<PAGE>

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

                                    FORM 10-Q


           /X/ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
                         SECURITIES EXCHANGE ACT OF 1934

                  FOR THE QUARTERLY PERIOD ENDED JUNE 30, 1999


          / / TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
                         SECURITIES EXCHANGE ACT OF 1934

                        For the transition period from _____to

                         Commission file number: 0-9808

                              PLAINS RESOURCES INC.
             (Exact name of registrant as specified in its charter)

           DELAWARE                                      13-2898764
(State or other jurisdiction of                       (I.R.S. Employer
incorporation or organization)                       Identification No.)


                                500 DALLAS STREET
                              HOUSTON, TEXAS 77002
                    (Address of principal executive offices)
                                   (Zip Code)

                                 (713) 654-1414
              (Registrant's telephone number, including area code)

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

16,964,128 shares of common stock $0.10 par value, issued and outstanding at
July 30, 1999.

<PAGE>

                     PLAINS RESOURCES INC. AND SUBSIDIARIES
                                TABLE OF CONTENTS
--------------------------------------------------------------------------------

                                                                          PAGE
PART I.  FINANCIAL INFORMATION

<TABLE>
<CAPTION>

CONSOLIDATED FINANCIAL STATEMENTS:
<S>                                                                        <C>
      Consolidated Balance Sheets:
         June 30, 1999 and December 31, 1998.............................   3
      Consolidated Statements of Income:
         For the three and six months ended June 30, 1999 and 1998.......   4
      Consolidated Statements of Cash Flows:
         For the six months ended June 30, 1999 and 1998.................   5
      Notes to Consolidated Financial Statements.........................   6

MANAGEMENT'S DISCUSSION AND ANALYSIS.....................................  11

PART II.  OTHER INFORMATION  ............................................  24

</TABLE>


                                   Page 2 of 25
<PAGE>

                                      PLAINS RESOURCES INC. AND SUBSIDIARIES
                                           CONSOLIDATED BALANCE SHEETS
                                        (IN THOUSANDS, EXCEPT SHARE DATA)

<TABLE>
<CAPTION>

                                                                                      JUNE 30,         DECEMBER 31,
                                                                                        1999              1998
                                                                                    ------------      ------------
                                                                                    (unaudited)
<S>                                                                                 <C>               <C>
                                                    ASSETS

CURRENT ASSETS
Cash and cash equivalents                                                           $     13,058      $      6,544
Accounts receivable                                                                      346,493           128,875
Inventory                                                                                 60,510            42,520
Prepaid expenses and other                                                                 4,984             1,527
                                                                                    ------------      ------------

Total current assets                                                                     425,045           179,466
                                                                                    ------------      ------------

PROPERTY AND EQUIPMENT
Oil and natural gas properties - full cost method
  Subject to amortization                                                                627,746           596,203
  Not subject to amortization                                                             59,374            54,545
Crude oil pipeline, gathering and terminal assets                                        513,226           378,254
Other property and equipment                                                              10,462             8,606
                                                                                    ------------      ------------
                                                                                       1,210,808         1,037,608

Less allowance for depreciation, depletion and amortization                             (389,833)         (375,882)
                                                                                    ------------      ------------
                                                                                         820,975           661,726
                                                                                    ------------      ------------
OTHER ASSETS                                                                             153,505           133,075
                                                                                    ------------      ------------
                                                                                    $  1,399,525      $    974,267
                                                                                    ------------      ------------
                                                                                    ------------      ------------

                                     LIABILITIES AND STOCKHOLDERS' EQUITY

CURRENT LIABILITIES
Accounts payable and other current liabilities                                      $    397,530      $    170,985
Interest payable                                                                           7,800             7,950
Royalties payable                                                                          2,851             4,211
Notes payable and other current obligations                                               23,161            10,261
                                                                                    ------------      ------------

Total current liabilities                                                                431,342           193,407

BANK DEBT                                                                                117,300            52,000
BANK DEBT OF A SUBSIDIARY                                                                289,350           175,000
SUBORDINATED DEBT                                                                        202,302           202,427
OTHER LONG-TERM DEBT                                                                       2,556             2,556
OTHER LONG-TERM LIABILITIES                                                                7,289            13,967
                                                                                    ------------      ------------
                                                                                       1,050,139           639,357
                                                                                    ------------      ------------
MINORITY INTEREST                                                                        180,340           173,461
                                                                                    ------------      ------------
SERIES E CUMULATIVE CONVERTIBLE PREFERRED STOCK,
   STATED AT LIQUIDATION PREFERENCE                                                       92,655            88,487
                                                                                    ------------      ------------
NON-REDEEMABLE PREFERRED STOCK, COMMON STOCK
   AND OTHER STOCKHOLDERS' EQUITY
Series D Cumulative Convertible Preferred Stock, $1.00 par value, 46,600 shares
  authorized, issued and outstanding, net of discount of $687,000 and
  $1,354,000, respectively                                                                22,613            21,946
Common Stock, $.10 par value, 50,000,000 shares authorized;
  issued and outstanding 16,927,474 and 16,881,938 shares, respectively                    1,693             1,688
Additional paid-in capital                                                               125,139           124,679
Accumulated deficit                                                                      (73,054)          (75,351)
                                                                                    ------------      ------------
                                                                                          76,391            72,962
                                                                                    ------------      ------------
                                                                                    $  1,399,525      $    974,267
                                                                                    ------------      ------------
                                                                                    ------------      ------------
</TABLE>

                    See notes to consolidated financial statements


                                  Page 3 of 25
<PAGE>

                                     PLAINS RESOURCES INC. AND SUBSIDIARIES
                                       CONSOLIDATED STATEMENTS OF INCOME
                              (UNAUDITED) (IN THOUSANDS, EXCEPT PER SHARE DATA)

<TABLE>
<CAPTION>

                                                                    THREE MONTHS ENDED             SIX MONTHS ENDED
                                                                         JUNE 30,                      JUNE 30,
                                                                 -------------------------     -------------------------
                                                                    1999           1998           1999           1998
                                                                 ----------     ----------     ----------     ----------
<S>                                                              <C>            <C>            <C>            <C>
REVENUES
Oil and natural gas sales                                        $   25,189     $   25,547     $   46,331     $   51,711
Marketing, transportation, storage and terminalling revenues        861,850        163,479      1,317,610        330,683
Interest and other income                                               238            415            307            619
                                                                 ----------     ----------     ----------     ----------

                                                                    887,277        189,441      1,364,248        383,013
                                                                 ----------     ----------     ----------     ----------

EXPENSES
Production expenses                                                  12,100         12,835         23,663         25,673
Marketing, transportation, storage and terminalling expenses        835,984        158,283      1,272,380        321,483
General and administrative                                            7,655          2,437         11,717          4,813
Depreciation, depletion and amortization                              8,275          6,838         15,445         13,593
Interest expense                                                     10,764          6,757         19,517         12,866
                                                                 ----------     ----------     ----------     ----------

                                                                    874,778        187,150      1,342,722        378,428
                                                                 ----------     ----------     ----------     ----------

Income before income taxes and minority interest                     12,499          2,291         21,526          4,585
Minority interest                                                     5,016             --          9,836             --
                                                                 ----------     ----------     ----------     ----------

Income before income taxes                                            7,483          2,291         11,690          4,585
Income tax expense:
   Current                                                               --             19             --             22
   Deferred                                                           2,918            854          4,559          1,714
                                                                 ----------     ----------     ----------     ----------

NET INCOME                                                            4,565          1,418          7,131          2,849
Less:  cumulative preferred stock dividends                           2,473            316          4,834            628
                                                                 ----------     ----------     ----------     ----------

NET INCOME AVAILABLE TO
  COMMON STOCKHOLDERS                                            $    2,092     $    1,102     $    2,297     $    2,221
                                                                 ----------     ----------     ----------     ----------
                                                                 ----------     ----------     ----------     ----------
EARNINGS PER COMMON SHARE:

   Basic                                                         $     0.12     $     0.07     $     0.14     $     0.13
                                                                 ----------     ----------     ----------     ----------
                                                                 ----------     ----------     ----------     ----------
   Diluted                                                       $     0.11     $     0.06     $     0.13     $     0.12
                                                                 ----------     ----------     ----------     ----------
                                                                 ----------     ----------     ----------     ----------
</TABLE>



                   See notes to consolidated financial statements


                                  Page 4 of 25
<PAGE>

                            PLAINS RESOURCES INC. AND SUBSIDIARIES
                            CONSOLIDATED STATEMENTS OF CASH FLOWS
                                  (unaudited) (in thousands)

<TABLE>
<CAPTION>
                                                                      SIX MONTHS ENDED
                                                                          JUNE 30,
                                                                  ------------------------
                                                                     1999           1998
                                                                  ---------      ---------
<S>                                                               <C>            <C>
CASH FLOWS FROM OPERATING ACTIVITIES

Net income                                                        $   7,131      $   2,849
Items not affecting cash flows from operating activities:
   Depreciation, depletion and amortization                          15,445         13,593
   Minority interest in income of a subsidiary                        9,836             --
   Deferred income taxes                                              4,559          1,714
   Other non-cash items                                                 971            131
Change in assets and liabilities from operating activities:
   Accounts receivable                                              (69,163)         9,524
   Inventory                                                         (1,170)        (9,330)
   Prepaid expenses and other                                        (3,457)           197
   Purchase of pipeline linefill                                         (4)            --
   Accounts payable and other current liabilities                    63,178         (7,016)
   Interest payable                                                    (150)           499
   Royalties payable                                                 (1,360)          (354)
                                                                  ---------      ---------

Net cash provided by operating activities                            25,816         11,807
                                                                  ---------      ---------

CASH FLOWS FROM INVESTING ACTIVITIES

Cost incurred in connection with acquisitions (see Note 3)         (141,971)            --
Payment for crude oil pipeline, gathering and terminal assets        (4,678)            --
Payment for acquisition, exploration and developments costs         (50,980)       (39,405)
Payment for additions to other property and assets                   (1,321)          (951)
                                                                  ---------      ---------

Net cash used in investing activities                              (198,950)       (40,356)
                                                                  ---------      ---------

CASH FLOWS FROM FINANCING ACTIVITIES

Proceeds from long-term debt                                        308,021        119,560
Proceeds from short-term debt                                        24,150         17,900
Principal payments of long-term debt                               (127,721)       (63,560)
Principal payments of short-term debt                               (11,900)       (18,000)
Distribution to public Unitholders                                   (8,413)            --
Other                                                                (4,489)           519
                                                                  ---------      ---------

Net cash provided by financing activities                           179,648         56,419
                                                                  ---------      ---------

Net increase in cash and cash equivalents                             6,514         27,870
Cash and cash equivalents, beginning of period                        6,544          3,714
                                                                  ---------      ---------

Cash and cash equivalents, end of period                          $  13,058      $  31,584
                                                                  ---------      ---------
                                                                  ---------      ---------
</TABLE>

                        See notes to consolidated financial statements

                                  Page 5 of 25
<PAGE>


                     PLAINS RESOURCES INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                                   (UNAUDITED)

NOTE 1 -- ORGANIZATION AND ACCOUNTING POLICIES

       The consolidated financial statements include the accounts of Plains
Resources Inc. (the "Company"), its wholly-owned subsidiaries and Plains All
American Pipeline, L.P. ("PAA") in which the Company has an approximate 59%
ownership interest. The operations of PAA are conducted through Plains
Marketing, L.P., All American Pipeline, L.P. and Plains Scurlock Permian,
L.P. ("Plains Scurlock"). Plains All American Inc. ("PAAI"), a wholly owned
subsidiary of the Company, is the general partner ("General Partner") of PAA.

       The accompanying consolidated financial statements at June 30, 1999
and for the three and six months ended June 30, 1999 are unaudited and have
been prepared in accordance with the instructions to interim financial
reporting as prescribed by the Securities and Exchange Commission ("SEC").
For further information, refer to the consolidated financial statements and
notes thereto included in the Company's Annual Report on Form 10-K for the
year ended December 31, 1998, filed with the SEC.

       All material adjustments, consisting only of normal recurring
adjustments, which in the opinion of management were necessary for a fair
statement of the results for the interim periods have been reflected. The
results for the three and six months ended June 30, 1999 are not necessarily
indicative of the final results to be expected for the full year. Certain
reclassifications have been made to the prior year statements to conform to
the current year presentation. The Company evaluates the capitalized costs of
its oil and natural gas properties on an ongoing basis and has utilized the
most recently available information to estimate its reserves at June 30,
1999, in order to determine the realizability of such capitalized costs.
Future events, including drilling activities, product prices and operating
costs, may affect future estimates of such reserves.

RECENT ACCOUNTING PRONOUNCEMENT

       In June 1998, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards No. 133, Accounting for
Derivative Instruments and Hedging Activities ("FAS 133"). FAS 133 is
effective for all fiscal years beginning after June 15, 2000. FAS 133
requires that all derivative instruments be recorded on the balance sheet at
their fair value. Changes in the fair value of derivatives are recorded each
period in current earnings or other comprehensive income, depending on
whether a derivative is designated as part of a hedge transaction and, if it
is, the type of hedge transaction. For fair-value hedge transactions in which
the Company is hedging changes in an asset's, liability's, or firm
commitment's fair value, changes in the fair value of the derivative
instrument will generally be offset in the income statement by changes in the
hedged item's fair value. For cash-flow hedge transactions, in which the
Company is 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. 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 Company is required to adopt this statement beginning in 2001. The
Company has not yet determined the impact that the adoption of FAS 133 will
have on its earnings or financial position.

NOTE 2 -- INVENTORY AND OTHER ASSETS

Inventory consists of the following:

<TABLE>
<CAPTION>
                                        JUNE 30,     DECEMBER 31,
                                          1999          1998
                                      ------------   ------------
                                             (IN THOUSANDS)
<S>                                   <C>            <C>
          Crude oil                   $     55,698   $     37,702
          Materials and supplies             4,812          4,818
                                      ------------   ------------
                                      $     60,510   $     42,520
                                      ------------   ------------
                                      ------------   ------------



                                  Page 6 of 25
<PAGE>

Other assets consist of the following:

<CAPTION>
                                                       JUNE 30,     DECEMBER 31,
                                                         1999           1998
                                                     ------------   ------------
                                                           (IN THOUSANDS)
<S>                                                  <C>             <C>
                Pipeline linefill                      $   70,572     $   54,511
                Deferred tax asset                         44,118         47,785
                Land                                        8,853          8,853
                Debt issue costs                           22,997         18,668
                Other                                      13,968          8,245
                                                     ------------   ------------
                                                          160,508        138,062
                Accumulated amortization                   (7,003)        (4,987)
                                                     ------------   ------------
                                                       $  153,505     $  133,075
                                                     ------------   ------------
                                                     ------------   ------------
</TABLE>

NOTE 3 -- ACQUISITIONS

SCURLOCK ACQUISITION

       On May 12, 1999, Plains Scurlock, a limited partnership of which PAAI
is the general partner and Plains Marketing, L.P. is the limited partner,
completed the acquisition of Scurlock Permian LLC ("Scurlock") and certain
other pipeline assets (the "Scurlock Acquisition") from Marathon Ashland
Petroleum LLC ("MAP"). Including working capital adjustments and associated
closing and financing costs, the cash purchase price was approximately $141
million.

       Scurlock, previously a wholly owned subsidiary of MAP, is engaged in
crude oil transportation, trading and marketing, operating in 14 states with
more than 2,400 miles of active pipelines, numerous storage terminals and a
fleet of more than 225 trucks. Its largest asset is an 800-mile pipeline and
gathering system located in the Spraberry Trend in West Texas that extends
into Andrews, Glasscock, Martin, Midland, Regan and Upton Counties, Texas.
The assets acquired also include approximately 2.4 million barrels of crude
oil.

       Financing for the Scurlock Acquisition was provided through (i) a
borrowing of approximately $92 million under Plains Scurlock's limited
recourse bank facility with BankBoston, N.A. (the "Plains Scurlock Credit
Facility"), (ii) the sale to the General Partner of 1.3 million Class B
Common Units ("Class B Units") of PAA at $19.125 per unit, the price equal to
the market value of PAA's common units ("Common Units") on May 12, 1999, for
a total cash consideration of $25 million and (iii) a $25 million draw under
PAA's existing revolving credit agreement. The funds for the purchase of the
Class B Units by the General Partner were provided through a capital
contribution by the Company, which was financed by the Company's revolving
credit facility (the "Revolving Credit Facility").

       The Plains Scurlock Credit Facility consists of (i) a five-year $126.6
million term loan and (ii) a three-year $35 million revolving credit
facility. The Plains Scurlock Credit Facility is nonrecourse to PAA, Plains
Marketing, L.P. and All American Pipeline, L.P. and is secured by the assets
acquired. Borrowings under the term loan bear interest at the London
Interbank Offering Rate ("LIBOR") plus 3% and under the revolving credit
facility at LIBOR plus 2.75%. A commitment fee equal to one-half of one
percent per year is charged on the unused portion of the revolving credit
facility. The revolving credit facility, which may be used for borrowings or
letters of credit to support crude oil purchases, matures in May 2002. The
term loan provides for principal amortization of $0.7 million annually
beginning May 2000, with a final maturity of May 2004. As of June 30, 1999,
letters of credit of approximately $15.2 million were outstanding under the
revolver and borrowings of $90 million were outstanding under the term loan.

       The Class B Units are initially pari passu with Common Units with
respect to distributions, and after six months are convertible into Common
Units upon approval of a majority of Common Unitholders. After such six month
period, the Class B Unitholder may request that PAA call a meeting of Common
Unitholders to consider approval of the conversion of Class B Units into
Common Units. If the approval of such conversion by the Common Unitholders is
not obtained within 120 days of such request (the "Initial Approval Period"),
the Class B Unitholders 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 Initial Approval Period. Except
for the vote to approve the conversion, Class B Units have the same voting
rights as the Common Units.


                                  Page 7 of 25
<PAGE>

       The assets, liabilities and results of operations of Scurlock are
included in the Consolidated Financial Statements of the Company 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 Accounting Principles Board Opinion No. 16, Business
Combinations ("APB 16") as follows:

<TABLE>
<CAPTION>
                                                                 (in thousands)
        <S>                                                      <C>
        Crude oil pipeline, gathering and terminal assets          $124,615
        Other property and equipment                                  1,546
        Pipeline linefill                                            16,057
        Other assets (debt issue costs)                               3,100
        Environmental accrual                                        (1,000)
        Net working capital items                                    (3,090)
                                                                  ----------

        Cash paid                                                  $141,228
                                                                  ----------
                                                                  ----------
</TABLE>

       The purchase price allocation was based on preliminary estimates of
fair value and is subject to adjustment as additional information becomes
available and is evaluated. The purchase accounting entries include a $1.0
million accrual for estimated environmental remediation costs. Under the
agreement for the sale of Scurlock by MAP to Plains Scurlock, MAP has agreed
to indemnify and hold harmless Scurlock and Plains Scurlock for claims,
liabilities and losses (collectively "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 Scurlock
against MAP on or before May 15, 2003.

CHEVRON ASSET ACQUISITION

       On July 15, 1999, Plains Scurlock completed the acquisition of a West
Texas crude oil pipeline and gathering system from Chevron Pipe Line Company
for approximately $36.6 million including transaction costs (the "Chevron
Asset Acquisition"). The principal assets acquired include approximately 450
miles of crude oil transmission mainlines, approximately 340 miles of
associated gathering and lateral lines and approximately three million
barrels of crude oil storage and terminalling capacity in Crane, Ector,
Midland, Upton, Ward and Winkler Counties, Texas. Financing for the Chevron
Asset Acquisition was provided by a draw of $36.6 million under the term loan
portion of the Plains Scurlock Credit Facility.

       Chevron U.S.A Inc. ("Chevron"), which currently transports
approximately 24,000 barrels of crude oil per day on the system, will
continue to transport its equity crude oil production from the region on the
system under a twelve-year contractual arrangement.

PRO FORMA RESULTS FOR THE SCURLOCK ACQUISITION AND ALL AMERICAN ACQUISITION

       The following unaudited pro forma data is presented to show pro forma
revenues, net income and basic and diluted net income per share as if the
Scurlock Acquisition and the acquisition of the All American Pipeline and
Celeron Gathering system ("All American Acquisition") had both occurred on
January 1, 1998.

<TABLE>
<CAPTION>
                                         SIX MONTHS ENDED
                                             JUNE 30,
                                   -------------------------------
                                       1999             1998
                                   --------------  ---------------
                                           (IN THOUSANDS)

       <S>                         <C>             <C>
       Revenues                      $ 2,409,209      $ 2,487,524
                                   --------------  ---------------
                                   --------------  ---------------
       Net income                        $ 9,631          $ 4,641
                                   --------------  ---------------
                                   --------------  ---------------
       Net income per share:
         Basic                            $ 0.28        $    0.00
                                   --------------  ---------------
                                   --------------  ---------------
         Diluted                          $ 0.26        $    0.00
                                   --------------  ---------------
                                   --------------  ---------------
       </TABLE>


                                  Page 8 of 25
<PAGE>

POINT ARGUELLO ACQUISITION

       On July 1, 1999, Arguello Inc., a wholly owned subsidiary of the
Company, acquired Chevron's interests in the Point Arguello Field. The
interests acquired include Chevron's 26% working interest in the Point
Arguello Field and associated onshore processing facilities, Chevron's right
to participate in surrounding leases and certain fee acreage onshore. The
acquisition, which was funded from the Company's working capital, has an
effective date of July 1, 1999. Chevron retained the obligation of (i)
removing, dismantling, and disposing of all existing offshore platforms, (ii)
removing and disposing of all existing pipelines and (iii) removing,
dismantling, disposing and remediation of all existing onshore facilities.
The Company assumed its 26% share of (i) plugging and abandoning all existing
well bores, (ii) removing conductors, (iii) flushing all lines and vessels,
and (iv) removing/abandoning all structures, fixtures and conditions created
subsequent to closing.

       Arguello Inc. will be the operator of record for the Point Arguello
field and has entered into an outsourcing agreement with a unit of Torch
Energy Advisors, Inc. for the conduct of daily operations and field
management.

NOTE 4 -- EARNINGS PER SHARE

       The following is a reconciliation of the numerators and the
denominators of the basic and diluted earnings per share ("EPS") computations
for income from continuing operations for the three and six months ended June
30, 1999 and 1998, as required by Statement of Financial Accounting Standards
No. 128, Earnings Per Share.

<TABLE>
<CAPTION>
                                                     FOR THE THREE MONTHS ENDED JUNE 30,
                                     --------------------------------------------------------------------
                                                    1999                              1998
                                     --------------------------------- ----------------------------------
                                       INCOME      SHARES      PER       INCOME       SHARES      PER
                                      (NUMERA-    (DENOMI-    SHARE     (NUMERA-     (DENOMI-    SHARE
                                        TOR)       NATOR)     AMOUNT      TOR)        NATOR)     AMOUNT
                                     -----------  ---------- --------- ------------ ----------- ---------
                                                    (IN THOUSANDS, EXCEPT PER SHARE DATA)

<S>                                  <C>          <C>        <C>       <C>          <C>         <C>
Net income                             $ 4,565                           $ 1,418
Less:  preferred stock dividends        (2,473)                             (316)
                                     -----------                       ------------
Income available to common
  stockholders                           2,092      16,914    $ 0.12      1,102       16,820     $ 0.07
                                                             ---------                          ---------
                                                             ---------                          ---------
Effect of dilutive securities:
Employee stock options                       -       1,137                      -       1,151
Warrants                                     -         545                      -         579
                                     -----------  ----------           ------------ -----------
Income available to common
  stockholders assuming dilution       $ 2,092      18,596    $ 0.11      $ 1,102      18,550    $ 0.06
                                     -----------  ---------- --------- ------------ ----------- ---------
                                     -----------  ---------- --------- ------------ ----------- ---------
</TABLE>

<TABLE>
<CAPTION>
                                                      FOR THE SIX MONTHS ENDED JUNE 30,
                                     --------------------------------------------------------------------
                                        1999                              1998
                                     --------------------------------- ----------------------------------
                                       INCOME      SHARES      PER        INCOME       SHARES      PER
                                      (NUMERA-    (DENOMI-    SHARE      (NUMERA-     (DENOMI-    SHARE
                                        TOR)       NATOR)     AMOUNT       TOR)        NATOR)     AMOUNT
                                     -----------  ---------- --------- ------------ ----------- ---------
                                                   (IN THOUSANDS, EXCEPT PER SHARE DATA)

<S>                                  <C>          <C>        <C>       <C>           <C>         <C>
Net income                               $ 7,131                            $ 2,849
Less:  preferred stock dividends          (4,834)                              (628)
                                     -----------                       ------------
Income available to common
stockholders                               2,297      16,902    $ 0.14        2,221      16,772    $ 0.13
                                                             ---------                          ---------
                                                             ---------                          ---------
Effect of dilutive securities:
Employee stock options                         -         882                      -       1,090
Warrants                                       -         470                      -         549
                                     -----------  ----------           ------------ -----------
Income available to common
   stockholders assuming dilution        $ 2,297      18,254    $ 0.13      $ 2,221      18,411    $ 0.12
                                     -----------  ---------- --------- ------------ ----------- ---------
                                     -----------  ---------- --------- ------------ ----------- ---------
</TABLE>


       Certain options and warrants to purchase shares of the Company's
common stock ("Common Stock") were not included in the computations of
diluted EPS because the exercise prices were greater than the average market
price of the Common Stock during the periods of the EPS calculations,
resulting in antidilution. In addition, the Company's preferred stock is
convertible into Common Stock but was not included in the computation of
diluted EPS because the effect was antidilutive.


                                  Page 9 of 25
<PAGE>
NOTE 5 -- OPERATING SEGMENTS

       The Company's operations consist of three operating segments: (i)
Upstream Operations - engages in the acquisition, exploitation, development,
exploration and production of crude oil and natural gas, (ii) Midstream
Operations - engages in crude oil gathering, marketing, terminalling, storage
and transportation and (iii) Corporate - reflects certain amounts that are
not directly attributable to Upstream or Midstream Operations. The Company
evaluates segment performance based on gross margin, gross profit and income
before income taxes and minority interest.

<TABLE>
<CAPTION>
(IN THOUSANDS)                                    UPSTREAM       MIDSTREAM       CORPORATE         TOTAL
-----------------------------------------------------------------------------------------------------------
<S>                                             <C>             <C>            <C>             <C>
FOR THE THREE MONTHS ENDED JUNE 30, 1999
Revenues:
  External Customers                            $     25,189    $    861,850   $         --    $    887,039
  Intersegment (a)                                        --             347             --             347
  Other income                                            48             190             --             238
                                                ------------    ------------   ------------    ------------
    Total revenues of reportable segments       $     25,237    $    862,387   $         --    $    887,624
                                                ------------    ------------   ------------    ------------
                                                ------------    ------------   ------------    ------------
Segment gross margin (b)                        $     13,089    $     25,866   $         --    $     38,955
Segment gross profit (c)                              11,716          20,097           (513)         31,300
Segment income (loss) before income taxes
  and minority interest                                1,512          11,726           (739)         12,499

-----------------------------------------------------------------------------------------------------------
FOR THE THREE MONTHS ENDED JUNE 30, 1998
Revenues:
  External Customers                            $     25,547    $    163,479   $         --    $    189,026
  Intersegment (a)                                        --             308             --             308
  Other income                                            12             403             --             415
                                                ------------    ------------   ------------    ------------
    Total revenues of reportable segments       $     25,559    $    164,190   $         --    $    189,749
                                                ------------    ------------   ------------    ------------
                                                ------------    ------------   ------------    ------------
Segment gross margin (b)                        $     12,712    $      5,196   $         --    $     17,908
Segment gross profit (c)                              11,330           4,141             --          15,471
Segment income (loss) before income taxes and
  minority interest                                     (602)          2,893             --           2,291

-----------------------------------------------------------------------------------------------------------
FOR THE SIX MONTHS ENDED JUNE 30, 1999
Revenues:
  External Customers                            $     46,331    $  1,317,610   $         --    $  1,363,941
  Intersegment (a)                                        --             674             --             674
  Other income                                            20             287             --             307
                                                ------------    ------------   ------------    ------------
    Total revenues of reportable segments       $     46,351    $  1,318,571   $         --    $  1,364,922
                                                ------------    ------------   ------------    ------------
                                                ------------    ------------   ------------    ------------
Segment gross margin (b)                        $     22,668    $     45,230   $         --    $     67,898
Segment gross profit (c)                              19,685          37,009           (513)         56,181
Segment income (loss) before income taxes
  and minority interest                                 (447)         22,712           (739)         21,526

-----------------------------------------------------------------------------------------------------------
FOR THE SIX MONTHS ENDED JUNE 30, 1998
Revenues:
  External Customers                            $     51,711    $    330,683   $         --    $    382,394
  Intersegment (a)                                        --             565             --             565
  Other income                                            39             580             --             619
                                                ------------    ------------   ------------    ------------
    Total revenues of reportable segments       $     51,750    $    331,828   $         --    $    383,578
                                                ------------    ------------   ------------    ------------
                                                ------------    ------------   ------------    ------------
Segment gross margin (b)                        $     26,038    $      9,200   $         --    $     35,238
Segment gross profit (c)                              23,266           7,159             --          30,425
Segment income (loss) before income taxes and
  minority interest                                     (301)          4,886             --           4,585
-----------------------------------------------------------------------------------------------------------
</TABLE>

       (a)    Intersegment revenues and transfers were conducted on an
              arm's-length basis.
       (b)    Gross margin is calculated as operating revenues less operating
              expenses.
       (c)    Gross profit is calculated as operating revenues less operating
              and general and administrative expenses.


                                  Page 10 of 25
<PAGE>

                      MANAGEMENT'S DISCUSSION AND ANALYSIS

GENERAL

       On May 12, 1999, Plains Scurlock Permian, L.P. ("Plains Scurlock"), a
limited partnership of Plains All American Pipeline, L.P., ("PAA"), through
which the Company's midstream activities are conducted, completed the
acquisition of Scurlock Permian LLC ("Scurlock") and certain other pipeline
assets from Marathon Ashland Petroleum LLC (the "Scurlock Acquisition").
Including working capital adjustments and associated closing and financing
costs, the cash purchase price was approximately $141 million. The assets,
liabilities and results of operations of the Scurlock Acquisition are
included in the Company's Consolidated Financial Statements effective May 1,
1999.

       Scurlock, previously a wholly owned subsidiary of Marathon Ashland
Petroleum LLC ("MAP"), is engaged in crude oil transportation, trading and
marketing, operating in 14 states with more than 2,400 miles of active
pipelines, numerous storage terminals and a fleet of more than 225 trucks.
Its largest asset is an 800-mile pipeline and gathering system located in the
Spraberry Trend in West Texas that extends into Andrews, Glasscock, Martin,
Midland, Regan and Upton Counties, Texas. The assets acquired also include
approximately 2.4 million barrels of crude oil.

       On November 23, 1998, PAA completed its initial public offering of
13.1 million common units representing limited partner interests. PAA's
results are consolidated into the Company's results with the public's
ownership reflected as a minority interest deduction from income. The
operations of PAA are conducted through Plains Marketing, L.P., All American
Pipeline, L.P. and Plains Scurlock. Plains All American Inc. ("PAAI"), a
wholly owned subsidiary of the Company is the general partner ("General
Partner") of PAA. PAA was formed to acquire the midstream crude oil business
and assets of the Company, including the All American Pipeline and the SJV
Gathering System, which the Company purchased from Goodyear in July 1998 (the
"All American Acquisition"). The assets, liabilities and results of
operations of the All American Acquisition are included in the Company's
Consolidated Financial Statements effective July 30, 1998. See Note 3 to the
accompanying Consolidated Financial Statements for pro forma information
giving effect to the Scurlock Acquisition and the All American Acquisition as
if such transactions had occurred on January 1, 1998.

RESULTS OF OPERATIONS

THREE MONTHS ENDED JUNE 30, 1999 AND 1998

       The Company reported net income for the second quarter of 1999 of $4.6
million, or $0.12 per common share ($0.11 assuming dilution) as compared with
net income of $1.4 million, or $0.07 per common share ($0.06 assuming
dilution) in the 1998 second quarter. Cash flow from operations (net income
before non-cash expenses) increased approximately 78% to $16.3 million in the
1999 period as compared to $9.2 million in the second quarter of 1998.
Earnings before interest, taxes, depreciation, amortization and minority
interest ("EBITDA") increased 99% to $31.5 million versus $15.9 million in
the second quarter of 1998.


                                  Page 11 of 25
<PAGE>

UPSTREAM RESULTS

The following table sets forth certain upstream operating information of the
Company for the periods presented:

<TABLE>
<CAPTION>
                                                                     THREE MONTHS ENDED
                                                                          JUNE 30,
                                                                   ---------------------
                                                                     1999        1998
                                                                   ---------   ---------
                                                                      (IN THOUSANDS)
                         <S>                                       <C>         <C>
                         AVERAGE DAILY PRODUCTION VOLUMES
                           Barrels of oil equivalent ("BOE")
                             California (approximately 92% oil)         15.7        13.8
                             Gulf Coast (100% oil)                       2.5         5.3
                             Illinois Basin (100% oil)                   3.0         3.6
                                                                   ---------   ---------
                               Total (approximately 94% oil)            21.2        22.7
                                                                   ---------   ---------
                                                                   ---------   ---------

                         UNIT ECONOMICS
                         Average sales price per BOE                 $ 13.05     $ 12.38
                         Production expense per BOE                     6.27        6.22
                                                                   ---------   ---------
                         Gross margin per BOE                           6.78        6.16
                         Upstream G&A expense per BOE                   0.72        0.67
                                                                   ---------   ---------
                         Gross profit per BOE                         $ 6.06      $ 5.49
                                                                   ---------   ---------
                                                                   ---------   ---------
</TABLE>

       During the 1999 second quarter, production volumes were affected by
shut-ins and production cutbacks related to lower crude oil prices and
curtailments due to refinery disruptions in California as well as declines in
the Company's Gulf Coast production. As a result, total oil equivalent
production decreased approximately 7% to an average of 21,200 BOE per day as
compared to the second quarter 1998 average of 22,700 BOE per day.

       Net daily production in California increased approximately 14% to
15,700 BOE in the second quarter of 1999 compared to 13,800 BOE in the same
quarter of 1998 due to the acquisition of the Mt. Poso Field in December 1998
and ongoing exploitation activities. Excluding production from the Mt. Poso
field, total California production increased approximately 7% from the
comparative prior year quarter. Net daily production for the Company's Gulf
Coast properties averaged approximately 2,500 barrels per day during the
second quarter of 1999, compared to 5,300 barrels per day in the 1998
comparative period. The Gulf Coast production decrease is due to voluntary
shut-ins, mechanical downtime resulting from the deferral of workovers due to
low crude oil prices, the effects of natural decline and drilling delays. The
Company recently completed some of the well work activity that was commenced
in the second quarter, which included returning wells to production and also
drilling a horizontal lateral out of an existing well to increase its
productive capacity. As a result, Gulf Coast production for July was
approximately 3,400 barrels per day, net to the Company's interest. Net daily
production in the Illinois Basin averaged approximately 3,000 barrels per day
during the second quarter of 1999, a decrease of approximately 17% as
compared to the 1998 second quarter average of 3,600 barrels per day. The
Illinois Basin production decrease is primarily attributable to well shut-ins
and natural decline.

       Oil and natural gas revenues were $25.2 million for the second quarter
of 1999, almost flat with the 1998 second quarter amount of $25.5 million as
slightly higher prices offset decreased production. The Company's average
product price, which represents a combination of fixed and floating price
sales arrangements and incorporates location and quality discounts from the
benchmark New York Mercantile Exchange ("NYMEX") price was $13.05 per BOE, up
5% as compared to the 1998 second quarter average wellhead price of $12.38
per BOE. The NYMEX benchmark West Texas Intermediate ("WTI") crude oil price
averaged $17.65 per barrel during the second quarter of 1999, approximately
20% above the $14.69 per barrel amount in the prior year period. The Company
maintained hedges on approximately 65% and 57% of its crude oil production in
the second quarter of 1999 and 1998, respectively, with the hedge price
averaging a NYMEX WTI price of approximately $17.45 per barrel and $19.80 per
barrel in the respective periods. Hedging transactions had the effect of
decreasing the Company's average price per BOE by $0.12 and increasing the
average price by $2.75 in the second quarter of 1999 and 1998, respectively.

       Unit production expenses averaged $6.27 per BOE for the second quarter
of 1999, almost equal to the 1998 second quarter average of $6.22 per BOE.
Unit gross margin in the upstream segment was $6.78 per BOE, a 10% increase
as compared to $6.16 per BOE reported for the second quarter of 1998.
Upstream unit gross profit, which deducts all pre-interest cash costs, was
$6.06 per BOE, 10% above the 1998 amount of $5.49 per BOE. Total production
expenses were $12.1 million, as compared to $12.8 million for the second
quarter of 1998. Unit general and administrative ("G&A")


                                  page 12 of 25
<PAGE>


expenses in the upstream segment were $0.72 per BOE in the second quarter of
1999, compared to $0.67 per BOE in the prior year comparative quarter.

       Total upstream depreciation, depletion and amortization ("DD&A")
expense was $4.4 million in the second quarter of 1999, compared to $6.5
million in the 1998 comparative quarter due primarily to a lower per unit
DD&A rate and decreased production volumes. DD&A per BOE was $2.10 for the
second quarter of 1999 compared to $3.00 per BOE in the 1998 comparative
quarter. Such decrease is primarily due to a $174 million reduction in the
carrying cost of the Company's proved oil and natural gas properties recorded
in the 1998 fourth quarter due to low crude oil prices, and the impact of
subsequent price recovery on proved reserve volumes. The NYMEX WTI price was
$12.05 per barrel at December 31, 1998, compared to $19.29 at June 30, 1999.

MIDSTREAM RESULTS

       The following table sets forth certain midstream operating information
of the Company for the periods presented:

<TABLE>
<CAPTION>
                                                                  THREE MONTHS ENDED
                                                                       JUNE 30,
                                                            -----------------------------
                                                                1999            1998
                                                            -------------    ------------
                                                                    (IN THOUSANDS)

                   <S>                                       <C>             <C>
                   Operating Results:
                     Gross margin
                       Pipeline                                  $ 12,917         $     -
                       Gathering and marketing and
                         terminalling and storage                  12,949           5,196
                                                            -------------    ------------
                         Total                                     25,866           5,196
                     General and administrative expense            (5,783)         (1,055)
                                                            -------------    ------------

                     Gross profit                                $ 20,083         $ 4,141
                                                            -------------    ------------
                                                            -------------    ------------

                   Average Daily Volumes (barrels)
                     Pipeline Activities:
                       All American
                         Tariff activities                            101               -
                         Margin activities                             63               -
                       Other                                           25               -
                                                            -------------    ------------

                       Total                                          189               -
                                                            -------------    ------------
                                                            -------------    ------------

                     Lease gathering                                  294              83
                     Bulk purchases                                   161             109
                     Terminal throughput                               84              83
</TABLE>

       PIPELINE OPERATIONS. The Company's results for the second quarter of
1998 do not include the results of operations of the All American Acquisition
which was effective July 30, 1998. Gross margin from pipeline operations was
$12.9 million for the second quarter of 1999. Approximately $0.8 million of
such margin was from the Scurlock Acquisition, for which two months of
operations are included in the current period's results. Pipeline tariff
revenues and tariff transport volumes from the All American Pipeline were
approximately $9.4 million and 101,000 barrels per day, respectively. Volumes
related to barrels shipped as part of the Company's merchant activities were
63,000 barrels per day in the current year period. Operations and maintenance
expenses were $6.8 million for such period.

       The following table sets forth the All American Pipeline average
deliveries per day within and outside California for the three months ended June
30, 1999.

<TABLE>
              <S>                                               <C>
              DELIVERIES:
                AVERAGE DAILY VOLUMES (THOUSAND BARRELS):
                  Within California                                   101
                  Outside California                                   63
                                                                ---------

                    Total                                             164
                                                                ---------
                                                                ---------
</TABLE>

       GATHERING AND MARKETING ACTIVITIES AND TERMINALLING AND STORAGE
ACTIVITIES. Gross margin from gathering, marketing, terminalling and storage
activities was approximately $12.9 million for the second quarter of 1999.
Approximately $6.2


                                  Page 13 of 25
<PAGE>

million of this gross margin is attributable to the Scurlock Acquisition
which was effective May 1, 1999. The Scurlock gross margin was generated on
gathering volumes of approximately 192,000 barrels per day and bulk purchase
volumes of approximately 71,000 barrels per day. Scurlock daily volumes are a
two month average of activity from the date of acquisition through June 30,
1999.

       Excluding the Scurlock Acquisition, gross margin from the Company's
gathering, marketing, terminalling and storage activities was approximately
$6.7 million for the second quarter of 1999, compared to $5.2 million in the
prior year comparative period. The increase is due to an increase in lease
gathering volumes and storage capacity leased at the Company's crude oil
terminal and storage facility in Cushing, Oklahoma, (the "Cushing Terminal").
Lease gathering volumes increased from an average of 83,000 barrels per day
for the second quarter of 1998 to approximately 102,000 barrels per day in
the current year quarter. Bulk purchase volumes declined from approximately
109,000 barrels per day in last year's quarter to approximately 90,000
barrels per day in the second quarter of 1999. This decrease is primarily due
to a lesser volume of contango purchases and an increased amount of tankage
that was leased to third parties at the Cushing Terminal. The one million
barrel expansion of the Cushing Terminal was placed in service during the
second quarter of 1999. Throughput volumes at the Company's terminals
averaged approximately 84,000 barrels per day in the current year quarter,
about flat with the 1998 comparative period average of 83,000 barrels per
day. Average leased terminal capacity increased significantly from
approximately 600,000 barrels per month in last year's quarter to 2.3 million
barrels per month during the current year quarter.

GENERAL

       Total G&A expenses, including midstream activities, were approximately
$7.7 million for the three months ended June 30, 1999, an increase of $5.2
million as compared to the 1998 comparative period. Approximately $4.7
million of the increase is attributable to the Company's midstream
activities. Approximately $4.2 million of the midstream increase is
associated with the May 1999 Scurlock Acquisition, the July 1998 All American
Acquisition and expenses incurred by PAA as a result of its being a separate
public entity. Interest expense for the quarter ended June 30, 1999 increased
to $10.8 million from $6.8 million for the comparative prior year quarter
primarily due to the debt incurred for the Scurlock Acquisition and the All
American Acquisition. Capitalized interest was $1.2 million and $0.9 million
for the three months ended June 30, 1999 and 1998, respectively.

       The Company's total tax provision for the quarter ended June 30, 1999,
was approximately $2.9 million, as compared to the second quarter 1998 tax
provision of approximately $0.9 million. Such increase is due to the increase
in income before taxes between the two periods. In both periods,
substantially all of the Company's income tax provision was deferred.

SIX MONTHS ENDED JUNE 30, 1999 AND 1998

       The Company reported net income for the first six months of 1999 of
$7.1 million, or $0.14 per common share ($0.13 assuming dilution), as
compared with net income of $2.8 million, or $0.13 per common share ($0.12
assuming dilution) in the first six months of 1998. Cash flow from operations
(net income before non-cash expenses) increased approximately 54% to $28.1
million in the 1999 period as compared to $18.3 million in the first six
months of 1998. EBITDA increased 82% to $56.5 million versus $31.0 million in
the first half of 1998. Net cash provided by operating activities, as
reported in the Consolidated Statements of Cash Flows was $25.8 million for
the six months ended June 30, 1999, as compared to $11.8 million for the 1998
comparative period.


                                  Page 14 of 25
<PAGE>

UPSTREAM RESULTS

The following table sets forth certain upstream operating information of the
Company for the periods presented:

<TABLE>
<CAPTION>
                                                                 SIX MONTHS ENDED
                                                                      JUNE 30,
                                                             ------------------------
                                                                1999          1998
                                                             ----------    ----------
                                                                  (IN THOUSANDS)
               <S>                                           <C>           <C>
               AVERAGE DAILY PRODUCTION VOLUMES
                 Barrels of oil equivalent
                   California (approximately 91% oil)              15.3          13.7
                   Gulf Coast (100% oil)                            2.7           5.1
                   Illinois Basin (100% oil)                        3.1           3.7
                                                             ----------    ----------
                     Total (approximately 94% oil)                 21.1          22.5
                                                             ----------    ----------
                                                             ----------    ----------

               UNIT ECONOMICS
                 Average sales price per BOE                    $ 12.14       $ 12.70
                 Production expense per BOE                        6.20          6.31
                                                             ----------    ----------
                 Gross margin per BOE                              5.94          6.39
                 Upstream G&A expense per BOE                      0.78          0.68
                                                             ----------    ----------
                 Gross profit per BOE                            $ 5.16        $ 5.71
                                                             ----------    ----------
                                                             ----------    ----------
</TABLE>

       During the first six months of 1999, production volumes were affected
by shut-ins and production cutbacks related to lower crude oil prices and
curtailments due to refinery disruptions in California as well as declines in
the Company's Gulf Coast production. As a result, total oil equivalent
production decreased approximately 6% to an average of 21,100 BOE per day as
compared to the 1998 first half average of 22,500 barrels per day.

       Net daily production in California increased approximately 12% to
15,300 BOE in the first half of 1999 compared to 13,700 BOE in the same
period of 1998 due to the acquisition of the Mt. Poso Field in December 1998
and ongoing exploitation activities. Excluding production from the Mt. Poso
field, total California production increased approximately 5% from the
comparative prior year period. Net daily production for the Company's Gulf
Coast properties averaged approximately 2,700 barrels per day during the
first half of 1999, compared to 5,100 barrels per day in the 1998 comparative
period. The Gulf Coast production decrease is due to voluntary shut-ins,
mechanical downtime resulting from the deferral of workovers due to low crude
oil prices, the effects of natural decline and drilling delays. The Company
recently completed some of the well work activity that was commenced in the
second quarter, which included returning wells to production and also
drilling a horizontal lateral out of an existing well to increase its
productive capacity. As a result, Gulf Coast production for July was
approximately 3,400 barrels per day, net to the Company's interest. Net daily
production in the Illinois Basin averaged approximately 3,100 barrels per day
during the first half of 1999, a decrease of approximately 16% as compared to
the 1998 first half average of 3,700 barrels per day. The Illinois Basin
production decrease is primarily attributable to well shut-ins and natural
decline.

       Oil and natural gas revenues were $46.3 million for the first half of
1999, a decrease of approximately 10% from the comparable 1998 period amount
of $51.7 million. The Company's average product price, which represents a
combination of fixed and floating price sales arrangements and incorporates
location and quality discounts from the benchmark NYMEX price was $12.14 per
BOE, a decrease of approximately 4% as compared to the 1998 first half
average wellhead price of $12.70 per BOE. The NYMEX WTI crude oil price
averaged $15.35 per barrel during the first half of 1999, compared to $15.33
per barrel in the prior year period. The Company maintained hedges on
approximately 56% and 58% of its crude oil production in the first half of
1999 and 1998, respectively, with the hedge price averaging a NYMEX WTI price
of approximately $17.80 per barrel and $19.80 per barrel in the respective
periods. Hedging transactions had the effect of increasing the Company's
average price per BOE by $1.03 and $2.43 in the first half of 1999 and 1998,
respectively.

       Unit production expenses averaged $6.20 per BOE, a 2% decrease as
compared to the 1998 first half average of $6.31 per BOE. Unit gross margin
in the upstream segment was $5.94 per BOE, a 7% decrease as compared to $6.39
per BOE reported for the first half of 1998. Upstream unit gross profit,
which deducts all pre-interest cash costs, was $5.16 per BOE, 10% below the
1998 amount of $5.71 per BOE. Total production expenses were $23.7 million,
as compared to $25.7 million for the first half of 1998. Unit G&A expenses in
the upstream segment were $0.78 per BOE in the first half of 1999, compared
to $0.68 per BOE in the prior year comparative period.


                                  Page 15 of 25
<PAGE>

       Total upstream DD&A expense was $8.8 million in the first half of
1999, compared to $13.0 million in the 1998 comparative period due to a lower
per unit DD&A rate and decreased production volumes. DD&A per BOE was $2.10
for the first half of 1999 compared to $3.00 per BOE in the 1998 comparative
period. Such decrease is primarily due to a $174 million reduction in the
carrying cost of the Company's proved oil and natural gas properties recorded
in the 1998 fourth quarter due to low crude oil prices, and the impact of
subsequent price recovery on proved reserve volumes. The NYMEX WTI price was
$12.05 per barrel at December 31, 1998, compared to $19.29 at June 30, 1999.

MIDSTREAM RESULTS

       The following table sets forth certain midstream operating information
of the Company for the periods presented:

<TABLE>
<CAPTION>
                                                               SIX MONTHS ENDED
                                                                   JUNE 30,
                                                        -----------------------------
                                                             1999            1998
                                                        -------------    ------------
                                                                 (IN THOUSANDS)
               <S>                                      <C>              <C>
               OPERATING RESULTS:
                 Gross margin
                   Pipeline                                  $ 24,799         $     -
                   Gathering and marketing and
                     terminalling and storage                  20,431           9,200
                                                        -------------    ------------
                     Total                                     45,230           9,200
                 General and administrative expense            (8,234)         (2,041)
                                                        -------------    ------------
                 Gross profit                                $ 36,996         $ 7,159
                                                        -------------    ------------
                                                        -------------    ------------

               AVERAGE DAILY VOLUMES (BARRELS)
                 Pipeline Activities
                   All American
                     Tariff activities                            113               -
                     Margin activities                             55               -
                   Other                                           25               -
                                                        -------------    ------------
                   Total                                          193               -
                                                        -------------    ------------
                                                        -------------    ------------

                 Lease gathering                                  292              82
                 Bulk purchases                                   163             102
                 Terminal throughput                               79              75
</TABLE>

       PIPELINE OPERATIONS. The Company's results for the first six months of
1998 do not include the results of operations of the All American Acquisition
which was effective July 30, 1998. Gross margin from pipeline operations was
$24.8 million for the first six months of 1999. Approximately $0.8 million of
such margin was from the Scurlock Acquisition, for which two months of
operations are included in the current period's results. Pipeline tariff
revenues and tariff transport volumes from the All American Pipeline were
approximately $22.0 million and 113,000 barrels per day, respectively, for
the first six months of 1999. Volumes related to barrels shipped as part of
the Company's merchant activities were 55,000 barrels per day in the current
year period. Operations and maintenance expenses were $13.0 million for such
period.

       The following table sets forth the All American Pipeline average
deliveries per day within and outside California for the six months ended
June 30, 1999.

<TABLE>
             <S>                                          <C>
              DELIVERIES:
                AVERAGE DAILY VOLUMES (THOUSAND BARRELS):
                  Within California                              106
                  Outside California                              62
                                                           ---------
                    Total                                        168
                                                           ---------
                                                           ---------
              </TABLE>

       GATHERING AND MARKETING ACTIVITIES AND TERMINALLING AND STORAGE
ACTIVITIES. Gross margin from gathering, marketing, terminalling and storage
activities was approximately $20.4 million for the first half of 1999.
Approximately $6.2 million of this gross margin is attributable to the
Scurlock Acquisition which was effective May 1, 1999. The Scurlock gross
margin was generated on gathering volumes of approximately 192,000 barrels
per day and bulk purchase volumes of approximately 71,000 barrels per day.
Scurlock daily volumes are a two month average of activity from the date of
acquisition through June 30, 1999.


                                  Page 16 of 25
<PAGE>

       Excluding the Scurlock Acquisition, gross margin from the Company's
gathering, marketing, terminalling and storage activities was approximately
$14.2 million for the first half 1999, compared to $9.2 million in the prior
year comparative period. The increase is due to an increase in per barrel
lease gathering margins, lease gathering volumes and storage capacity leased
at the Company's crude oil terminal facilities. Lease gathering volumes
increased from an average of 82,000 barrels per day for the first half of
1998 to approximately 100,000 barrels per day in the current year period.
Bulk purchase volumes declined from approximately 102,000 barrels per day in
the first half of 1998 to approximately 92,000 barrels per day in the 1999
comparative period. This decrease is primarily due to a lesser volume of
contango purchases and an increased amount of tankage that was leased to
third parties at the Cushing Terminal. The one million barrel expansion of
the Cushing Terminal was placed in service during the second quarter of 1999.
Throughput volumes at the Company's terminals averaged approximately 79,000
barrels per day in the current year period, up approximately 5% as compared
to the 1998 first half average of 75,000 barrels per day. Average leased
terminal capacity increased significantly from approximately 935,000 barrels
per month in last year's first half to 2.0 million barrels per month during
the current year period.

GENERAL

       Total G&A expenses, including midstream activities, were approximately
$11.7 million for the six months ended June 30, 1999, an increase of $6.9
million as compared to the 1998 comparative period. Approximately $6.2
million of the increase is attributable to the Company's midstream
activities. Approximately $5.1 million of the midstream increase is
associated with the May 1999 Scurlock Acquisition, the July 1998 All American
Acquisition and expenses incurred by PAA as a result of its being a separate
public entity. An additional $0.3 million is due to a one time expense
related to a staff reduction and relocation of certain functions related to
the midstream segment's pipeline operations. Interest expense for the six
month period ended June 30, 1999 increased to $19.5 million from $12.9
million for the comparative prior year period, primarily due to the debt
incurred for the Scurlock Acquisition and the All American Acquisition.
Capitalized interest was $2.2 million and $1.8 million for the six months
ended June 30, 1999 and 1998, respectively.

       The Company's total tax provision for the six months ended June 30,
1999, was approximately $4.6 million, as compared to the comparative period
1998 tax provision of approximately $1.7 million. Such increase is due to the
increase in income before taxes between the two periods. In both periods,
substantially all of the Company's income tax provision was deferred.

RECENT ACCOUNTING PRONOUNCEMENTS

       In June 1998, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards No. 133, Accounting for
Derivative Instruments and Hedging Activities ("FAS 133"). FAS 133 is
effective for all fiscal years beginning after June 15, 2000. FAS 133
requires that all derivative instruments be recorded on the balance sheet at
their fair value. Changes in the fair value of derivatives are recorded each
period in current earnings or other comprehensive income, depending on
whether a derivative is designated as part of a hedge transaction and, if it
is, the type of hedge transaction. For fair value hedge transactions in which
the Company is hedging changes in an asset's, liability's, or firm
commitment's fair value, changes in the fair value of the derivative
instrument will generally be offset in the income statement by changes in the
hedged item's fair value. For cash flow hedge transactions, in which the
Company is 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. 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 Company is required to adopt this statement beginning in 2001. The
Company has not yet determined the impact that the adoption of FAS 133 will
have on its results of operations or financial position.

CAPITAL RESOURCES, LIQUIDITY AND FINANCIAL CONDITION

ACQUISITIONS

Scurlock

       On May 12, 1999, Plains Scurlock, a limited partnership of which PAAI
is the general partner and Plains Marketing, L.P. is the limited partner,
completed the Scurlock Acquisition. Including working capital adjustments and
associated closing and financing costs, the cash purchase price was
approximately $141 million.

                                  Page 17 of 25
<PAGE>

       Financing for the Scurlock Acquisition was provided through (i) a
borrowing of approximately $92 million under Plains Scurlock's limited
recourse bank facility with BankBoston, N.A. (the "Plains Scurlock Credit
Facility"), (ii) the sale to the General Partner of 1.3 million Class B
Common Units ("Class B Units") of PAA at $19.125 per unit, the price equal to
the market value of PAA's common units ("Common Units") on May 12, 1999, for
a total cash consideration of $25 million and (iii) a $25 million draw under
PAA's existing revolving credit agreement. The funds for the purchase of the
Class B Units by the General Partner were provided through a capital
contribution by the Company which was financed by the Company's revolving
credit facility (the "Revolving Credit Facility").

       The Class B Units are initially pari passu with Common Units with
respect to distributions, and after six months are convertible into Common
Units upon approval of a majority of Common Unitholders. After such six month
period, the Class B Unitholder may request that PAA call a meeting of Common
Unitholders to consider approval of the conversion of Class B Units into
Common Units. If the approval of such conversion by the Common Unitholders is
not obtained within 120 days of such request (the "Initial Approval Period"),
the Class B Unitholders 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 Initial Approval Period. Except
for the vote to approve the conversion, Class B Units have the same voting
rights as the Common Units.

Chevron

       On July 15, 1999, Plains Scurlock completed the acquisition of a West
Texas crude oil pipeline and gathering system from Chevron Pipeline Company
for approximately $36.6 million including transaction costs (the "Chevron
Asset Acquisition"). The principal assets acquired include approximately 450
miles of crude oil transmission mainlines, approximately 340 miles of
associated gathering and lateral lines and approximately three million
barrels of crude oil storage and terminalling capacity in Crane, Ector,
Midland, Upton, Ward and Winkler Counties, Texas. Financing for the Chevron
Asset Acquisition was provided by a draw of $36.6 million under the term loan
portion of the Plains Scurlock Credit Facility.

       Chevron U.S.A Inc. ("Chevron"), which currently transports
approximately 24,000 barrels of crude oil per day on the system, will
continue to transport its equity crude oil production from the region on the
system under a twelve-year contractual arrangement.

Point Arguello

       On July 1, 1999, Arguello Inc., a wholly owned subsidiary of the
Company, acquired Chevron's interests in the Point Arguello Field. The
interests acquired include Chevron's 26% working interest in the Point
Arguello Field and associated onshore processing facilities, Chevron's right
to participate in surrounding leases and certain fee acreage onshore. The
acquisition, which was funded from the Company's working capital, has an
effective date of July 1, 1999. Chevron retained the obligation of (i)
removing, dismantling, and disposing of all existing offshore platforms, (ii)
removing and disposing of all existing pipelines and (iii) removing,
dismantling, disposing and remediation of all existing onshore facilities.
The Company assumed its 26% share of (i) plugging and abandoning all existing
well bores, (ii) removing conductors, (iii) flushing all lines and vessels,
and (iv) removing/abandoning all structures, fixtures and conditions created
subsequent to closing.

       Arguello Inc. will be the operator of record for the Point Arguello
field and has entered into an outsourcing agreement with a unit of Torch
Energy Advisors, Inc. for the conduct of daily operations and field
management.

PAA DISTRIBUTIONS

       On July 22, 1999, PAA declared a cash distribution of $0.4625 per Unit
on its outstanding Common Units, Class B Units and Subordinated Units. The
distribution is payable on August 13, 1999, to holders of record of such
Units on August 3, 1999. The total distribution to be paid is approximately
$14.9 million, with approximately $6.1 million to be paid to PAA's public
Unitholders and the remainder to be paid to the Company for its limited and
general partner interests. This distribution represents an increase of $.0125
per unit over the minimum quarterly distribution of $0.45 per unit.

                                  Page 18 of 25
<PAGE>

CREDIT FACILITIES

       The Plains Scurlock Credit Facility consists of (i) a five-year $126.6
million term loan and (ii) a three-year $35 million revolving credit
facility. The Plains Scurlock Credit Facility is nonrecourse to PAA, Plains
Marketing, L.P. and All American Pipeline, L.P. and is secured by the assets
acquired. Borrowings under the term loan bear interest at the London
Interbank Offering Rate ("LIBOR") plus 3% and under the revolving credit
facility at LIBOR plus 2.75%. A commitment fee equal to one-half of one
percent per year is charged on the unused portion of the revolving credit
facility. The revolving credit facility, which may be used for borrowings or
letters of credit to support crude oil purchases, matures in May 2002. The
term loan provides for principal amortization of $0.7 million annually
beginning May 2000, with a final maturity of May 2004. As of June 30, 1999,
letters of credit of approximately $15.2 million were outstanding under the
revolver and borrowings of $90 million were outstanding under the term loan.

       The Company has a $225 million Revolving Credit Facility with a group
of banks (the "Lenders"). The Revolving Credit Facility is guaranteed by all
of the Company's upstream subsidiaries and is collateralized by the oil and
gas properties of the Company and the guaranteeing subsidiaries and the stock
of all upstream subsidiaries. The borrowing base under the Revolving Credit
Facility at June 30, 1999, is $225 million and is subject to redetermination
from time to time by the Lenders in good faith, in the exercise of the
Lenders' sole discretion, and in accordance with customary practices and
standards in effect from time to time for oil and natural gas loans to
borrowers similar to the Company. Such borrowing base may be affected from
time to time by the performance of the Company's oil and natural gas
properties and changes in oil and natural gas prices. The Company incurs a
commitment fee of 3/8% per annum on the unused portion of the borrowing base.
The Revolving Credit Facility, as amended, matures on July 1, 2001, at which
time the remaining outstanding balance converts to a term loan which is
repayable in sixteen equal quarterly installments commencing October 1, 2001,
with a final maturity of July 1, 2005. The Revolving Credit Facility bears
interest, at the Company's option of either LIBOR plus 1 3/8% or Base Rate
(as defined therein). At June 30, 1999, outstanding borrowings under the
Revolving Credit Facility were approximately $117.3 million.

       Concurrently with the closing of the IPO, PAA entered into a $225
million bank credit agreement (the "Bank Credit Agreement") that includes a
$175 million term loan facility (the "Term Loan Facility") and a $50 million
revolving credit facility (the "PAA Revolving Credit Facility"). PAA may
borrow up to $50 million under the PAA Revolving Credit Facility for
acquisitions, capital improvements, working capital and general business
purposes. At June 30, 1999, PAA had $175 million outstanding under the Term
Loan Facility, representing indebtedness assumed from the General Partner and
$25 million outstanding under the PAA Revolving Credit Facility. The Term
Loan Facility matures in 2005, and no principal is scheduled for payment
prior to maturity. The Term Loan Facility may be prepaid at any time without
penalty. The PAA Revolving Credit Facility expires in November 2000.

       PAA has a $175 million letter of credit and borrowing facility (the
"Letter of Credit Facility"), the purpose of which is to provide (i) standby
letters of credit to support the purchase and exchange of crude oil for
resale and (ii) borrowings to finance crude oil inventory which has been
hedged against future price risk or designated as working inventory.
Aggregate availability under the Letter of Credit Facility for direct
borrowings and letters of credit is limited to a borrowing base which is
determined monthly based on certain current assets and current liabilities of
PAA, primarily crude oil inventory and accounts receivable and accounts
payable related to the purchase and sale of crude oil. At June 30, 1999, the
borrowing base under the Letter of Credit Facility was $175 million. The
Letter of Credit Facility has a $40 million sublimit for borrowings to
finance crude oil purchased in connection with operations at PAA's crude oil
terminal and storage facilities. At June 30, 1999, there were letters of
credit of approximately $90.1 million and borrowings of $22 million
outstanding under the Letter of Credit Facility.

INVESTING AND FINANCING ACTIVITIES

       At June 30, 1999, the Company had a working capital deficit of
approximately $6.3 million compared to a working capital deficit of $13.9
million at December 31, 1998. The Company has historically operated with a
working capital deficit due primarily to ongoing capital expenditures that
have been financed through cash flow and the Revolving Credit Facility.

       Net cash flows used in investing activities were $199.0 million and
$40.4 million for the six months ended June 30, 1999, and 1998, respectively.
Investing activities for the 1999 period include payments of approximately
$135.9 million related to the Scurlock Acquisition (net of Scurlock cash on
hand at acquisition date) and a $6.0 million deposit on the Chevron Asset
Acquisition. Investing activities include payments for acquisition,
exploration and development costs of $51.0


                                  Page 19 of 25
<PAGE>

million and $39.4 million for the six months ended June 30, 1999 and 1998,
respectively. Investing activities for the 1999 period include payments for
crude oil pipeline, gathering and terminal assets (excluding the Scurlock
Acquisition and the Chevron Asset Acquisition) of approximately $4.7 million,
including approximately $3.3 million related to the expansion of the Cushing
Terminal.

       Net cash provided by financing activities amounted to $179.6 million
and $56.4 million for the six months ended June 30, 1999 and 1998,
respectively. Financing activities for 1999 include approximately $117.0
million borrowed to fund the Scurlock Acquisition and approximately $6.0
million borrowed to fund a deposit paid on the Chevron Asset Acquisition,
which closed in July 1999. Included in both years are net proceeds from
borrowings under the Revolving Credit Facility as a result of acquisition,
exploration and development activities. Financing activities include
approximately $24.2 million and $17.9 million in short-term borrowings for
the six months ended June 30, 1999 and 1998, respectively, and approximately
$11.9 million and $18.0 million of repayments for the respective periods,
related to hedged crude oil inventory transactions at the Cushing Terminal.
Financing activities for the first six months of 1999 include cash
distributions paid to PAA's public Unitholders of approximately $8.4 million.

CHANGING OIL AND NATURAL GAS PRICES

       The Company's upstream activities are affected by changes in crude oil
prices which have historically been volatile. Although the Company has
routinely hedged a substantial portion of its crude oil production and
intends to continue this practice, substantial future crude oil price
declines would adversely affect the Company's overall results, and therefore
its liquidity. Furthermore, low crude oil prices could affect the Company's
ability to raise capital on terms favorable to the Company. In order to
manage its exposure to commodity price risk, the Company has routinely hedged
a portion of its crude oil production. For the second half of 1999, the
Company has entered into crude oil swap agreements for an average of 16,500
barrels per day at an average NYMEX WTI crude oil price of approximately
$18.20 per barrel. This hedge position is equivalent to approximately 66% of
second quarter 1999 average daily oil volumes, adjusted for the Point
Arguello acquisition completed effective July 1, 1999. For the first half of
2000, the Company has entered into various arrangements which will provide
for it to receive a minimum NYMEX WTI price of approximately $15.80 per
barrel on 17,500 barrels per day (equivalent to 70% of second quarter 1999
crude oil production levels, adjusted for Point Arguello). For the second
half of 2000, the Company has entered into various arrangements which will
provide for it to receive a minimum NYMEX WTI price of approximately $15.25
per barrel on 14,000 barrels per day (equivalent to 56% of second quarter
1999 crude oil production levels, adjusted for Point Arguello). Approximately
10,000 barrels per day of the volumes hedged in 2000 will participate in
price increases above the $15.25 floor price, subject to a ceiling limitation
of $19.75 per barrel. The foregoing NYMEX WTI crude oil prices are before
quality and location differentials. Management intends to continue to
maintain hedging arrangements for a significant portion of its production.
Such contracts may expose the Company to the risk of financial loss in
certain circumstances.

YEAR 2000

       YEAR 2000 ISSUE. Some software applications, hardware and equipment,
and embedded chip systems identify dates using only the last two digits of
the year. These products may be unable to distinguish between dates in the
year 2000 and dates in the year 1900. That inability, if not addressed, could
cause applications, equipment or systems to fail or provide incorrect
information after December 31, 1999, or when using dates after December 31,
1999. This in turn could have an adverse effect on the Company because the
Company directly depends on its own applications, equipment and systems and
indirectly depends on those of third parties with which the Company does
business. The Company's key applications, equipment, and automated systems
consist of:

       -   financial systems applications;
       -   computer hardware and equipment;
       -   embedded chip systems; and
       -   third-party developed software.

       YEAR 2000 PROJECT. In order to address the year 2000 issue, the
Company has implemented a year 2000 project for all of its business units. As
the Company evaluates new properties for acquisition, it performs a
pre-acquisition assessment to determine year 2000 readiness. Upon
acquisition, the Company has incorporated these properties into the year 2000
project. The Company has formed a project team to coordinate the five phases
of the year 2000 project. Those phases are:



                                  Page 20 of 25
<PAGE>

       -   assessment;
       -   remediation;
       -   testing;
       -   implementation of the necessary modifications; and
       -   contingency planning.

       The year 2000 project also includes the evaluation of the extent and
status of the year 2000 compliance efforts of third parties who are material
to the Company's operations and its business units. In conjunction with its
internal efforts, the Company retained a year 2000 consulting firm to review
certain operations of all of its business units and to assess the potential
impact of the year 2000 issue on such operations. The consulting firm has
completed its review, and the Company is utilizing the consultant's
recommendations in its year 2000 project. The Company also retained a second
year 2000 consulting firm to perform an assessment of certain field equipment
which has embedded chip systems. The Company and the consulting firm are
currently performing the necessary remediation, testing and modification of
embedded chip systems which are critical to the Company`s field operations.

       YEAR 2000 PROJECT STATUS. The assessment phase for all key
applications, equipment, and automated systems is complete. The remaining
phases of the project involving remediation, testing, and implementation of
necessary modifications are proceeding concurrently. The following table sets
forth the estimated dates of completion of the Year 2000 project for the
Company`s key applications, equipment, and automated systems:

<TABLE>
<CAPTION>

         Key Applications, Equipment               Estimated Completion
         and Automated Systems                             Date
         ---------------------                             ----

         <S>                                       <C>
         Third Party Developed Software              September 1999
         Computer Hardware and Equipment             October 1999
         Embedded Chip Systems                       October 1999
         Financial Systems Applications              October 1999

</TABLE>

       An integral part of the year 2000 project is communication with the
Company's critical suppliers and key customers and partners to determine
whether their operations and/or services or products will be year 2000 ready.
The Company has contacted all of these third parties requesting information
on the status of their year 2000 efforts and is currently evaluating
responses and making additional inquiries as needed.

       CONTINGENCY PLANNING. As the other phases of the year 2000 project
near completion, the Company is evaluating which of its business activities
may still be vulnerable to a year 2000 disruption. The Company is developing
appropriate contingency plans for each material "at risk" business activity
to provide an alternative means of functioning in an attempt to minimize the
effect of the potential year 2000 disruptions, both internally and on third
parties. The contingency plans are expected to be completed by December 1,
1999. Communications with third parties that are critical to the Company's
business will continue throughout the remainder of 1999, and the Company
plans to develop contingency plans to the extent necessary to address any
concerns regarding the year 2000 readiness of such third parties.

       COSTS OF THE YEAR 2000 PROJECT. Through June 30, 1999, the Company has
incurred approximately $1.3 million for its year 2000 project, approximately
$0.4 million of which were costs paid to third parties. While the total cost
of the Company's year 2000 project is still being evaluated, the Company
currently estimates that the costs of the project to be incurred in the
remainder of 1999 and 2000 is between $1.0 million and $1.2 million. The
Company anticipates that approximately $0.5 million of these estimated costs
will be paid to third parties with the remainder being internal costs. The
Company expects to fund these expenditures with cash from operations or
borrowings.

       RISK OF NON-COMPLIANCE. The items that pose the greatest year 2000
risks for the Company if implementation of the year 2000 project is not
successful are its financial systems applications, its pipeline supervisory
control and data acquisition ("SCADA") systems and embedded chip systems in
its field equipment. The potential problems if the year 2000 project is not
successful with respect to the financial systems applications are disruptions
of the Company's revenue gathering from and distribution to its customers and
vendors and the inability to perform the Company's other financial and
accounting functions. Failures of SCADA systems or embedded chip systems in
the Company's field equipment or its customers'



                                  Page 21 of 25
<PAGE>

equipment could disrupt the Company's upstream exploitation and production
activities and its midstream crude oil transportation, terminalling, storage
and gathering and marketing activities.

       While the Company believes that the year 2000 project will
substantially reduce the risks associated with the year 2000 issue, there can
be no assurance that the Company will be successful in completing each and
every aspect of the project on schedule, and if successful, that the project
will have the expected results. Due to the general uncertainty inherent in
the year 2000 issue, the Company cannot conclude that its failure or the
failure of third parties to achieve year 2000 compliance will not adversely
affect its financial position, results of operations or cash flows. Specific
factors that might affect the success of the Company's year 2000 efforts and
the occurrence of a year 2000 disruption or expense include:

       -   the Company's failure or the failure of its consultants to
           properly identify deficient systems;
       -   the failure of the selected remedial action to adequately address
           any deficiencies;
       -   the failure of the Company or its consultants to complete the
           remediation in a timely manner, due to shortages of qualified
           labor or other factors;
       -   unforeseen expenses related to the remediation of existing systems
           or the transition to replacement systems; and
       -   the failure of third parties to become compliant or to adequately
           notify us of potential non-compliance.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS

       The Company is exposed to various market risks, including volatility
in crude oil and natural gas commodity prices and interest rates. To manage
such exposure, the Company enters into various derivative transactions. The
Company does not enter into derivative transactions for speculative trading
purposes. Substantially all the Company's derivative contracts are exchange
traded or with major financial institutions and the risk of credit loss is
considered remote.

       COMMODITY PRICE RISK. The fair value of outstanding derivative
commodity instruments and the change in fair value that would be expected
from a 10 percent adverse price change are shown in the table below:

<TABLE>
<CAPTION>
                                                     CHANGE IN FAIR
                                        FAIR          VALUE FROM 10%
                                       VALUE       ADVERSE PRICE CHANGE
                                     ---------   ------------------------
                                              (IN MILLIONS)
            <S>                      <C>         <C>
            AT JUNE 30, 1999
              Crude Oil
                Swaps                 $  (4.3)            $ (8.5)
                Futures and option
                  contracts              (2.3)              (2.0)
</TABLE>

       INTEREST RATE RISK. The Company's debt instruments are sensitive to
market fluctuations in interest rates. The table below presents principal
cash flows and the related weighted average interest rates by expected
maturity dates for debt outstanding at June 30, 1999. The Company's variable
rate debt bears interest at LIBOR plus the applicable margin. The average
interest rates presented below are based upon rates in effect at June 30,
1999. The carrying value of variable rate bank debt approximates fair value
as interest rates are variable, based on prevailing market rates. The fair
value of fixed rate debt was based on quoted market prices based on trades of
subordinated debt. The fair value of the Redeemable Preferred Stock
approximates its liquidation value at June 30, 1999.

                                  Page 22 of 25
<PAGE>

<TABLE>
<CAPTION>
                                   -------------------------------------------------------------------------
                                                          EXPECTED YEAR OF MATURITY
                                   -------------------------------------------------------------------------    FAIR
                                     1999      2000       2001      2002      2003     THEREAFTER    TOTAL      VALUE
                                   ---------  --------   -------   -------   -------   -----------   -------   ---------
                                                              (DOLLARS IN MILLIONS)
<S>                                <C>        <C>        <C>       <C>       <C>       <C>           <C>       <C>>
LIABILITIES:
  Short-term debt  - variable rate   $ 22.0       $ -       $ -       $ -       $ -           $ -     $22.0      $ 22.0
    Average interest rate              6.3%                                                            6.3%
  Long-term debt - variable rate          -      25.7       8.0      30.0      30.0         313.6     407.3       407.3
    Average interest rate                 -      6.4%      6.7%      6.6%      6.6%          7.0%      6.9%
  Long-term debt - fixed rate             -         -         -         -         -         200.0     200.0       203.0
    Average interest rate                 -         -         -         -         -        10.25%
REDEEMABLE PREFERRED STOCK                -         -         -         -         -          92.7      92.7        92.7

</TABLE>


       Interest rate swaps and collars are used to hedge underlying debt
obligations. These instruments hedge 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 June 30,
1999, the Company had interest rate swap and collar arrangements for an
aggregate notional principal amount of $290 million. The Company would
receive approximately $9.0 million if such arrangements were terminated as of
such date.

FORWARD-LOOKING STATEMENTS AND ASSOCIATED RISKS

       All statements, other than statements of historical facts, included in
this report which address activities, events or developments that the Company
expects or anticipates will or may occur in the future are forward-looking
statements. Such forward-looking statements are subject to risks and
uncertainties including, among other things, market conditions, drilling and
operating hazards, uncertainties inherent in estimating oil and gas reserves,
uncertainties inherent in the year 2000 issue, environmental liabilities not
covered by an indemnity or insurance and other factors discussed in the
Company's Annual Report on Form 10-K for the year ended December 31, 1998.


                                  Page 23 of 25
<PAGE>

PART II.  OTHER INFORMATION

ITEMS 1, 2, 3 & 5 ARE NOT APPLICABLE AND HAVE BEEN OMITTED.

ITEM 4 - SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

       The 1999 Annual Meeting of Stockholders (the "Meeting") of the Company
       was held on May 20, 1999. At the Meeting, holders of common stock, $.10
       par value, of the Company ("Common Stock"), elected eight members of the
       Company's Board of Directors. No other matters were voted on at the
       Meeting.

       Out of the 16,891,617 shares of Common Stock entitled to vote at the
       Meeting, there were 14,193,031 shares of Common Stock represented at the
       Meeting either by proxies solicited in accordance with Schedule 14A or by
       security holders voting in person.

       The tabulation of votes for each director nominee is as follows:

<TABLE>
<CAPTION>
                      NOMINEES FOR ELECTION TO THE
                       COMPANY'S BOARD OF DIRECTORS            VOTES "FOR"        WITHHELD
                                                               -----------        --------
                       <S>                                     <C>                <C>>
                             Greg Armstrong                    14,135,643          57,388
                             Jerry L. Dees                     14,135,630          57,401
                           Tom H. Delimitros                   14,135,630          57,401
                          William H. Hitchcock                 14,135,345          57,686
                             Dan M. Krausse                    14,135,623          57,408
                             John H. Lollar                    14,135,630          57,401
                           Robert V. Sinnott                   14,135,630          57,401
                            J. Taft Symonds                    14,135,555          57,476

</TABLE>

ITEM 6 - EXHIBITS AND REPORTS ON FORM 8-K

       A.     Exhibits

              10(h)  Purchase and Sale Agreement dated June 4, 1999, by and
                     among the Company, Chevron U.S.A., Inc., and Chevron
                     Pipe Line Company.

              10(p)  Third Amendment to Fourth Amended and Restated Credit
                     Agreement dated June 21, 1999, among the Company and
                     ING (U.S.) Capital Corporation, et. al.

              10(q)  Second Amendment to Plains Resources 1996 Stock
                     Incentive Plan dated May 20, 1999.

              27.    Financial Data Schedule

       B.     Reports on Form 8-K

              Amendment No. 1 to Current Report was filed on June 28, 1999, on
              form 8-K/A which amends the financial statements, exhibits or
              other portion of the Current Report on Form 8-K filed with the
              Securities and Exchange Commission on May 27, 1999, with respect
              to PAA's acquisition of Scurlock Permian LLC and certain other
              pipeline assets from Marathon Ashland Petroleum LLC.

              A Current Report on Form 8-K was filed on May 27, 1999, with
              respect to PAA's acquisition of Scurlock Permian LLC and certain
              other pipeline assets from Marathon Ashland Petroleum LLC.


                                  Page 24 of 25
<PAGE>

                                   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 and thereunto duly authorized.



                              PLAINS RESOURCES INC.




Date:      August 16, 1999        By: /s/  Cynthia A. Feeback
                                      -------------------------------------
                                       Cynthia A. Feeback, Vice President -
                                       Accounting and Assistant Treasurer
                                       (Principal Accounting Officer)


                                  Page 25 of 25