================================================================================

                       SECURITIES AND EXCHANGE COMMISSION
                            WASHINGTON, D.C.  20549

                             ---------------------

                                    FORM 8-K

                                 CURRENT REPORT

                       Pursuant to Section 13 or 15(d) of
                      the Securities Exchange Act of 1934

       Date of Report (Date of earliest event reported) - March 14, 2002

                       PLAINS ALL AMERICAN PIPELINE, L.P.
                (Name of Registrant as specified in its charter)

          DELAWARE                         0-9808                 76-0582150
(State or other jurisdiction       (Commission File Number)   (I.R.S. Employer
of incorporation or organization)                            Identification No.)

                          333 CLAY STREET, SUITE 2900
                              HOUSTON, TEXAS 77002
                                 (713) 646-4100
              (Address, including zip code, and telephone number,
       including area code, of Registrant's principal executive offices)

                                      N/A
         (Former name or former address, if changed since last report.)

================================================================================

ITEM 7. FINANCIAL STATEMENTS AND EXHIBITS

        (c)  Exhibits

             23.1  Consent of PricewaterhouseCoopers LLP

             99.1  Plains All American Pipeline, L.P.'s Audited 2001
                   Consolidated Financial Statements

                                   SIGNATURES

     Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned hereunto duly authorized.

                            PLAINS ALL AMERICAN PIPELINE, L.P.

Date:  March 14, 2002       By:  Plains AAP, L.P., its general partner

                            By: Plains All American GP LLC, its general partner

                            By:     /s/ Phil Kramer
                                -----------------------------------------------
                            Name:   Phil Kramer
                            Title:  Executive Vice President and Chief
                                    Financial Officer

                                                                    EXHIBIT 23.1

                       CONSENT OF INDEPENDENT ACCOUNTANTS

We hereby consent to the incorporation by reference in the Registration
Statement on Form S-8 (Nos. 333-91141, 333-54118, 333-74920) and Form S-3 (Nos.
333-59224, 333-68446) of Plains All American Pipeline, L.P. of our report dated
March 6, 2002, relating to the consolidated financial statements, which appears
in this Current Report on Form 8-K.

Houston, Texas
March 14, 2002

                                                                    EXHIBIT 99.1

                      PLAINS ALL AMERICAN PIPELINE, L.P.
                  INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

                                                                                                                          Page
                                                                                                                          ----
                                                                                                                       
  Financial Statements

       Report of Independent Accountants.................................................................................  F-2

       Consolidated Balance Sheets as of December 31, 2001 and 2000......................................................  F-3

       Consolidated Statements of Operations for the years ended
          December 31, 2001, 2000 and 1999...............................................................................  F-4

       Consolidated Statements of Cash Flows for the years ended
          December 31, 2001, 2000 and 1999...............................................................................  F-5

       Consolidated Statements of Changes in Partners' Capital for the years ended
          December 31, 2001, 2000 and 1999...............................................................................  F-6

       Notes to Consolidated Financial Statements........................................................................  F-7

                                      F-1

                       REPORT OF INDEPENDENT ACCOUNTANTS

To the Board of Directors of the General Partner and the Unitholders of
Plains All American Pipeline, L.P.

In our opinion, the accompanying consolidated balance sheets and the related
consolidated statements of operations, of changes in partners' capital and of
cash flows present fairly, in all material respects, the financial position of
Plains All American Pipeline, L.P. and its subsidiaries (the "Partnership") at
December 31, 2001 and 2000, and the results of their operations and their cash
flows for each of the three years in the period ended December 31, 2001, 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 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 discussed in Note 2 to the consolidated financial statements, the Partnership
changed its method of accounting for derivatives and hedging activities
effective January 1, 2001.

PricewaterhouseCoopers LLP

Houston, Texas
March 6, 2002

                                      F-2

 PAGE>

              PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
                          CONSOLIDATED BALANCE SHEETS
                       (in thousands, except unit data)

                                                                                            December 31,
                                                                                  ----------------------------------
                                                                                        2001              2000
                                                                                  ----------------  ----------------
                                                                                              
                                     ASSETS

CURRENT ASSETS
Cash and cash equivalents                                                         $         3,511   $         3,426
Accounts receivable and other                                                             365,697           347,698
Inventory                                                                                 188,874            46,780
                                                                                  ----------------  ----------------
Total current assets                                                                      558,082           397,904
                                                                                  ----------------  ----------------

PROPERTY AND EQUIPMENT                                                                    653,050           467,619
Less allowance for depreciation and amortization                                          (48,131)          (26,974)
                                                                                  ----------------  ----------------
                                                                                          604,919           440,645
                                                                                  ----------------  ----------------

OTHER ASSETS
Pipeline linefill                                                                          57,367            34,312
Other, net                                                                                 40,883            12,940
                                                                                  ----------------  ----------------
                                                                                  $     1,261,251   $       885,801
                                                                                  ================  ================

                        LIABILITIES AND PARTNERS' CAPITAL

CURRENT LIABILITIES
Accounts payable and other current liabilities                                    $       386,993   $       328,542
Due to related party                                                                       13,685            20,951
Short-term debt and current portion of long-term debt                                     104,482             1,300
                                                                                  ----------------  ----------------
Total current liabilities                                                                 505,160           350,793

LONG-TERM LIABILITIES
Bank debt                                                                                 351,677           320,000
Other long-term liabilities and deferred credits                                            1,617             1,009
                                                                                  ----------------  ----------------
Total liabilities                                                                         858,454           671,802
                                                                                  ----------------  ----------------

COMMITMENTS AND CONTINGENCIES (Note 14)

PARTNERS' CAPITAL
Common unitholders (31,915,939 and 23,049,239 units outstanding
at December 31, 2001 and 2000, respectively)                                              408,562           217,073
Class B Common unitholders (1,307,190 units outstanding at each date)                      19,534            21,042
Subordinated unitholders (10,029,619 units outstanding at each date)                      (38,891)          (27,316)
General partner                                                                            13,592             3,200
                                                                                  ----------------  ----------------
                                                                                          402,797           213,999
                                                                                  ----------------  ----------------
                                                                                  $     1,261,251   $       885,801
                                                                                  ================  ================

                See notes to consolidated financial statements.

                                      F-3

              PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
                     CONSOLIDATED STATEMENTS OF OPERATIONS
                     (in thousands, except per unit data)

                                                                            Year Ended December 31,
                                                                ---------------------------------------------------
                                                                     2001             2000              1999
                                                                ---------------  ----------------  ----------------
                                                                                          
REVENUES                                                         $   6,868,215    $    6,641,187    $   10,910,423

COST OF SALES AND OPERATIONS                                         6,720,970         6,506,504        10,800,109

UNAUTHORIZED TRADING LOSSES
  AND RELATED EXPENSES (Note 3)                                              -             6,963           166,440

INVENTORY VALUATION ADJUSTMENT (Note 2)                                  4,984                 -                 -
                                                                ---------------  ----------------  ----------------
Gross Margin                                                           142,261           127,720           (56,126)
                                                                ---------------  ----------------  ----------------

EXPENSES
General and administrative                                              46,586            40,821            23,211
Depreciation and amortization                                           24,307            24,523            17,344
Restructuring expense                                                        -                 -             1,410
                                                                ---------------  ----------------  ----------------
Total expenses                                                          70,893            65,344            41,965
                                                                ---------------  ----------------  ----------------

OPERATING INCOME (LOSS)                                                 71,368            62,376           (98,091)

Interest expense                                                       (29,082)          (28,691)          (21,139)
Gain on sale of assets (Note 5)                                            984            48,188            16,457
Interest and other income (expense)                                        401            10,776               958
                                                                ---------------  ----------------  ----------------

Income (loss) before extraordinary item and
  cumulative effect of accounting change                                43,671            92,649          (101,815)
Extraordinary item (Note 10)                                                 -           (15,147)           (1,545)
Cumulative effect of accounting change (Note 9)                            508                 -                 -
                                                                ---------------  ----------------  ----------------
NET INCOME (LOSS)                                                $      44,179    $       77,502    $     (103,360)
                                                                ===============  ================  ================

NET INCOME (LOSS) - LIMITED PARTNERS                             $      42,239    $       75,754    $     (101,517)
                                                                ===============  ================  ================

NET INCOME (LOSS) - GENERAL PARTNER                              $       1,940    $        1,748    $       (1,843)
                                                                ===============  ================  ================

BASIC AND DILUTED NET INCOME (LOSS)
  PER LIMITED PARTNER UNIT
  Income (loss) before extraordinary item and
    cumulative effect of accounting change                       $        1.12    $         2.64    $        (3.16)
  Extraordinary item                                                         -             (0.44)            (0.05)
  Cumulative effect of accounting change                                  0.01                 -                 -
                                                                ---------------  ----------------  ----------------
  Net income (loss)                                              $        1.13    $         2.20    $        (3.21)
                                                                ===============  ================  ================

WEIGHTED AVERAGE UNITS OUTSTANDING                                      37,528            34,386            31,633
                                                                ===============  ================  ================

                See notes to consolidated financial statements.

                                      F-4

              PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
                     CONSOLIDATED STATEMENTS OF CASH FLOWS
                                (in thousands)

                                                                                       Year Ended December 31,
                                                                            ----------------------------------------------
                                                                                  2001            2000           1999
                                                                            ---------------  --------------  -------------
                                                                                                   
CASH FLOWS FROM OPERATING ACTIVITIES

Net income (loss)                                                            $      44,179    $    77,502    $   (103,360)
Items not affecting cash flows
  from operating activities:
    Depreciation and amortization                                                   24,307         24,523          17,344
    (Gain) loss on sale of assets (Note 5)                                            (984)       (48,188)        (16,457)
    Cumulative effect of accounting change                                            (508)             -               -
    Noncash compensation expense                                                     5,741          3,089           1,013
    Allowance for doubtful accounts                                                  3,000          5,000               -
    Inventory valuation adjustment                                                   4,984              -               -
    Other non cash items                                                              (207)         4,574           1,047
Change in assets and liabilities, net of acquisition:
    Accounts receivable and other                                                  (18,856)       120,497        (224,181)
    Inventory                                                                     (117,878)       (11,954)         34,772
    Accounts payable and other current liabilities                                  46,671       (161,543)        164,783
    Pipeline linefill                                                              (13,736)       (16,679)             (3)
    Other long-term liabilities and deferred credits                                   600         (8,591)         18,873
    Due (to) from related party                                                     (7,266)       (21,741)         34,924
                                                                            ---------------  --------------  -------------

Net cash provided by (used in) operating activities                                (29,953)       (33,511)        (71,245)
                                                                            ---------------  --------------  -------------

CASH FLOWS FROM INVESTING ACTIVITIES

Acquisitions (Note 4)                                                             (229,162)             -        (176,918)
Additions to property and equipment                                                (21,069)       (12,603)        (12,801)
Disposals of property and equipment and other (Note 5)                                 740        223,604           3,626
                                                                            ---------------  --------------  -------------

Net cash provided by (used in) investing activities                               (249,491)       211,001        (186,093)
                                                                            ---------------  --------------  -------------

CASH FLOWS FROM FINANCING ACTIVITIES

Proceeds from issuance of units (Note 7)                                           227,549              -          76,450
Costs incurred in connection with financing arrangements                            (6,351)        (6,748)        (17,243)
Subordinated notes - general partner                                                     -       (114,000)        114,000
Proceeds from long-term debt                                                     1,837,750      1,433,750         403,721
Proceeds from short-term debt                                                      492,005         51,300         131,119
Principal payments of long-term debt                                            (1,803,073)    (1,423,850)       (268,621)
Principal payments of short-term debt                                             (392,422)      (108,719)        (82,150)
Distributions to unitholders                                                       (75,929)       (59,565)        (51,673)
                                                                            ---------------  --------------  -------------

Net cash provided by (used in) financing activities                                279,529       (227,832)        305,603
                                                                            ---------------  --------------  -------------

Net increase (decrease) in cash and cash equivalents                                    85        (50,342)         48,265
Cash and cash equivalents, beginning of period                                       3,426         53,768           5,503
                                                                            ---------------  --------------  -------------

Cash and cash equivalents, end of period                                     $       3,511    $     3,426     $    53,768
                                                                            ===============  ==============  =============

                See notes to consolidated financial statements.

                                      F-5

              PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
            CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS' CAPITAL
                                (in thousands)

                                                                                                                    Total
                                                                Class B                                General    Partners'
                                         Common Units         Common Units       Subordinated Units    Partner     Capital
                                    ---------------------- ------------------- --------------------- ---------- ------------
                                      Units      Amount      Units     Amount    Units      Amount     Amount      Amount
                                    --------- ------------ --------- --------- --------- ----------- ---------- ------------
                                                                                           
Balance at December 31, 1998          20,059     $253,568        -   $      -    10,030   $  15,995   $    980    $ 270,543

Issuance of Class B Common Units           -            -    1,307     25,000         -           -        252       25,252

Noncash compensation expense               -            -        -          -         -           -      1,013        1,013

Issuance of units to public            2,990       50,654        -          -         -           -        544       51,198

Net loss                                   -      (62,598)       -     (3,218)        -     (35,701)    (1,843)    (103,360)

Distributions                              -      (33,265)       -     (1,234)        -     (15,915)    (1,259)     (51,673)
                                    --------- ------------ --------- --------- --------- ----------- ---------- ------------

Balance at December 31, 1999          23,049      208,359    1,307     20,548    10,030     (35,621)      (313)     192,973

Noncash compensation expense               -            -        -          -         -           -      3,089        3,089

Net income                                 -       50,780        -      2,878         -      22,096      1,748       77,502

Distributions                              -      (42,066)       -     (2,384)        -     (13,791)    (1,324)     (59,565)
                                    --------- ------------ --------- --------- --------- ----------- ---------- ------------

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 income                 -       (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
                                    ========= ============ ========= ========= ========= =========== ========== ============

                 See notes to consolidated financial statements.

                                       F-6

              PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
                  NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1 -- Organization and Basis of Presentation

   Organization

     We are a publicly traded Delaware limited partnership engaged in interstate
and intrastate marketing, transportation and terminalling of crude oil and
liquefied petroleum gas (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 affiliates ("Plains Resources") as a separate, publicly traded
master limited partnership.

     We completed our initial public offering (IPO) in November 1998, issuing
13.1 million common units at $20.00 per unit and received net proceeds of $244.7
million. Concurrently with the offering, Plains Resources sold certain assets to
us and contributed other assets in exchange for cash, common and subordinated
units, an aggregate 2% general partner interest, the right to receive incentive
distributions as defined in the partnership agreement and the assumption of
related indebtedness. Immediately after our initial public offering, Plains
Resources owned 100% of our general partner interest and an overall effective
ownership in the Partnership of 57% (including the 2% general partner interest
and common and subordinated units owned by it).

     In May 2001, senior management of our general partner and a group of
financial investors entered into a transaction with Plains Resources to acquire
control of the general partner interest and a majority of the outstanding
subordinated units. The transaction closed in June 2001, and for purposes of
this report is referred to as the "General Partner Transition." As a result of
this transaction, Plains Resources' ownership in the general partner was reduced
from 100% to 44%. Additionally, as a result of this transaction and various
equity offerings conducted since the IPO, Plains Resources' overall effective
ownership has been reduced to approximately 29%.

     The general partner interest is now 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. Our operations and activities
are managed by, and our officers and personnel are employed by, Plains All
American GP LLC. 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. We
use the phrase "former general partner" to refer to the subsidiary of Plains
Resources that formerly held the general partner interest.

     We conduct our operations through our wholly owned operating limited
partnerships Plains Marketing, L.P., All American Pipeline, L.P., and Plains
Marketing Canada, L.P. Our operations are concentrated in Texas, Oklahoma,
California, Louisiana and the Canadian provinces of Alberta, Saskatchewan and
Manitoba.

   Basis of Consolidation and Presentation

     The accompanying financial statements and related notes present our
consolidated financial position as of December 31, 2001 and 2000, and the
results of our operations, cash flows and changes in partners' capital for the
years ended December 31, 2001, 2000 and 1999. All significant intercompany
transactions have been eliminated. Certain reclassifications were made to prior
period amounts to conform with the current period presentation.

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 (1) estimated useful lives of assets,
which impacts depreciation and amortization, (2) allowance for doubtful accounts
receivable, (3) accruals related to revenues and expenses and (4) liability and
contingency accruals. Although we believe these estimates are reasonable, actual
results could differ from these estimates.

   Revenue Recognition

     Gathering and marketing revenues are accrued at the time title to the
product sold transfers to the purchaser, which occurs upon receipt of the
product by the purchaser. Terminalling and storage revenues are recognized at
the time service is performed. Revenues for the transportation of crude oil are
recognized either at the point of delivery or at the point of receipt pursuant
to regulated and non-regulated tariffs.

                                      F-7

    Cost of Sales and Operations

     Cost of sales and operations consists of the cost of crude oil,
transportation and storage fees, field and pipeline operating expenses and
letter of credit expenses. Field and pipeline operating expenses consist
primarily of fuel and power costs, telecommunications, labor costs for truck
drivers and pipeline field personnel, maintenance, utilities, insurance and
property taxes.

    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. 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.

     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. At December 31, 2001, approximately 93% of accounts receivable
were less than 60 days past scheduled invoice date. At December 31, 2001, our
allowance for doubtful accounts receivable totaled $3.0 million for receivables
included in current assets and $5.0 million for receivables classified as
long-term, representing 11% and 33%, respectively, of all balances greater than
60 days past scheduled invoice date. There was no allowance for doubtful
accounts at December 31, 1999. We consider these reserves adequate. Amounts due
from affiliated entities at December 31, 2001, totaled less than $0.6 million
and represented amounts due under current contracts in the ordinary course of
business or billings for reimbursing expenses that were collected subsequent to
year end. None of the accounts receivables are related to any equity investments
in the Partnership.

   Inventory

     Inventory consists of liquefied petroleum gas and crude oil 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.

   Property and Equipment and Pipeline Linefill

     Property and equipment is stated at cost and consists of (in thousands):

                                                               December 31,
                                                        ---------------------------
                                                            2001           2000
                                                        ------------    -----------
                                                                  
Crude oil pipelines                                       $ 470,671      $ 359,826
Crude oil pipeline facilities                                87,446         39,358
Crude oil storage and terminal facilities                    62,974         45,989
Trucking equipment, injection stations and other             25,599         19,435
Office property and equipment                                 6,360          3,011
                                                        ------------    -----------

                                                            653,050        467,619
Less accumulated depreciation and amortization              (48,131)       (26,974)
                                                        ------------    -----------

                                                          $ 604,919      $ 440,645
                                                        ============    ===========

                                       F-8

     Depreciation is computed using the straight-line method over estimated
useful lives as follows:

          .   crude oil pipelines - 30 years;
          .   crude oil pipeline facilities - 30 years;
          .   crude oil storage and terminal facilities - 30 to 40 years;
          .   trucking equipment, injection stations and other - 5 to 15 years;
              and
          .   office property and equipment - 5 years

     Acquisitions and improvements are capitalized; maintenance and repairs are
expensed as incurred.

     Pipeline linefill is recorded at cost and consists of liquefied petroleum
gas and crude oil linefill 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, 2001, we had approximately 2.6 million barrels of crude oil and
6.4 million gallons of liquefied petroleum gas used to maintain our minimum
operating linefill 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.

   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.
Fair value is generally determined from estimated discounted future net cash
flows.

   Other Assets

     Other assets consist of the following (in thousands):

                                                  December 31,
                                           ---------------------------
                                              2001           2000
                                           ------------   ------------
                                                    
Debt issue costs                              $ 17,293        $ 8,918
Long term receivable, net                       10,000          5,000
Goodwill                                         9,419            601
Intangible assets (contracts)                      980              -
Other                                            7,649            169
                                           ------------   ------------

                                                45,341         14,688
Less accumulated amortization                   (4,458)        (1,748)
                                           ------------   ------------

                                              $ 40,883       $ 12,940
                                           ============   ============

     Costs incurred in connection with the issuance of long-term debt 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. Goodwill is recorded as the
amount of the purchase price in excess of the fair value of certain assets
purchased. In accordance with Statement of Financial Accounting Standards (SFAS)
No. 142, "Goodwill and Other Intangible Assets", which we will adopt in its
entirety January 1, 2002, we will test goodwill and other intangible assets
periodically to determine whether an impairment has occurred. An impairment
occurs when the carrying amount of an asset exceeds the fair value of the
recognized goodwill or intangible asset. If impairment occurs, the loss is
recorded in the period.

    Income and Other Taxes

     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 bases
cannot be readily determined. Accordingly, we do not believe that in our
circumstances, the aggregate difference would be meaningful information.

                                       F-9

     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 2001, the income tax was not material and the
capital-based tax was approximately $0.4 million (U.S.). 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
2001 totaled $0.3 million 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 and to pay Canadian federal and provincial income taxes and
to file state income tax returns and to pay taxes in various states.

   Hedging

     We utilize various derivative instruments, for purposes other than trading,
to hedge our exposure to price fluctuations on crude oil and liquefied petroleum
gas in storage and expected purchases, sales and transportation of those
commodities. The derivative instruments consist primarily of futures and option
contracts traded on the New York Mercantile Exchange and over-the-counter
transactions including crude oil swap contracts entered into with financial
institutions. We also utilize interest rate and foreign exchange swaps and
collars to manage the interest rate exposure on our long-term debt and foreign
exchange exposure arising from our Canadian operations.

     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". Generally for our domestic U.S. operations, these derivative
instruments qualify for hedge accounting as they reduce the price risk of the
underlying hedged item and are designated as a hedge at inception. These
derivative hedges result in financial impacts that are inversely correlated to
those of the items being hedged. This correlation, generally in excess of 80% (a
measure of hedge effectiveness), is measured both at the inception of the hedge
and on an ongoing basis. To qualify for hedge accounting treatment, companies
must formally document, designate and assess the effectiveness of these
transactions. If the necessary correlation ceases to exist or if physical
delivery of the hedged item becomes improbable, we would discontinue hedge
accounting and apply mark to market accounting. Gains and losses on the
termination of hedging instruments are deferred and recognized in income as the
impact of the hedged item is recorded.

     SFAS 133 requires that changes in derivative contracts' fair value be
recognized currently in earnings unless specific hedge accounting criteria are
met. We have some derivative contracts, primarily related to our LPG activities,
that do not receive hedge treatment, as the correlation is not consistently at
the necessary level between prices for those markets or commodities and the
hedging instrument. As a result, gains and losses on those derivative contracts
impact earnings directly. The intent of entering into these transactions,
however, is to mitigate price exposure arising from those operations.

     Aside from the exceptions noted above, unrealized changes in the market
value of crude oil or LPG hedge contracts are not generally recognized in our
consolidated statement of operations until the underlying hedged transaction
occurs. The financial impacts of these hedge contracts are included in our
consolidated statements of operations as a component of revenues. Such financial
impacts are offset by gains or losses realized in the physical market. Cash
flows from these hedging activities are included in operating activities in the
accompanying consolidated statements of cash flows. Net deferred gains and
losses on futures contracts (including closed futures contracts) entered into to
hedge anticipated crude oil and LPG purchases and sales, are included in current
assets or current liabilities in the accompanying consolidated balance sheets.
Deferred gains or losses from inventory hedges are included as part of the
inventory costs and recognized when the related inventory is sold.

     Amounts paid or received from interest rate swaps and collars are charged
or credited to interest expense and matched with the cash flows and interest
expense of the debt being hedged, resulting in an adjustment to the effective
interest rate.

   Net Income Per Unit

     Basic and diluted net income (loss) per unit is determined by dividing net
income (loss) 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 common units and subordinated
units. Partnership income (loss) is first allocated according to percentage
ownership in the Partnership and then reallocated between the limited partners
and general partner based on the amount of incentive distributions. Basic and

                                      F-10

diluted net income (loss) per unit for 2001, 2000 and 1999 is as follows (in
thousands, except per unit data):

                                                                    Year Ended December 31,
                                                         --------------------------------------------
                                                             2001            2000           1999
                                                         -------------   -------------  -------------
                                                                               
               Net income (loss)                          $     44,179    $     77,502   $   (103,360)

               Less:
                 General partner incentive distributions        (1,056)           (198)          (224)
                 General partner 2% ownership                     (884)         (1,550)         2,067
                                                         -------------   -------------  -------------

               Net income (loss) attributable to
                 limited partners                         $     42,239    $     75,754   $   (101,517)
                                                         =============   =============  =============

               Weighted average units outstanding               37,528          34,386         31,633
                                                         =============   =============  =============

               Basic and diluted net income (loss)
                 per limited partner unit                     $   1.13        $   2.20      $   (3.21)
                                                         =============   =============  =============

   Foreign Currency Translation

     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 and
expenses are translated using the average exchange rate during the reporting
period.

   Recent Accounting Pronouncements

     In June 2001, the Financial Accounting Standards Board ("FASB") issued SFAS
141 "Business Combinations" and SFAS 142 "Goodwill and Other Intangible Assets".
SFAS 141 requires all business combinations initiated after June 30, 2001 (see
Note 4), to be accounted for under the purchase method. For all business
combinations for which the date of acquisition is after June 30, 2001, this
Standard also establishes specific criteria for the recognition of intangible
assets separately from goodwill. We have adopted SFAS 142 effective January 1,
2002. SFAS 142 changes the accounting for goodwill and other intangible assets
after an acquisition. The most significant changes made by SFAS 142 are: 1)
goodwill and intangible assets with indefinite lives will no longer be
amortized; 2) goodwill and intangible assets with indefinite lives must be
tested for impairment at least annually; and 3) the amortization period for
intangible assets with finite lives will no longer be limited to forty years. In
conjunction with the adoption of SFAS 142, amortization on the unamortized
portion of the goodwill arising from previous acquisitions will cease in 2002.
The adoption of SFAS 142 will not have a material effect on either our financial
position, results of operations, or cash flows.

     In June 2001, the FASB also issued SFAS 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 an
asset retirement cost 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. We will adopt the statement effective January 1, 2003, as
required. The transition adjustment resulting from the adoption of SFAS 143 will
be reported as a cumulative effect of a change in accounting principle. At this
time, we cannot reasonably estimate the effect of the adoption of this statement
on either our financial position, results of operations, or cash flows.

     In August 2001, the FASB approved SFAS 144, "Accounting for Impairment
or Disposal of Long-Lived Assets". SFAS 144 establishes a single accounting
model for long-lived assets to be disposed of by sale and provides additional
implementation guidance for assets to be held and used and assets to be disposed
of other than by sale. Upon adoption of this Statement effective January 1,
2002, there was no effect on either our financial position, results of
operations or cash flows.

     In June 1998, the FASB issued SFAS 133, which was subsequently amended (i)
in June 1999 by SFAS 137, "Accounting for Derivative Instruments and Hedging
Activities - Deferral of the Effective Date of FASB Statement No. 133", which
deferred the effective date of SFAS 133 to fiscal years beginning after June 15,
2000; and (ii) in June 2000 by SFAS 138, "Accounting for Certain Derivative
Instruments and Certain Hedge Activities," which amended certain provisions,
inclusive of the definition of the normal purchase and sale exclusion. We have
determined that our physical purchase and sale agreements qualify for the normal
purchase and sale exclusion.

     SFAS 133 requires that all derivative instruments be recorded on the
balance sheet as either assets or liabilities measured at their fair value.
Changes in the fair value of derivatives are recorded each period in current
earnings or other

                                      F-11

comprehensive income, depending on whether a derivative is designated as part of
a hedge transaction and, if so, the type of hedge transaction. For fair value
hedge transactions in which we are hedging changes in the fair value of an
asset, liability, or firm commitment, changes in the fair value of the
derivative instrument will generally be offset in the income statement by
changes in the fair value of the hedged item. For cash flow hedge transactions,
in which we are hedging the variability of cash flows related to a variable-rate
asset, liability, or a forecasted transaction, changes in the fair value of the
derivative instrument will be reported in other comprehensive income, a
component of partners' capital. The gains and losses on the derivative
instrument that are reported in other comprehensive income will be reclassified
as earnings in the periods in which earnings are affected by the variability of
the cash flows of the hedged item. The ineffective portion of all hedges will be
recognized in earnings in the current period. Hedge effectiveness is measured at
least quarterly based on the relative cumulative changes in fair value between
the derivative contract and the hedged item over time.

     We adopted SFAS 133, as amended, effective January 1, 2001. Our
implementation procedures identified all instruments in place at the adoption
date that are subject to the requirements of SFAS 133. Upon adoption, we
recorded a cumulative effect charge of $8.3 million in accumulated other
comprehensive income to recognize at fair value all derivative instruments that
are designated as cash flow hedging instruments and a cumulative effect gain of
$0.5 million to earnings. Correspondingly, an asset of $2.8 million and a
liability of $10.6 million were established. Hedge losses/gains included in
accumulated other comprehensive income are transferred to earnings as the
forecasted transactions actually occur. Implementation issues continue to be
addressed by the FASB and any change to existing guidance might impact our
implementation. Adoption of this standard will most likely increase volatility
in earnings and partners' capital through comprehensive income.

Note 3 -- Unauthorized Trading Losses

     In November 1999, we discovered that a former employee had engaged in
unauthorized trading activity, resulting in losses of approximately $162.0
million ($174.0 million, including estimated associated costs and legal
expenses). 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 from March through November 1999.
Approximately $7.1 million of the unauthorized trading losses was recognized in
1998 and the remainder in 1999. In 2000, we recognized an additional $7.0
million charge for litigation related to the unauthorized trading losses (see
Note 14).

Note 4 -- Acquisitions

   Wapella Pipeline System

     In December 2001, we acquired the Wapella Pipeline System from private
investors for approximately $12.0 million, including transaction costs. The
system is located in southeastern Saskatchewan and southwestern Manitoba. In
2001, the Wapella Pipeline System delivered approximately 11,000 barrels per day
of crude oil to the Enbridge Pipeline at Cromer, Manitoba. The acquisition also
includes approximately 21,500 barrels of crude oil storage capacity located
along the system as well as a truck terminal. Initial financing for the
acquisition was provided through borrowings under our bank credit facility.

     The Wapella acquisition has been accounted for using the purchase method of
accounting and the purchase price was allocated in accordance with SFAS 141 (see
Note 2). The purchase price allocation is as follows (in thousands):

               Crude oil pipeline, gathering and terminal assets    $   10,251
               Other property and equipment                              1,720
                                                                  ------------
               Total                                                $   11,971
                                                                  ============

   CANPET Energy Group Inc.

     In July 2001, we acquired the assets of CANPET Energy Group Inc.
("CANPET"), a Calgary-based Canadian crude oil and liquefied petroleum gas
marketing company, for approximately $42.0 million plus excess inventory at the
closing date of approximately $25.0 million. Approximately $24.0 million of the
purchase price plus $25.0 million for the additional inventory was paid in cash
at closing, and the remainder, which is subject to certain performance
standards, will be paid in common units in April 2004, if such standards are
met. 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
working capital of approximately $8.6 million. Initial financing for the
acquisition was provided through borrowings under our bank credit facility.

                                      F-12

     The CANPET acquisition has been accounted for using the purchase method of
accounting and the purchase price was allocated in accordance with SFAS 141 (see
Note 2). The purchase price allocation is as follows (in thousands):

                                                               
                    Inventory                                      $ 29,708
                    Goodwill                                          8,818
                    Intangible assets (contracts)                       980
                    Other assets, including debt issue costs          1,661
                    Pipeline linefill                                 4,332
                    Crude oil gathering and terminal assets           4,243
                    Other property and equipment                        502
                                                                  ---------
                    Total                                          $ 50,244
                                                                  =========

   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 $161.0 million in cash ("the Murphy
Acquisition"), including financing and transaction costs. Initial financing for
the acquisition was provided through borrowings under our bank credit
facilities. The purchase included $6.5 million for excess inventory in the
pipeline systems. The principal assets acquired include approximately 450 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, an inactive 108-mile mainline system and
121 trailers used primarily for crude oil transportation. We have reactivated
the 108-mile mainline system and began shipping volumes in May of 2001.

     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 Murphy Acquisition has been accounted for using the purchase method of
accounting and the purchase price was allocated in accordance with Accounting
Principles Board Opinion No. 16, Business Combinations ("APB 16"). The purchase
price allocation, as adjusted pursuant to the provisions of the purchase and
sale agreement upon resolution of an outstanding pipeline tariff dispute, is as
follows (in thousands):

                 Crude oil pipeline, gathering and terminal assets    $145,106
                 Pipeline linefill                                       7,602
                 Net working capital items                               1,953
                 Other property and equipment                              487
                 Other assets, including debt issue costs                  360
                                                                      --------
                 Total                                                $155,508
                                                                      ========

                                      F-13

   Pro Forma Results for the Murphy and CANPET Acquisitions

     The following unaudited pro forma data is presented to show pro forma
revenues, net income and basic and diluted net income per limited partner unit
for the Partnership as if the Murphy and CANPET acquisitions had occurred on
January 1, 2000 (in thousands):

                                                                             Year Ended December 31,
                                                                         -----------------------------
                                                                            2001 (1)        2000 (1)
                                                                         --------------  -------------
                                                                                   
          Revenues                                                        $   7,043,143   $  7,330,621
                                                                         ==============  =============

          Income before extraordinary item and cumulative
             effective of accounting change                               $      51,905   $     98,821
                                                                         ==============  =============
          Net income                                                      $      52,413   $     83,674
                                                                         ==============  =============
          Basic and diluted income before extraordinary item and
             cumulative effect of accounting change per
             limited partner unit                                         $        1.32   $       2.81
                                                                         ==============  =============
          Basic and diluted net income per limited partner unit           $        1.33   $       2.38
                                                                         ==============  =============

          _________________

          (1)  The pro forma information does not include the results of the
               Wapella acquisition as it would not differ materially from the
               reported results.

   Scurlock Acquisition

     On May 12, 1999, we completed the acquisition of Scurlock Permian LLC 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.

     Financing for the Scurlock acquisition was provided through:

        .  borrowings of approximately $92.0 million under a previous bank
           facility;
        .  the sale to our former general partner of 1.3 million of our Class B
           common units for a total cash consideration of $25.0 million, or
           $19.125 per unit, the price equal to the market value of our common
           units on May 12, 1999; and
        .  a $25.0 million draw under our revolving credit agreement.

     The assets, liabilities and results of operations of Scurlock are included
in our consolidated financial statements effective May 1, 1999. The Scurlock
acquisition has been accounted for using the purchase method of accounting and
the purchase price was allocated in accordance with APB 16 as follows (in
thousands):

          Crude oil pipeline, gathering and terminal assets    $  125,120
          Other property and equipment                              1,546
          Pipeline linefill                                        16,057
          Other assets (debt issue costs)                           3,100
          Other long-term liabilities (environmental accrual)      (1,000)
          Net working capital items                                (3,090)
                                                              -----------

          Cash paid                                            $  141,733
                                                              ===========

     The purchase accounting entries include a $1.0 million accrual for
estimated environmental remediation costs. Under the agreement for the sale of
Scurlock by Marathon Ashland Petroleum, Marathon Ashland Petroleum has agreed to
indemnify us and hold us harmless for claims, liabilities and losses resulting
from any act or omission attributable to Scurlock's business or properties
occurring prior to the date of the closing of such sale to the extent the
aggregate amount of such losses exceed $1.0 million; provided, however, that
claims for such losses must individually exceed $25,000 and must be asserted by
us against Marathon Ashland Petroleum on or before May 15, 2003.

    West Texas Gathering System Acquisition

     On July 15, 1999, we completed the acquisition of a West Texas crude oil
pipeline and gathering system from Chevron Pipe Line Company for approximately
$36.0 million, including transaction costs. Our total acquisition cost was
approximately $38.9 million including costs to address certain issues identified
in the due diligence process. The principal assets acquired include
approximately 450 miles of crude oil transmission mainlines, approximately 400
miles of associated gathering and lateral lines and approximately 2.9 million
barrels of crude oil storage and terminalling capacity in Crane,

                                      F-14

Ector, Midland, Upton, Ward and Winkler Counties, Texas. Financing for the
amounts paid at closing was provided by a draw under a previous credit facility.

Note 5 -- Asset Disposition

     In December 2001, we sold excess communications equipment remaining from
the sale of the All American Pipeline discussed below and recognized a gain of
$1.0 million.

     In March 2000, we sold to a unit of El Paso Corporation for $129.0 million
the segment of the All American Pipeline that extends from Emidio, California to
McCamey, Texas. 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 the acquisition of the line from Goodyear 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 gains of approximately $28.1 million
and $16.5 million in 2000 and 1999, respectively, in connection with the sale of
the linefill.

Note 6 -- Debt

     Short-term debt and current maturities of long-term debt consist of the
following (in thousands):

                                                                                             December 31,
                                                                                      --------------------------
                                                                                          2001           2000
                                                                                      ------------   -----------
                                                                                               
          $200.0 million senior secured letter of credit and borrowing facility
            bearing interest at a weighted average interest rate of 3.8% at
            December 31, 2001, and 8.4% at December 31, 2000                            $  100,000       $ 1,300
          Other                                                                              1,482             -
                                                                                      ------------   -----------
                                                                                           101,482         1,300
          Current portion of long-term debt                                                  3,000             -
                                                                                      ------------   -----------
            Total short-term debt and current maturities of long-term debt              $  104,482       $ 1,300
                                                                                      ============   ===========

     Long-term debt consists of the following (in thousands):

                                                                                             December 31,
                                                                                      --------------------------
                                                                                          2001          2000
                                                                                      ------------   -----------
                                                                                               
          $450.0 million senior secured domestic revolving credit facility, bearing
            interest at a weighted average interest rate of 4.5% at
            December 31, 2001, and 9.2% at December 31, 2000                            $   27,450     $ 320,000

          $200.0 million senior secured term B loan, bearing interest at a weighted
            average interest rate of 4.5% at December 31, 2001                             200,000             -

          $100.0 million senior secured term loan, bearing interest at a weighted
            average interest rate of 4.4% at December 31, 2001                             100,000             -

          $30.0 million Canadian senior secured revolving credit facility, bearing
            interest at a weighted average interest rate of 4.4% at
            December 31, 2001                                                               27,227             -
                                                                                      ------------   -----------
                                                                                           354,677       320,000
          Less current maturities                                                           (3,000)            -
                                                                                      ------------   -----------
            Total long-term debt                                                        $  351,677     $ 320,000
                                                                                      ============   ===========

                                      F-15

     In September 2001, we amended and expanded our credit facilities to include
a six-year, $200.0 million term B loan. In connection with this amendment, we
reduced the revolving portion of the facilities by $50.0 million. Our credit
facilities currently consist of:

         .   a $780.0 million senior secured revolving credit and term loan
             facility, which is secured by substantially all of our assets. The
             facility consists of (i) a $450.0 million domestic revolving
             facility (reflecting the $50 million reduction in such facility in
             connection with the September amendment), with a $10.0 million
             letter of credit sublimit, (ii) a $30.0 million Canadian revolving
             facility (with a $5.0 million letter of credit sublimit), (iii) a
             $100.0 million term loan and (iv) a $200.0 million term B loan. The
             facility matures, (i) as to the aggregate $480.0 million domestic
             and Canadian revolver portions, in April 2005, (ii) as to the
             $100.0 million term portion, in May 2006, and, (iii) as to the
             $200.0 million term B loan portion, September 2007. On the revolver
             portions, no principal is scheduled for payment prior to maturity.
             The $100.0 million term loan portion of this facility has four
             scheduled annual payments of principal, commencing May 4, 2002, in
             the respective amounts of 1%, 7%, 8% and 8% of the original term
             principal amount, with the remaining principal balance scheduled
             for payment on the stated maturity date of May 5, 2006. If any part
             of the term portion is prepaid prior to its first anniversary, a 1%
             premium will be due on that portion. The $200.0 million term B loan
             has 1% payable yearly commencing on September 21, 2002, with the
             remaining principal balance scheduled for payment on the stated
             maturity date of September 26, 2007. The term B loan may be prepaid
             without penalty. The revolving credit and term loan facility bears
             interest at our option at either the base rate, as defined, plus an
             applicable margin, or LIBOR plus an applicable margin, and further,
             the Canadian revolver may effectively bear interest based upon
             bankers' acceptance rates. We incur a commitment fee on the unused
             portion of the revolver portion of this credit facility.

         .   a $200.0 million senior secured letter of credit and borrowing
             facility, the purpose of which is to provide standby letters of
             credit to support the purchase and exchange of crude oil and other
             specified petroleum products for resale and borrowings to finance
             crude oil inventory and other specified petroleum products that
             have been hedged against future price risk. The letter of credit
             facility is secured by substantially all of our assets and has a
             sublimit for cash borrowings of $100.0 million to purchase crude
             oil and other petroleum products that have been hedged against
             future price risk and to fund margin requirements under NYMEX
             contracts used to facilitate our hedging activities. The letter of
             credit facility expires in April 2004. Aggregate availability under
             the letter of credit facility for direct borrowings and letters of
             credit is limited to a borrowing base that is determined monthly
             based on certain of our current assets and current liabilities,
             primarily inventory and accounts receivable and accounts payable
             related to the purchase and sale of crude oil and other specified
             petroleum products. We incur a commitment fee on the unused portion
             of this facility.

     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;
         .   grant liens;
         .   sell assets;
         .   make investments;
         .   engage in transactions with affiliates;
         .   enter into certain contracts; and
         .   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 current ratio (as defined) of 1.0 to 1.0;
         .   a debt coverage ratio which is not greater than 4.00 to 1;
         .   an interest coverage ratio which is not less than 2.75 to 1.0; and
         .   a debt to capital ratio of not greater than 0.70 to 1.0 prior to
             December 31, 2002, and 0.65 to 1.0 thereafter.

     A default under our credit facilities would permit the lenders to
accelerate the maturity of the outstanding debt and to foreclose on the assets
securing the credit facilities. As long as we are in compliance with our
commercial credit agreements, they do not restrict our ability to make
distributions of "available cash" as defined in our partnership agreement. We
are currently in compliance with the covenants contained in our credit
agreements.

                                      F-16

     The credit facilities provide that the Partnership may issue up to $400.0
million of senior unsecured debt that has a maturity date extending beyond the
maturity date of the credit facilities. If senior unsecured debt is issued, the
aggregate amount available under the $450.0 million U.S. revolving credit
facility will be reduced by an amount equal to (a) 40% of the face amount of the
senior unsecured debt if the aggregate amount of new debt issued is less than
$350.0 million, or (b) 50% of the face amount of the senior unsecured debt if
the aggregate amount of new debt issued is equal to or greater than $350.0
million; provided, however, in both cases, the amount of the revolver reduction
is decreased by $50.0 million.

     In January 2002, we amended our credit facility to remove a condition
requiring us to obtain lender approval before making any acquisition greater
than $50.0 million to provide the Partnership with greater structuring
flexibility to finance larger acquisitions.

   Maturities

     The aggregate amount of maturities of all long-term indebtedness at
December 31, 2001, for the next five years is: 2002 - $3.0 million, 2003 - $9.0
million, 2004 - $10.0 million, 2005 - $64.7 million, 2006 and thereafter -$268.0
million.

Note 7 - Partners' Capital and Distributions

     Partners' capital consists of (1) 33,223,129 common units, including
1,307,190 Class B common units, representing a 75.3% effective aggregate
ownership interest in the Partnership and its subsidiaries, (after giving affect
to the general partner interest), (2) 10,029,619 Subordinated units representing
a 22.7% effective aggregate ownership interest in the Partnership and its
subsidiaries limited partner interest (after giving affect to the general
partner interest) and (3) a 2% general partner interest.

     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.

     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. Distributions of available cash to holders of subordinated units
are subject to the prior rights of holders of common units to receive the
minimum quarterly distribution ("MQD") for each quarter during the subordination
period and to receive any arrearages in the distribution of the MQD on the
common units for the prior quarters during the subordination period. There were
no arrearages on common units at December 31, 2001. The MQD is $0.45 per unit
($1.80 per unit on an annual basis). Common units will not accrue arrearages
with respect to distributions for any quarter after the subordination period and
subordinated units will not accrue any arrearages with respect to distributions
for any quarter.

     The subordination period (as defined in the partnership agreement) will end
if certain financial tests are met for three consecutive four-quarter periods
(the "testing period"), but not sooner than December 31, 2003. During the first
quarter after the end of the subordination period, all of the subordinated units
will convert into common units, and will participate pro rata with all other
common units in future distributions. Early conversion of a portion of the
subordinated units may occur if the testing period is satisfied before December
31, 2003. We have determined that the first four-quarter period of the testing
period was satisfied as of September 30, 2001. Although we cannot give assurance
in that regard, if we continue to meet the requirements, 25% of the subordinated
units will convert in the fourth quarter of 2003 and the remainder will convert
in the first quarter of 2004.

     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 to 15% of amounts we distribute in
excess of $0.450 per unit, 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. Cash
distributions for the first, second, third and fourth quarters of 2001 were
$0.4750, $0.5000, $0.5125 and $0.5125, respectively, per unit on our outstanding
common units, Class B units and subordinated units, representing an excess of
$0.025, $0.050, $0.0625 and $0.0625 per unit, respectively, over the MQD. Cash
distributions for the second, third and fourth quarters of 2000 were $0.4625 per
unit on our outstanding common units, Class B units and subordinated units,
representing an excess of $0.0125 per unit over the MQD. Cash distributions for
the second and third quarters of 1999 were $0.4625 and $0.4812 per unit,
respectively, on our outstanding common units, Class B units and subordinated
units, representing an excess of $0.0125 per unit and $0.0312 per unit,
respectively, over the MQD. Distributions were not paid on the subordinated
units for the fourth quarter of 1999.

                                      F-17

     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.

Note 8 -- Comprehensive Income

     Comprehensive income includes net income and certain items recorded
directly to Partners' Capital and classified as Other Comprehensive Income
(OCI). Such amounts are allocated in proportion to the limited partners and
general partners interest. Following the adoption of SFAS 133, we recorded a
charge to OCI of $8.3 million related to the change in fair value of certain
derivative financial instruments that qualified for cash flow hedge accounting.
The following table reflects comprehensive income for the year ended
December 31, 2001 (in thousands):

       Total comprehensive income at January 1, 2001              $        -
         Cumulative effect of change in accounting principle          (8,337)
         Reclassification adjustment for settled contracts            (2,526)
         Changes in fair value of outstanding hedging positions        6,123
         Currency translation adjustment                              (8,002)
                                                                 -----------
       Other comprehensive income (loss)                             (12,742)
         Net income                                                   44,179
                                                                 -----------
       Total comprehensive income at December 31, 2001            $   31,437
                                                                 ===========

Note 9 -- Financial Instruments

   Derivatives

     On January 1, 2001, we adopted SFAS 133 "Accounting for Derivative
Instruments and Hedging Activities" as amended by SFAS 137 and SFAS 138. In
accordance with the transition provisions of SFAS 133, we recorded a loss of
$8.3 million in 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.

     At December 31, 2001, a $4.7 million unrealized loss was recorded to OCI
together with related assets and liabilities of $4.2 million and $8.2 million,
respectively. Earnings included a noncash gain of $0.2 million (excluding the
$0.5 million gain related to the cumulative effect of accounting change upon
adoption of SFAS 133) related to the ineffective portion of our cash flow
hedges, as well as certain derivative contracts that did not qualify as hedges
primarily relating to our LPG activities due to a low correlation between the
futures contract and hedged item. Our hedge-related assets and liabilities are
included in other current assets and other current liabilities in the
consolidated balance sheet.

     As of December 31, 2001, the total amount of deferred net losses on
derivative instruments recorded in OCI are expected to be reclassified to
earnings during 2002 and 2003. The following table sets forth our open crude oil
hedge positions at December 31, 2001. These are futures hedges and have
offsetting physical exposures to the extent they are effective.

                                                  2002                                               2003
                             ------------------------------------------------    ---------------------------------------------
                                1st Qtr      2nd Qtr      3rd Qtr    4th Qtr      1st Qtr     2nd Qtr    3rd Qtr     4th Qtr
                             ------------ ------------ ------------ ---------    --------- ------------ --------- ------------
                                                                                          
     Volume (bbls)
         Short positions       1,228,000             -      200,000         -            -      200,000         -    1,800,000
         Long positions                -     1,053,000            -         -            -            -         -            -
     Average price ($/bbl)   $     20.64   $     22.73   $    19.53  $      -     $      -   $    21.26   $     -   $    21.23

     Interest rate swaps and collars are used to hedge underlying interest
obligations. These instruments hedge interest rates on specific debt issuances
and qualify for hedge accounting. The interest rate differential is reflected as
an adjustment to interest expense over the life of the instruments. At December
31, 2001, we had interest rate swap and collar arrangements for an aggregate
notional principal amount of $275.0 million for which we would pay approximately
$5.3 million if such arrangements were terminated as of such date.

                                      F-18

     The table shown below summarizes the fair value of our interest rate swaps
and collars by year of maturity (in thousands):

                                              Year of Maturity
                                    ------------------------------------------
                                       2002       2003      2004       Total
                                    --------    --------   -------    --------
                                                          
          Interest rate swaps       $     --    $  (810)   $   (689)   $ (1,499)
          Interest rate collars       (3,777)        --          --      (3,777)
                                    --------    --------   --------    --------

             Total                  $ (3,777)   $  (810)   $   (689)   $ (5,276)
                                    ========    ========   ========    ========

     The adjustment to interest expense resulting from interest rate swaps for
the years ended December 31, 2001, 2000 and 1999 was a $2.4 million loss, a $0.1
million gain and a $0.1 million loss, respectively. These instruments are based
on LIBOR rates. The collar provides for a floor of 6.1% and a ceiling of 8.0%
with an expiration date of August 2002 for $125.0 million notional principal
amount. The fixed rate interest rate swaps provide for a rate of 4.3% for $50.0
million notional principal amount expiring March 2004, and a rate of 3.6% for
$100.0 million notional principal amount expiring September 2003.

     We formally document all relationships between hedging instruments and
hedged items, as well as our risk management objectives and strategy for
undertaking the hedge. Hedge effectiveness is measured on a quarterly basis.
This process includes specific identification of the hedging instrument and the
hedge 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. No amounts were excluded from the computation of hedge
effectiveness.

     Since substantially all of our Canadian business is conducted in Canadian
dollars (CAD), we use certain financial instruments to minimize the risks of
changes in the exchange rate. These instruments include forward exchange
contracts, forward extra option contracts and cross currency swaps.
Additionally, at December 31, 2001, $25.4 million ($40.5 million CAD) of our
long-term debt was denominated in Canadian dollars. All of the financial
instruments utilized are placed with large creditworthy financial institutions
and meet the criteria under SFAS 133 for hedge accounting treatment.

     At December 31, 2001, 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. (based on a Canadian-U.S. dollar exchange rate of 1.55)
quarterly during 2002 and 2003. If these contracts were terminated on December
31, 2001, we would receive $0.5 million U.S. At December 31, 2001, we also had a
cross currency swap contract for an aggregate notional principal amount of $25.0
million, effectively converting this amount of our $100.0 million senior secured
term loan (25% of the total) from U.S. dollars to $38.7 million of Canadian
dollar debt (based on a Canadian-U.S. dollar exchange rate of 1.55). The terms
of this contract mirror the term loan, matching the amortization schedule and
final maturity in May 2006. If this swap contract was terminated on
December 31, 2001, we would receive $0.5 million U.S.

     The table shown below summarizes the fair value of our foreign currency
hedges by year of maturity (in thousands):

                                                      Year of Maturity
                                         --------------------------------------
                                          2002       2003    2006(1)    Total
                                         ------     ------   -------    -------
                                                            
          Forward exchange contracts     $  123     $  100    $  --     $   223
          Forward extra options             145        146       --         291
          Cross currency swaps               --         --      497         497
                                         ------     ------    -----     -------

            Total                        $  268     $  246    $ 497     $ 1,011
                                         ======     ======    =====     =======

          ____________

          (1)  At December 31, 2001, we did not have foreign currency hedges
               expiring in 2004 or 2005.

   Fair Value of Financial Instruments

     The carrying values of items comprising current assets and current
liabilities approximate fair value due to the short-term maturities of these
instruments. The carrying value of bank debt approximates fair value as interest
rates are variable, based on prevailing market rates. Crude oil futures
contracts permit settlement by delivery of the crude oil and, therefore, are not

                                      F-19

financial instruments, as defined. The fair value of crude oil swap and option
contracts and interest rate swap and collar agreements are based on current
termination values or quoted market prices of comparable contracts.

     The carrying amounts and fair values of our financial instruments are as
follows (in thousands):

                                                                          December 31,
                                                     ------------------------------------------------------
                                                                2001                        2000
                                                     --------------------------  --------------------------
                                                       Carrying        Fair        Carrying        Fair
                                                        Amount         Value        Amount         Value
                                                     ------------  ------------  ------------  ------------
                                                                                   
          Unrealized gain (loss) on interest rate
            swaps and collars                           $ (5,276)     $ (5,276)          $ -        $ (561)

Note 10 --  Early Extinguishment of Debt

     During 2000, we recognized extraordinary losses, consisting primarily of
unamortized debt issue costs, totaling $15.1 million related to the permanent
reduction of the All American Pipeline, L.P. term loan facility and the
refinancing of our credit facilities. In addition, interest and other income for
the year ended December 31, 2000, included $9.7 million of previously deferred
gains from terminated interest rate swaps as a result of debt extinguishments
(see Note 3). The extraordinary loss of $1.5 million in 1999 relates to the
write-off of certain debt issue costs and penalties associated with the
prepayment of debt.

Note 11 -- Major Customers and Concentration of Credit Risk

     Customers accounting for 10% or more of revenues were as follows for the
periods indicated:

                                                                         Percentage
                                                                  Year Ended December 31,
                                                          ----------------------------------------
                                                             2001          2000           1999
                                                          ------------  ------------   -----------
                                                                              
               Marathon Ashland Petroleum                          11%           12%           -
               Sempra Energy Trading Corporation                    -             -           22%
               Koch Oil Company                                     -             -           19%

     All of the customers above pertain to our marketing, gathering,
terminalling and storage segment. We believe that the loss of the customer
included above for 2001 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.

Note 12 -- Related Party Transactions

  Reimbursement of Expense 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. 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. Total costs reimbursed by us to our general partner in 2001
were approximately $31.3 million. Total costs reimbursed by us to our former
general partner and Plains Resources were approximately $31.2 million, $63.8
million and $44.7 million for the years ended December 31, 2001, 2000 and 1999,
respectively. Such costs include, (1) allocated personnel costs (such as
salaries and employee benefits) of the personnel providing such services, (2)
rent on office space allocated to our general partner in Plains Resources'
offices in Houston, Texas, (3) property and casualty insurance premiums and (4)
out-of-pocket expenses related to the provision of such services.

                                      F-20

   Crude Oil Marketing Agreement

     We are the exclusive marketer/purchaser for all of Plains Resources' equity
crude oil production. The marketing agreement with Plains Resources provides
that we will purchase for resale at market prices all of Plains Resources' crude
oil production for which we charge a 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, 2001, 2000 and 1999, we paid Plains
Resources approximately $223.2 million, $244.9 million and $131.5 million,
respectively, for the purchase of crude oil under the agreement, including the
royalty share of production, and recognized margins of approximately $1.8
million, $1.7 million and $1.5 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.

   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.

   Financing

     In May 2000, we repaid to our former general partner $114.0 million of
subordinated debt. Interest expense related to the notes was $3.3 million and
$0.6 million for the years ended December 31, 2000 and 1999, respectively.

     To finance a portion of the purchase price of the Scurlock acquisition, we
sold to our former general partner 1.3 million Class B common units at $19.125
per unit, the market value of our common units on May 12, 1999 (see Note 4).

     The balance of amounts due to related parties at December 31, 2001 and 2000
was $13.7 million and $21.0 million, respectively, and was related to crude oil
purchased by us but not yet paid as of December 31 of each year.

   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. Under these grants, the common units vested
based on attaining a targeted operating surplus for a given year. Of the 400,000
units subject to the transaction grant agreements, 69,444 units vested in 2000
for 1999's operating results and 133,336 units vested in 2001 for 2000's
operating results. The remainder (197,220 units) vested in connection with the
consummation of the General Partner Transition. Distribution equivalent rights
were paid in cash at the time of the vesting of the associated common units. The
values of the units and associated distribution equivalent rights that vested
under the Transaction Grant Agreements for all grantees in 2001, 2000 and 1999
were $5.7 million, $3.1 million and $1.0 million, respectively. 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, all except one of the
owners of the general partner contributed an aggregate of 450,000 subordinated
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 332,500 units have been granted to officers
and key employees of our general partner. Such 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
options will vest immediately upon a change in control (as defined in the grant
agreements). The 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. The terms of future grants may differ from the existing grants. Because
the subordinated 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, but will have a noncash
compensation charge offset by a deemed capital contribution.

                                      F-21

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 with a value equal
to the discounted present value of the spread on the unvested options, with
distribution equivalent rights from the date of grant. The subordinated units
vest on the same schedule as the stock options would have vested. The general
partner will administer the vesting and delivery of the units under the grants.
Because the units necessary to satisfy the delivery requirements under the
grants will be provided by Plains Resources, we will 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
Plains AAP, L.P. Effective July 1, 2001, Plains All American GP LLC (Plains
AAP, L.P.'s general partner), now 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 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 (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. For the years ended December 31, 2000 and 1999,
defined contribution plan expense was approximately $1.0 million and $0.7
million, respectively.

Note 13 -- Long-Term Incentive Plans

     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 Long-Term Incentive Plan
consists of two components, a restricted unit plan and a unit option plan. The
Long-Term Incentive Plan currently permits the grant of restricted 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 Long-Term Incentive Plan 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 Long-Term Incentive Plan or
any part of the plan from time to time, including 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 a common unit upon the vesting of the phantom unit. As of
March 5, 2002, aggregate outstanding grants of approximately 679,000 restricted
units have been made to employees of our general partner. Grants made include
165,000 restricted units to executive officers as a group. Additional grants of
approximately 288,000 restricted units have been approved, with vesting in 25%
increments when the quarterly distribution reaches $0.525, $0.575 and $0.625
($2.10, $2.30 and $2.50 annualized), and the criteria for the remaining 25% is
yet to be determined. These grants include approximately 203,000 restricted
units to executive officers of the general partner. The Compensation Committee
of the general partner may, in the future, make additional grants under the plan
to employees and directors containing such terms as the Compensation Committee
shall determine. Restricted units granted to employees during the subordination
period, although additional vesting criteria may sometimes apply, will vest only
after, and in the same proportions as, the conversion of the subordinated units
to common units. Grants made to non-employee directors of our general partner
are eligible to vest prior to termination of the subordination period. In 2000,
the three non-employee directors of our former general partner were each granted
5,000 restricted units. These units vested in connection with the consummation
of the General Partner Transition.

     If a grantee terminates employment or membership on the board for any
reason, the grantee's restricted 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, we may issue up to 975,000 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 restricted units, the total number of common units
outstanding will increase. Whether we satisfy vested units with purchases or by
new issuances, the vesting will result in a compensation charge to us. Following
the subordination period, the Compensation Committee, in its discretion, may
grant tandem distribution equivalent rights with respect to restricted units.

                                      F-22

     The subordination period (as defined in the partnership agreement) will end
if certain financial tests are met for three consecutive four-quarter periods
(the "testing period"), but no sooner than December 31, 2003 (see Note 7).

     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.

     Unit Option Plan. The Unit Option 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. Unit options
granted during the subordination period will become exercisable automatically
upon, and in the same proportions as, the conversion of the subordinated units
to common units, unless a later vesting date is provided.

     Upon exercise of a unit option, our general partner will 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 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.

     Certain employees and officers of the general partner have received grants
of equity not associated with the Long-Term Incentive Plan described above, and
for which we have no cost or reimbursement obligations (see Note 12).

Note 14 -- 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, 2001, are summarized below (in thousands):

                            2002                $ 6,774
                            2003                  6,245
                            2004                  6,340
                            2005                  6,216
                            2006                  4,458
                            Thereafter            5,595

     Total lease expense incurred for 2001, 2000 and 1999 was $7.4 million, $6.7
million and $8.9 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 liquefied petroleum
gas.

     From 1994 to 1997 (prior to our acquisition in 1999), our Venice, Louisiana
terminal experienced several releases of crude oil and jet fuel into the soil.
The Louisiana Department of Environmental Quality has been notified of the
releases. Marathon Ashland has performed some soil remediation related to the
releases and retained liability for these conditions. The extent of the
contamination at the sites is uncertain and there is a potential for groundwater
contamination. We do not expect expenditures related to this terminal to be
material, although we can provide no assurances in that regard.

     During 1997, the All American Pipeline experienced a leak in a segment of
its pipeline in California that resulted in an estimated 12,000 barrels of crude
oil being released into the soil. Immediate action was taken to repair the
pipeline leak, contain the spill and to recover the released crude oil. We have
expended approximately $0.4 million to date in connection with this spill and do
not expect any additional expenditures to be material to the financial
statements, although we can provide no assurances in that regard.

                                      F-23

     Prior to being acquired by our predecessor in 1996, the Ingleside Terminal
experienced releases of refined petroleum products into the soil and groundwater
underlying the site due to activities on the property. We are undertaking a
voluntary state-administered remediation of the contamination on the property to
determine the extent of the contamination. We have proposed extending the scope
of our study and are awaiting the state's response. We have spent approximately
$0.1 million to date in investigating the contamination at this site. We do not
anticipate the total additional cost related to this site to exceed $0.3
million, although no assurance can be given that the actual cost could not
exceed such estimate.

    Litigation

     Texas Securities Litigation. On November 29, 1999, a class action lawsuit
was filed in the United States District Court for the Southern District of Texas
entitled Di Giacomo v. Plains All American Pipeline, L.P., et al. The suit
alleged that Plains All American and certain of our former general partner's
officers and directors violated federal securities laws, primarily in connection
with unauthorized trading by a former employee. An additional nineteen cases
were filed in the Southern District of Texas, some of which named our former
general partner and Plains Resources as additional defendants. All of the
federal securities claims were consolidated into two actions. The first
consolidated action is that filed by purchasers of Plains Resources' common
stock and options, and is captioned Koplovitz v. Plains Resources Inc., et al.
The second consolidated action is that filed by purchasers of our common units,
and is captioned Di Giacomo v. Plains All American Pipeline, L.P., et al.
Plaintiffs alleged that the defendants were liable for securities fraud
violations under Rule l0b-5 and Section 20(a) of the Securities Exchange Act of
1934 and for making false registration statements under Sections 11 and 15 of
the Securities Act of 1933.

     We and Plains Resources reached an agreement with representatives for the
plaintiffs for the settlement of all of the class actions, and in January 2001,
we deposited approximately $30.0 million under the terms of the settlement
agreement. The total cost of the settlement to us and Plains Resources,
including interest and expenses and after insurance reimbursements, was $14.9
million. Of that amount, $1.0 million was allocated to Plains Resources by
agreement between special independent committees of the board of directors of
our former general partner and the board of directors of Plains Resources. All
such amounts were reflected in our financial statements at December 31, 2000.
The settlement was approved by the court on December 19, 2001. The order became
final on January 18, 2002. The settlement agreement does not affect the Texas
Derivative Litigation and Delaware Derivative Litigation described below.

     Delaware Derivative Litigation. On December 3, 1999, two derivative
lawsuits were filed in the Delaware Chancery Court, New Castle County, entitled
Susser v. Plains All American Inc., et al and Senderowitz v. Plains All American
Inc., et al. These suits, and three others which were filed in Delaware
subsequently, named our former general partner, its directors and certain of its
officers as defendants, and allege that the defendants breached the fiduciary
duties that they owed to Plains All American Pipeline, L.P. and its unitholders
by failing to monitor properly the activities of its employees. The court
consolidated all of the cases under the caption In Re Plains All American Inc.
Shareholders Litigation, and has designated the complaint filed in Susser v.
Plains All American Inc. as the complaint in the consolidated action.

     The plaintiffs in the Delaware derivative litigation seek, among other
things, to cause the defendants to account for all losses and damages allegedly
sustained by Plains All American from the unauthorized trading losses; to
establish and maintain effective internal controls ensuring that our affiliates
and persons responsible for our affairs do not engage in wrongful practices
detrimental to Plains All American; and to pay for the plaintiffs' costs and
expenses in the litigation, including reasonable attorneys' fees, accountants'
fees and experts' fees.

     We have agreed with the plaintiffs to settle the Delaware litigation for
approximately $1.1 million. On March 6, 2002, the Delaware court approved the
settlement.

     Texas Derivative Litigation. On July 11, 2000, a derivative lawsuit was
filed in the United States District Court of the Southern District of Texas
entitled Fernandes v. Plains All American Inc., et al, naming our former general
partner, its directors and certain of its officers as defendants. This lawsuit
contains the same claims and seeks the same relief as the Delaware derivative
litigation, described above. We have reached an agreement in principle with the
plaintiffs, subject to approval by the District Court, to settle the Texas
litigation for approximately $112,500.

     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.

                                      F-24

Note 15 -- Quarterly Financial Data (Unaudited) (in thousands, except per unit
data):

                                                   First         Second         Third        Fourth
                                                  Quarter       Quarter        Quarter       Quarter         Total
                                               ------------- -------------  ------------- -------------  --------------
                                                                                          
     2001
     ----
     Revenues                                   $ 1,520,124   $ 1,586,617    $ 2,191,310   $ 1,570,164     $ 6,868,215
     Gross margin                                    32,730        36,387         39,644        33,500         142,261
     Operating income                                19,071        14,843         22,945        14,509          71,368
     Income before extraordinary item and
       cumulative effect of accounting change        12,507         7,067         15,161         8,936          43,671
     Cumulative effect of accounting change             508             -              -             -             508
     Net income                                      13,015         7,067         15,161         8,936          44,179
     Income per limited partner unit before
       extraordinary item and cumulative
       effect of accounting change (1)                 0.36          0.19           0.38          0.20            1.12
       Cumulative effect of accounting change          0.01             -              -             -            0.01
       After extraordinary item (1)                    0.37          0.19           0.38          0.20            1.13
     Cash distributions per common unit (2)     $     0.475   $     0.500    $     0.513   $     0.513     $     2.000

     2000
     ----
     Revenues                                   $ 2,002,507   $ 1,481,834    $ 1,555,863   $ 1,600,983     $ 6,641,187
     Gross margin                                    36.552        32.774         25.960        32.434         127.720
     Operating income                                17,788        20,164         10,700        13,724          62,376
     Income before extraordinary item and
       cumulative effect of accounting change        64,300        17,063          4,516         6,770          92,649
     Extraordinary item                              (4,145)      (11,002)             -             -         (15,147)
     Net income                                      60,155         6,061          4,516         6,770          77,502
     Income per limited partner unit before
       extraordinary item and cumulative
       effect of accounting change                     1.83          0.49           0.13          0.19            2.64
       Extraordinary item                             (0.12)        (0.32)             -             -           (0.44)
       Net income per limited partner unit             1.71          0.17           0.13          0.19            2.20
     Cash distributions per common unit (2)     $     0.450   $     0.463    $     0.463   $     0.463     $     1.839

_______________

     (1)  The sum of the four quarters does not equal the total year due to
          rounding.

     (2)  Represents cash distributions declared per common unit for the period
          indicated. Distributions are paid in the following calendar quarter.

Note 16 -- 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) Marketing, Gathering, Terminalling and
Storage Operations - engages in purchases and resales of crude oil and liquified
petroleum gas at various points along the distribution chain and the leasing of
certain terminalling and storage assets. We evaluate segment performance based
on gross margin, gross profit and income (loss) before extraordinary items and
cumulative effect of accounting change.

     The following table summarizes segment revenues, gross margin, gross profit
and income (loss) before extraordinary items and cumulative effect of accounting
change (in thousands):

                                                                            Marketing,
                                                                            Gathering,
                                                                           Terminalling
                                                          Pipeline           & Storage           Total
- -----------------------------------------------------------------------------------------------------------
                                                                                    
 Twelve Months Ended December 31, 2001
 Revenues:
  External Customers                                       $ 339,852        $  6,528,363      $  6,868,215
  Intersegment (a)                                            17,528               2,046            19,574
  Other revenue                                                   53                 348               401
                                                        -------------    ----------------    --------------
      Total revenues of reportable segments                $ 357,433        $  6,530,757      $  6,888,190
                                                        =============    ================    ==============
 Gain on sale of assets                                    $     984        $          -      $        984
 Segment gross margin (b)                                     71,322              70,939           142,261
 Segment gross profit (c)                                     65,110              36,306           101,416
 Income allocated to reportable segments (d)                  39,494               9,918            49,412
 Noncash compensation expense                                    n/a                 n/a             5,741
                                                        -------------    ----------------    --------------
 Income before extraordinary item and
   cumulative effect of accounting change                  $     n/a        $        n/a      $     43,671
                                                        =============    ================    ==============
 Interest expense                                             10,667              18,415            29,082
 Depreciation and amortization                                15,983               8,324            24,307
 Capital expenditures                                         11,035              30,204            41,239
 Total assets                                                472,324             788,927         1,261,251
- ----------------------------------------------------------------------------- -----------------------------
                                                                         Table continued on following page

                                      F-25

                                                                            Marketing,
                                                                            Gathering,
                                                                           Terminalling
                                                          Pipeline           & Storage           Total
- -----------------------------------------------------------------------------------------------------------
                                                                                    
 Twelve Months Ended December 31, 2000
 Revenues:
   External Customers                                      $ 505,712        $  6,135,475      $  6,641,187
   Intersegment (a)                                           68,745                   -            68,745
   Other revenue                                               9,045               1,731            10,776
                                                        -------------    ----------------    --------------
      Total revenues of reportable segments                $ 583,502        $  6,137,206      $  6,720,708
                                                        =============    ================    ==============
 Gain on sale of assets                                    $  48,188        $          -      $     48,188
 Segment gross margin (b)                                     51,787              75,933           127,720
 Segment gross profit (c)                                     49,996              39,992            89,988
 Income allocated to reportable segments (d)                  94,461               1,277            95,738
 Noncash compensation expense                                    n/a                 n/a             3,089
                                                        -------------    ----------------    --------------
 Income before extraordinary item and
   cumulative effect of accounting change                  $     n/a        $        n/a      $     92,649
                                                        =============    ================    ==============
 Interest expense                                              5,738              22,953            28,691
 Depreciation and amortization                                 7,030              17,493            24,523
 Capital expenditures                                          1,544              11,059            12,603
 Total assets                                                324,751             561,050           885,801
- ----------------------------------------------------------------------------- -----------------------------
 Twelve Months Ended December 31, 1999
 Revenues:
   External Customers                                      $ 854,377        $ 10,056,046      $ 10,910,423
   Intersegment (a)                                          131,445                   -           131,445
   Other revenue                                                 195                 763               958
                                                        -------------    ----------------    --------------
      Total revenues of reportable segments                $ 986,017        $ 10,056,809      $ 11,042,826
                                                        =============    ================    ==============
 Segment gross margin (b)                                  $  58,001        $   (114,127)     $    (56,126)
 Segment gross profit (c)                                     55,384            (133,708)          (78,324)
 Income (loss) allocated to reportable segments (d)           46,075            (146,877)         (100,802)
 Noncash compensation expense                                    n/a                 n/a             1,013
                                                        -------------    ----------------    --------------
 Income (loss) before extraordinary item and
   cumulative effect of accounting change                  $     n/a        $        n/a      $   (101,815)
                                                        =============    ================    ==============
 Interest expense                                             13,572               7,567            21,139
 Depreciation and amortization                                10,979               6,365            17,344
 Capital expenditures                                         69,375             119,911           189,286
 Total assets                                                524,438             698,599         1,223,037
- -----------------------------------------------------------------------------------------------------------

     (a)  Intersegment sales were conducted on an arm's length basis.

     (b)  Gross margin is calculated as revenues less cost of sales and
          operations expense. The 2001 gross margin includes the impact of the
          $5.0 million inventory valuation adjustment.

     (c)  Gross profit is calculated as revenues less costs of sales and
          operations expenses and general and administrative expenses, excluding
          noncash compensation expense.

     (d)  Excludes noncash compensation expense, as it is not allocated to the
          reportable segments.

                                             F-26

     Prior to 2001, all of our revenues were derived from, and our assets
located in, the United States. During 2001, we expanded into Canada (see Note
4). Set forth below is a table of 2001 revenues and long lived assets
attributable to these geographic areas (in thousands):

          Revenues
            United States       $ 6,149,788
            Canada              $   718,427

          Long Lived Assets
            United States       $   567,551
            Canada              $   188,207

Note 17 -- Subsequent Events

   Acquisitions

     In March 2002, we completed the acquisition of substantially all of the
domestic crude oil pipeline, gathering, and marketing assets of Coast Energy
Group and Lantern Petroleum, divisions of Cornerstone Propane Partners, L.P. for
approximately $8.2 million in cash plus transaction costs. The principal assets
acquired, which are located in West Texas, include several gathering lines,
crude oil contracts and a small truck and trailer fleet.

     In February 2002, we acquired an approximate 22% equity interest in Butte
Pipe Line Company from Murphy Ventures, a subsidiary of Murphy Oil Corporation.
The total cost of the acquisition, including various transaction and related
expenses, was approximately $8.0 million. Butte Pipe Line Company owns the 373-
mile Butte Pipeline System that runs from Baker, Montana, to Guernsey, Wyoming.
The Butte Pipeline System, principally a mainline system, transported
approximately 60,000 barrels per day of crude oil at the time of acquisition.
The remaining 78% interest in the Butte Pipe Line Company is owned by Equilon
Pipeline Company LLC.

                                      F-27