	Chairman of the Board, Chief Executive Officer and Director (Principal Executive Officer)	December 10, 2004
/s/ PHIL KRAMER Phil Kramer	Executive Vice President, Chief Financial Officer (Principal Financial Officer)	December 10, 2004
/s/ TINA VAL Tina Val	Vice President—Accounting (Principal Accounting Officer)	December 10, 2004
/s/ EVERARDO GOYANES Everardo Goyanes	Director	December 10, 2004
/s/ ARTHUR L. SMITH Arthur L. Smith	Director	December 10, 2004
/s/ ROBERT V. SINNOTT Robert V. Sinnott	Director	December 10, 2004
/s/ GARY R. PETERSON Gary R. Petersen	Director	December 10, 2004
/s/ DAVID N. CAPOBIANCO David N. Capobianco	Director	December 10, 2004
/s/ JOHN T. RAYMOND John T. Raymond	Director	December 10, 2004
/s/ J. TAFT SYMONDS J. Taft Symonds	Director	December 10, 2004

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PLAINS MARKETING GP INC., for itself and as the general partner of PLAINS MARKETING, L.P. and PLAINS PIPELINE, L.P., which is the sole member of each of BASIN HOLDINGS GP LLC, the general partner of BASIN PIPELINE HOLDINGS, L.P. and RANCHO HOLDINGS GP LLC, the general partner of RANCHO PIPELINE HOLDINGS, L.P., and as the general partner of PLAINS MARKETING, L.P., the sole member of PLAINS MARKETING CANADA LLC

/s/ GREG L. ARMSTRONG Greg L. Armstrong	Chief Executive Officer and Director (Principal Executive Officer)	December 10, 2004
/s/ HARRY N. PEFANIS Harry N. Pefanis	President, Chief Operating Officer and Director	December 10, 2004
/s/ PHIL KRAMER Phil Kramer	Executive Vice President and Chief Financial Officer (Principal Financial Officer)	December 10, 2004
/s/ TINA VAL Tina Val	Vice President—Accounting (Principal Accounting Officer)	December 10, 2004
/s/ TIM MOORE Tim Moore	Vice President, General Counsel, Secretary and Director	December 10, 2004

PAA FINANCE CORP.

/s/ GREG L. ARMSTRONG Greg L. Armstrong	President and Director (Principal Executive Officer)	December 10, 2004
/s/ PHIL KRAMER Phil Kramer	Executive Vice President, Chief Financial Officer and Director (Principal Financial Officer)	December 10, 2004
/s/ TINA VAL Tina Val	Vice President—Accounting (Principal Accounting Officer)	December 10, 2004
/s/ HARRY N. PEFANIS Harry N. Pefanis	Vice President and Director	December 10, 2004

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PMC (NOVA SCOTIA) COMPANY, for itself and as the general partner of PLAINS MARKETING CANADA, L.P.

SIGNATURE	TITLE	DATE

/s/ W. DAVID DUCKETT W. David Duckett	President (Principal Executive Officer)	December 10, 2004
/s/ D. MARK ALENIUS D. Mark Alenius	Vice President Chief Financial Officer (Principal Financial and Accounting Officer)	December 10, 2004
/s/ TIM MOORE Tim Moore	Vice President and Director	December 10, 2004
/s/ GREG L. ARMSTRONG Greg L. Armstrong	Director	December 10, 2004
/s/ HARRY N. PEFANIS Harry N. Pefanis	Director	December 10, 2004

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