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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES TABLE OF CONTENTS

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

FORM 10-Q

Commission file number: 1-14569

PLAINS ALL AMERICAN PIPELINE, L.P.
(Exact name of registrant as specified in its charter)

333 Clay Street, Suite 1600
Houston, Texas 77002
(Address of principal executive offices)
(Zip Code)

(713) 646-4100
(Registrant's telephone number, including area code)

        Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý    No o

        Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes ý    No o

        At August 5,November 1, 2004, there were outstanding 62,628,72262,740,218 Common Units, 1,307,190 Class B Common Units and 3,245,700 Class C Common Units.

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

TABLE OF CONTENTS

PART I. FINANCIAL INFORMATION

Item 1. CONSOLIDATED FINANCIAL STATEMENTS

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands, except unit data)

The accompanying notes are an integral part of these consolidated financial statements.

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per unit data)

The accompanying notes are an integral part of these consolidated financial statements.

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

The accompanying notes are an integral part of these consolidated financial statements.

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF PARTNERS' CAPITAL

(in thousands)

The accompanying notes are an integral part of these consolidated financial statements.

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

Statement of Changes in Accumulated Other Comprehensive Income

The accompanying notes are an integral part of these consolidated financial statements.

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Note 1—Organization and Accounting Policies

        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 liquefied petroleum gas and other petroleum products collectively as "LPG." Our operations are conducted in the United States and Canada, directly and indirectly through our operating subsidiaries, Plains Marketing, L.P., Plains Pipeline, L.P. (formerly known as All American Pipeline, L.P.) and Plains Marketing Canada, L.P., and are concentrated in Texas, Oklahoma, California, Louisiana, Kansas and the Canadian provinces of Alberta and Saskatchewan.

        The accompanying consolidated financial statements and related notes present (i) our consolidated financial position as of JuneSeptember 30, 2004, and December 31, 2003, (ii) the results of our consolidated operations for the three months and sixnine months ended JuneSeptember 30, 2004 and 2003, (iii) our consolidated cash flows for the sixnine months ended JuneSeptember 30, 2004 and 2003, (iv) our consolidated changes in partners' capital for the sixnine months ended JuneSeptember 30, 2004, (v) our consolidated comprehensive income for the three months and sixnine months ended JuneSeptember 30, 2004 and 2003, and (vi) our changes in consolidated accumulated other comprehensive income for the sixnine months ended JuneSeptember 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 three months and sixnine months ended JuneSeptember 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

        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 beis 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 the consolidated statement of operations for the sixnine months ended JuneSeptember 30, 2004 and the consolidated balance sheet as of JuneSeptember 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 secondthird quarter of 2003 was not material to net income or net income per basic and diluted limited partner unit. The pro forma impact for the first halfnine months of 2003 would have been an increase to net income of approximately $1.8$2.2 million ($0.04 per basic and diluted limited partner unit) resulting in pro forma net income of $49.6$61.8 million and pro forma basic net income per limited partner unit (basicof $1.10 and diluted)pro forma diluted net income per limited partner unit of $0.91.$1.09.

        In conjunction with this change in accounting principle, we will classifyhave 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 asof cash flows from operating activities. Accordingly, the accompanying statement of cash flows for the sixnine months ended JuneSeptember 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 $28.5$40.4 million for the sixnine months ended JuneSeptember 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.

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 $326$332 million, including $268 million of cash (net of approximately $5.5 million subsequently returned to us from an indemnity escrow account) and approximately $58$64 million of net liabilities assumed and acquisition relatedacquisition-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.

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

⁽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 $19.1$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 4)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 comprised of affiliates of Kayne Anderson Capital Advisors, Vulcan Capital and Tortoise Capital Advisors for $30.81 per unit, generating aggregate net proceeds of approximately $101 million, including the general partner's proportionate contribution.investors. During the third quarter of 2004, we completed a public offering of common units raising approximately $159and the sale of an aggregate of $350 million net of expenses and inclusivesenior notes. A portion of the underwriters' exercise of the overallotment option and the general partner's proportionate contribution. Proceedsproceeds from the public offering werethese transactions was used to retire a portion of the $200 million, 364-day credit facility. Seefacility (see Note 6.7).

        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

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 667-mile,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):

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 (in millions, except per unit amounts):reported:

⁽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 for Link's predecessor company's reorganization, discharge of debt and fresh start adjustments along withas 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 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 $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

        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.

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 JuneSeptember 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 $0.4$0.5 million. We 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.

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:

⁽¹⁾

Value per barrel reflects the impact of inventory hedges on a portion of our volumes.

Note 4—5—Debt

      Debt consists of the following (in millions):following:

⁽¹⁾

At JuneSeptember 30, 2004 and December 31, 2003, we have classified $13.2$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.

        In connection with the Link acquisition, we entered into a new $200 million revolving credit facility that has a 364-day term and contains a twelve-month term out option, exercisable at our election, at the end of the primary term. We have classified amounts outstanding under this facility as long-term as we have both the intent and the ability to refinance these amounts into long-term borrowings. The facility 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. We repaid approximately $160 million of amounts outstanding under this facility with proceeds from our third quarter 2004 equity offering, and have committed to use net proceeds from future debt and equity offerings to prepay indebtedness outstanding and reduce the commitment level. See Note 6.

        OnDuring August 5, 2004, we soldcompleted 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

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 expect to close the sale on August 12, 2004, with proceeds after initial purchaser discount and offering costs of approximately $345.3 million. We intend to useused the proceeds 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,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.

        We are inIn the processthird quarter of increasing the capacity of2004, we increased our uncommitted senior secured hedged inventory facility from $200 million to $300 million, primarily as a resultwith 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 increasedhedged crude oil pricesinventory for storage when market conditions warrant. Borrowings under the hedged inventory facility are secured by the inventory purchased under the facility and an increasethe associated accounts receivable, and are repaid with the proceeds from the sale of such inventory. This facility expires in our crude oil storage capacity as a result of acquisitions. WeNovember 2004, and we expect to completeextend the increase during the third quarter.maturity to November 2005 before expiration.

        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.

Note 5—6—Earnings Per Common Unit

        The following table sets forth the computation of basic and diluted earnings per limited partnercommon unit:

        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.

Note 6—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 138,000315,500 common units during the first quarterhalf of 2004 and approximately 177,50047,500 common units during the secondthird 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 proportionalproportionate two percent contribution. See Note 78 for additional discussion.

        Payment of Deferred Acquisition Price.    In connection with the CANPET acquisition in July 2001, $26.5 million Canadian of the purchase price, payable in common units or cash at our option, was deferred subject to various performance objectives being met. These objectives were met as of December 31, 2003 and an increase to goodwill for this liability was recorded as of that date. The liability was satisfied onOn April 30, 2004, with the issuance ofwe issued approximately 385,000 common units and the payment ofpaid approximately $6.5 million in cash. Thecash 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 comprisedconsisting 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 arepari passu in voting and distribution rights with the Partnership's publicly traded common units. The Class C common units are similar in manymost respects to the Partnership's Class B common units. The Class C common units areBoth classes become convertible into common units upon approval by the holders of a majority of the common units. Beginning six months from the closingSee "—Class B and Class C Common; Unitholder Meeting."

        Class B and Class C Common; Unitholder Meeting.    Each of the private placement, theClass 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 conversionterms 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 conversioncommon unitholders is not obtained within 120 days of the request, the holders of the Class B and Class C unitholdersunits (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 conversioncommon unitholders is not secured within 90 days after the

end of the 120-day period, the distribution right increases to 115%. The holderPartnership is in the process of our Class B common units, Plains Holdings Inc., haspreparing for a similar right to request a unitholder meeting which is currently exercisable.of unitholders.

        Equity Offering.    In the third quarter of 2004, we completed a public offering of 4,904,0004,968,000 common units for $33.25 per unit. The offering resulted in gross proceeds of approximately $163.1$165.2 million from the sale of units and approximately $3.3$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 $7.3$7.7 million. Net proceeds of $159.1$160.9 million were used to permanently reduce outstanding borrowings under the $200 million, 364-day credit facility (see Note 4)5).

Distributions

        On July 21,October 22, 2004, we declared a cash distribution of $0.5775$0.60 per unit on our outstanding common units, Class B common units and Class C common units. The distribution is payable on August 13,November 12, 2004, to unitholders of record on August 3,November 2, 2004, for the period AprilJuly 1, 2004, through JuneSeptember 30, 2004. The total distribution to be paid is approximately $41.8$43.9 million, with approximately $38.8$40.4 million to be paid to our common unitholders and $0.8 million and $2.2$2.7 million to be paid to our general partner for its general partner and incentive distribution interests, respectively.

        On April 23,August 13, 2004, we declaredpaid 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. The distribution was paid on May 14, 2004, to unitholders of record on May 4, 2004,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 January 22,February 13, 2004, we declaredpaid 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,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 7—8—Vesting of Unit Grants Under Long-Term Incentive Plan

        During the first halfnine months of 2004, approximately 796,000895,000 phantom units vested. We paid cash in lieu of delivery of common units for approximately 306,000328,000 of the phantom units and issued approximately 315,500362,000 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 halfnine months of

2004, we recognized $4.2 million of compensation expense related to the vesting of phantom units under the LTIP. This expense includes an anticipated vesting in August 2004. 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. We anticipate that, afterAfter giving effect to the Augustthird quarter 2004 vesting and related tax withholding and cash settlement, approximately 874,000 phantom units will beare available under the plan for future grant and approximately 140,000134,000 phantom units will remain outstanding. In accordance with the provisions of the LTIP and applicable NYSE standards, no more than approximately 564,000460,000 of such phantom unit grants (outstanding or future) could be satisfied by delivery of common units.

Note 8—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 JuneSeptember 30, 2004, balance sheet includes assets of $35.4$53.6 million ($27.739.5 million current), liabilities of $23.5$43.9 million ($16.332.8 million current) and unrealized net gains deferred to Other Comprehensive Income ("OCI") of $4.6$0.4 million. EarningsTotal derivative activities for the sixnine months ended JuneSeptember 30, 2004, includegenerated a gain of $10.7 million (including a gain$66.3 million. Total derivative activities include the mark-to-market of $7.1 millionopen positions that was reclassified intodo not meet hedge accounting requirements and gains and losses recognized in earnings from OCIfor all hedges settled during the period).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 JuneSeptember 30, 2004, the total amount of deferred net lossesgains 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 sixnine months ended JuneSeptember 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 $4.6$0.4 million net gain deferred in OCI at JuneSeptember 30, 2004, a net gain of $11.0$7.3 million will be reclassified into earnings in the next twelve months and the remaining net loss at various intervals ending in 2013.2016. Since a portion of these amounts areis 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 utilizedwe 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 cost of salescrude oil and operationsLPG 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 JuneSeptember 30, 2004, we have no open interest rate hedging instruments. However, there isare approximately $5.4$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 2003.2004 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 fiftyforty percent over threethe next two years and the remaining fiftysixty percent over approximately ten years). Approximately $0.7$1.1 million related to the terminated instruments has been reclassified into interest expense during the first halfnine months of 2004, and approximately $1.4$1.5 million will be reclassified for the entire year of 2004. In addition, earnings for the first halfnine 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.

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. Additionally, at times, a portion of our debt is denominated in Canadian dollars. At June 30, 2004, $4.0 million of our long-term debt was denominated in Canadian dollars ($5.3 million Canadian based on a Canadian dollar to U.S. dollar exchange rate of 1.33 to 1). All of these financial instruments are placed with what we believe to be large creditworthy financial institutions.

        At JuneSeptember 30, 2004, we had forward exchange contracts that allow us to exchange $2.0 million Canadian dollars for approximately $1.5 million U.S. dollars, quarterly, during 2004 and approximately $1.0 million Canadian for approximately $0.7 million U.S. quarterly during 2005 (based on a Canadian dollar to U.S. dollarat set exchange rate of 1.33 to 1 and 1.34 to 1, respectively).rates as detailed below: