<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, 1997


[ ]  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.) 



                               1600 SMITH 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
                                         ------      -------

16,580,807 shares of common stock $.10 par value, issued and outstanding at 
July 31, 1997.

                                  Page 1 of 21
<PAGE>
 
                     PLAINS RESOURCES INC. AND SUBSIDIARIES
                               TABLE OF CONTENTS



PART I.  FINANCIAL INFORMATION                                PAGE

CONDENSED CONSOLIDATED FINANCIAL STATEMENTS:

Condensed Consolidated Balance Sheets:
  June 30, 1997 and December 31, 1996........................    3
Condensed Consolidated Statements of Operations:
  For the three and six months ended June 30, 1997 and 1996..    4
Condensed Consolidated Statements of Cash Flows:
  For the six months ended June 30, 1997 and 1996............    5
Notes to Condensed Consolidated Financial Statements.........    6

MANAGEMENT'S DISCUSSION AND ANALYSIS.........................    9

PART II.  OTHER INFORMATION..................................   19

                                  Page 2 of 21
<PAGE>
 
PLAINS RESOURCES INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS (in thousands, except share data)

<TABLE>
<CAPTION>
 
 
                                                                                                          JUNE 30,    DECEMBER 31,
                                                                                                            1997          1996
                                                                                                         -----------  -------------
                                                                                                         (UNAUDITED)
                                                              ASSETS
CURRENT ASSETS
<S>                                                                                                      <C>          <C>
Cash and cash equivalents                                                                                 $   4,557      $   2,517
Accounts receivable and other                                                                                67,167         94,778
Inventory                                                                                                    39,583          4,563
                                                                                                          ---------   ------------
 
Total current assets                                                                                        111,307        101,858
                                                                                                          ---------   ------------
PROPERTY AND EQUIPMENT
Oil and natural gas properties - full cost method:
       Subject to amortization                                                                              438,453        384,019
       Not subject to amortization                                                                           48,712         41,698
Downstream assets, primarily crude oil terminal and storage facility                                         35,395         35,122
Other property and equipment                                                                                  8,638          8,275
                                                                                                          ---------   ------------
                                                                                                            531,198        469,114
Less allowance for depreciation, depletion and amortization                                                (168,496)      (158,074)
                                                                                                          ---------   ------------
                                                                                                            362,702        311,040
                                                                                                          ---------   ------------
OTHER ASSETS                                                                                                 16,338         17,351
                                                                                                          ---------   ------------
                                                                                                          $ 490,347      $ 430,249
                                                                                                          =========   ============
                                               LIABILITIES AND STOCKHOLDERS' EQUITY
 
CURRENT LIABILITIES
Accounts payable and other current liabilities                                                            $  91,725      $  93,242
Interest payable                                                                                              6,117          5,089
Royalties payable and drilling advances                                                                       6,878          7,859
Notes payable and other current obligations                                                                  17,001            511
                                                                                                          ---------   ------------
Total current liabilities                                                                                   121,721        106,701
 
BANK DEBT                                                                                                   109,200         72,700
SUBORDINATED DEBT                                                                                           149,151        149,121
OTHER LONG-TERM DEBT                                                                                          3,578          3,578
OTHER LONG-TERM LIABILITIES                                                                                   3,482          2,577
                                                                                                          ---------   ------------
                                                                                                            387,132        334,677
                                                                                                          ---------   ------------
STOCKHOLDERS' EQUITY
Common stock, $.10 par value, 50,000,000 shares authorized;                                                                        
  issued and outstanding 16,568,685 at June 30, 1997,
  and 16,518,645 shares at December 31, 1996                                                                  1,657          1,652 
Additional paid-in capital                                                                                  120,546        120,051
Accumulated deficit                                                                                         (18,988)       (26,131)
                                                                                                          ---------   ------------
                                                                                                            103,215         95,572
                                                                                                          ---------   ------------
                                                                                                          $ 490,347      $ 430,249
                                                                                                          =========   ============
</TABLE> 

           See notes to condensed consolidated financial statements.

                                  Page 3 of 21
<PAGE>
 
PLAINS RESOURCES INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (unaudited) 
(in thousands, except per share data)
 
 
<TABLE> 
<CAPTION> 
 
                                                                                   THREE MONTHS ENDED        SIX MONTHS ENDED
                                                                                         JUNE 30,                JUNE 30,
                                                                                   --------------------   ------------------------
                                                                                      1997       1996        1997         1996
                                                                                   ---------   --------   ---------   ------------
<S>                                                                                 <C>        <C>        <C>            <C> 
REVENUE
Oil and natural gas sales                                                           $ 26,285   $ 25,115   $  52,564      $  45,772
Marketing, transportation and storage                                                162,219    130,760     343,014        233,550
Interest and other income                                                                 88         55         146            121
                                                                                    --------   --------   ---------   ------------
                                                                                     188,592    155,930     395,724        279,443
                                                                                    --------   --------   ---------   ------------
EXPENSES
Production expenses                                                                   10,771      9,319      20,965         18,631
Purchases, transportation and  storage                                               159,155    128,258     337,484        229,099
General and administrative                                                             2,120      1,984       4,215          4,042
Depreciation, depletion and amortization                                               5,944      5,532      11,264         10,421
Interest expense                                                                       5,181      4,335       9,891          8,532
Litigation settlement                                                                     --         --          --          4,000
                                                                                    --------   --------   ---------   ------------
                                                                                     183,171    149,428     383,819        274,725
                                                                                    --------   --------   ---------   ------------
Income before income taxes and                                                         
extraordinary item                                                                     5,421      6,502      11,905          4,718 
Income tax expense (benefit)
   Current                                                                                96         --         210             --
   Deferred                                                                            2,073      1,888       4,552         (9,112)
                                                                                    --------   --------   ---------   ------------
 
INCOME BEFORE EXTRAORDINARY ITEM                                                       3,252      4,614       7,143         13,830
 
EXTRAORDINARY ITEM:
(Loss) on early extinguishment of debt, net of tax benefit                                --      1,888          --         (6,619)
                                                                                    --------   --------   ---------   ------------
 
NET INCOME                                                                          $  3,252   $  6,502   $   7,143      $   7,211
                                                                                    ========   ========   =========   ============
 
Net income per common and common equivalent share:
Before extraordinary item                                                              $0.18      $0.26       $0.40          $0.80
Extraordinary item                                                                        --       0.11          --          (0.38)
                                                                                    --------   --------   ---------   ------------
                                                                                       $0.18      $0.37       $0.40          $0.42
                                                                                    ========   ========   =========   ============
Weighted average number of common and common equivalent shares                        17,938     17,573      18,007         17,335
                                                                                    ========   ========   =========   ============
</TABLE> 
 
           See notes to condensed consolidated financial statements.

                                  Page 4 of 21
<PAGE>
 
PLAINS RESOURCES INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited) (in thousands)
 
<TABLE> 
<CAPTION> 
 
                                                                                                             SIX MONTHS ENDED
                                                                                                                 JUNE 30,
                                                                                                          ------------------------
                                                                                                             1997         1996
                                                                                                          ---------   ------------
<S>                                                                                                       <C>            <C> 
CASH FLOWS FROM OPERATING ACTIVITIES
Net income                                                                                                $   7,143      $   7,211
Items not affecting cash flows from operating activities:
    Depreciation, depletion and amortization                                                                 11,264         10,421
    Loss on early extinguishment of debt, net of tax                                                             --          6,619
    Deferred income taxes                                                                                     4,552         (9,112)
    Amortization of debt discount and other                                                                     173             16
Change in assets and liabilities resulting from operating activities:
    Accounts receivable                                                                                      24,292        (19,307)
    Inventory                                                                                               (35,020)           735
    Prepaids and other                                                                                         (432)          (686)
    Accounts payable and other current liabilities                                                           (9,606)        20,517
    Interest payable                                                                                          1,029          1,086
    Royalties payable                                                                                           (16)           787
                                                                                                          ---------   ------------
 
Net cash provided by operating activities                                                                     3,379         18,287
                                                                                                          ---------   ------------
 
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from the sale of oil and natural gas properties                                                        200          3,066
Payment for acquisition, exploration and development costs                                                  (50,754)       (22,326)
Payment for additions to other property and other assets                                                     (3,817)        (1,188)
                                                                                                          ---------   ------------
 
Net cash used in investing activities                                                                       (54,371)       (20,448)
                                                                                                          ---------   ------------
 
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt                                                                                105,600        202,223
Proceeds from short-term debt                                                                                16,490             --
Principal payments of long-term debt                                                                        (69,100)      (189,900)
Costs incurred to redeem long-term debt                                                                          --         (6,468)
Payments of other long-term debt                                                                                 --         (3,946)
Other                                                                                                            42           (272)
                                                                                                          ---------   ------------
 
Net cash provided by financing activities                                                                    53,032          1,637
                                                                                                          ---------   ------------
 
Net increase (decrease) in cash and cash equivalents                                                          2,040           (524)
Cash and cash equivalents, beginning of period                                                                2,517          6,129
                                                                                                          ---------   ------------
 
Cash and cash equivalents, end of period                                                                  $   4,557      $   5,605
                                                                                                          =========   ============
 
</TABLE>

           See notes to condensed consolidated financial statements.

                                  Page 5 of 21
<PAGE>
 
                     PLAINS RESOURCES INC. AND SUBSIDIARIES

              NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

                                 JUNE 30, 1997
                                  (UNAUDITED)

NOTE 1--ACCOUNTING POLICIES

The accompanying unaudited condensed consolidated financial statements 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, 1996 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.  Certain reclassifications have
been made to the prior year statements to conform with 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, 1997, 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.

NOTE 2 -- PROPERTY ACQUISITION

In March 1997, the Company completed the acquisition of Chevron USA's
("Chevron") interest in the Montebello Field for $25 million, effective February
1, 1997.  The assets acquired consist of a 100% working interest and a 99.2% net
revenue interest in 55 producing oil wells and related facilities and also
include approximately 450 acres of surface fee lands.  At the acquisition date,
the Montebello Field, which is located approximately 15 miles from the Company's
existing LA Basin operations, was producing approximately 800 barrels of oil and
800 Mcf of gas per day and added approximately 23 million barrels of oil
equivalent to the Company's proved reserves.  The acquisition was funded with
proceeds from the Company's revolving credit facility ("Revolving Credit
Facility").

NOTE 3 -- LONG-TERM DEBT

On July 23, 1997, the Company sold $50 million of Senior Subordinated Notes due
2006, Series C, bearing a coupon rate of 10.25% (the "Series C 10.25% Notes").
Such notes were issued pursuant to a Rule 144A private placement at
approximately 107.21% of par to yield a minimum yield to worst of 8.79%, or
9.03% yield to maturity.  The stated coupon rate of interest and maturity date
are the same as those of the Company's existing $150 million principal amount of
senior subordinated notes currently outstanding.  The Series C 10.25% Notes are
redeemable, at the option of the Company, on or after March 15, 2001 at 105.13%,
at decreasing prices thereafter prior to March 15, 2004, and thereafter at 100%
plus, in each case, accrued interest to the date of redemption.  In addition,
prior to March 15, 1999, up to $15 million in principal amount of the Series C
10.25% Notes are redeemable at the option of the Company, in whole or in part,
from time to time, at 110.25% of the principal amount thereof, with the Net
Proceeds (as defined in the Indenture) of any Public Equity Offering (as defined
in the Indenture).

                                  Page 6 of 21
<PAGE>
 
The indenture under which the Series C 10.25% Notes were issued (the
"Indenture") contains covenants including, but not limited to, covenants with
respect to the following: (i) limitations on incurrence of additional
indebtedness; (ii) limitations on certain investments; (iii) limitations on
restricted payments; (iv) limitations on disposition of assets; (v) limitations
on dividends and other payment restrictions affecting subsidiaries; (vi)
limitations on transactions with affiliates; (vii) limitations on liens; and
(viii) restrictions on mergers, consolidations and transfers of assets. In the
event of a Change of Control and a corresponding Rating Decline, as both are
defined in the Indenture, the Company will be required to make an offer to
repurchase the Series C 10.25% Notes at 101% of the principal amount thereof,
plus accrued and unpaid interest to the date of the repurchase. The Series C
10.25% Notes are unsecured general obligations of the Company and are
subordinated in right of payment to all existing and future senior indebtedness
of the Company and are guaranteed by all of the Company's subsidiaries.

Proceeds from the sale of the Series C 10.25% Notes, net of offering costs, were
approximately $53 million and were used to reduce the balance outstanding on the
Revolving Credit Facility.

In March 1997, the Company's Revolving Credit Facility and borrowing base
thereunder was increased to $165 million from $125 million.  The Revolving
Credit Facility, as amended, converts to a term loan on July 1, 1999, with a
final maturity of July 1, 2004, and bears interest at the option of the Company
at LIBOR plus 1.375% or Base Rate (as defined therein).  The Revolving Credit
Facility is guaranteed by all of the Company's principal subsidiaries and is
secured by the oil and gas properties of the Company and its subsidiaries and
the stock of all subsidiaries.  At June 30, 1997, the Company had approximately
$109 million in borrowings and a $1 million standby letter of credit outstanding
under the Revolving Credit Facility.

NOTE 4 -- UNCOMMITTED SECURED TRANSACTIONAL GUIDANCE FACILITY

Plains Marketing and Transportation Inc. ("Plains Marketing") and PMCT Inc.,
wholly owned subsidiaries of the Company, have a $90 million Transactional
Facility with five banks.  The purpose of the Transactional Facility is to
provide standby letters of credit to support the purchase of crude oil for
resale and borrowings to finance crude oil inventory that has been hedged
against future price risk.  In August 1997, the sublimit for cash borrowings
under the Transactional Facility was increased to $25 million from $20 million.
Letters of credit under the Transactional Facility are generally issued for
seventy-day periods and bear fees of 1 1/8% per annum.  Borrowings incur
interest at the option of the borrower at (i) the Base Rate or (ii) LIBOR plus 
1 1/2%.  At June 30, 1997, approximately $38 million in letters of credit and
$16.5 million in borrowings were outstanding under the Transactional Facility.

The Transactional Facility is secured by all of the assets of Plains Marketing
and is guaranteed by the Company.  The Company's guarantee is secured by a $1.0
million standby letter of credit issued on behalf of the Company.  All
financings under the Transactional Facility, which expires in November 1997, are
at the discretion of the lenders.

NOTE 5 -- EARNINGS PER SHARE

Earnings per share is based on the weighted average number of common and common
equivalent shares outstanding.  Common equivalent shares include employee stock
options and warrants.

In February 1997, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards No. 128 ("SFAS 128"), Earnings Per
Share ("EPS").  SFAS 128 replaces the presentation of primary EPS with a
presentation of basic EPS and requires a dual presentation of basic and 

                                  Page 7 of 21
<PAGE>
 
diluted EPS on the face of the income statement for all entities with complex
capital structures. Basic EPS excludes dilutive securities and is computed by
dividing income available to common stockholders by the weighted-average number
of common shares outstanding for the period. Diluted EPS reflects the potential
dilution that could occur if dilutive securities were converted into common
stock and is computed similarly to fully diluted EPS pursuant to previous
accounting pronouncements. SFAS 128 is effective for periods ending after
December 15, 1997, including interim periods, although earlier application is
not permitted. SFAS 128 requires restatement of all prior period EPS data
presented.

The Company reported primary EPS of $.18 per share and $.37 per share for the
three months ended June 30, 1997 and 1996, respectively, and $.40 per share and
$.42 per share for the six months ended June 30, 1997 and 1996, respectively.
Under SFAS 128, basic EPS would have been $.20 per share and $.40 per share for
the three months ended June 30,1997 and 1996, respectively, and $.43 per share
and $.44 per share for the six months ended June 30, 1997 and 1996,
respectively.  Diluted EPS would have been $.18 per share and $.37 per share for
the three months ended June 30, 1997 and 1996, respectively, and $.40 per share
and $.42 per share for the six months ended June 30, 1997 and 1996,
respectively.

NOTE 6 -- NEW ACCOUNTING PRONOUNCEMENT

In July 1997, the FASB issued Statement of Financial Accounting Standards No.
131 ("SFAS 131"), Disclosures About Segments of an Enterprise and Related
Information, effective for fiscal years beginning after December 15, 1997.  This
statement introduces a new model for segment reporting and applies to public,
for-profit entities.  SFAS 131 requires disclosures for each segment that are
similar to those required under current standards with the addition of quarterly
disclosure requirements and a finer partitioning of geographic disclosures.
Reportable segments are based on products and services, geography, legal
structure, management structure or any manner in which management disaggregates
a company.  This statement replaces the notion of industry and geographic
segments in current FASB standards.  Management is currently evaluating the
impact of this statement on the Company's disclosures.

                                  Page 8 of 21
<PAGE>
 
                     MANAGEMENT'S DISCUSSION AND ANALYSIS

RESULTS OF OPERATIONS

Three month periods ended June 30, 1997 and 1996

For the quarter ended June 30, 1997, the Company reported net income of $3.3
million, or $.18 per share.  This compares with $6.5 million, or $.37 per share,
for last year's second quarter, which included a $1.9 million income tax benefit
related to an extraordinary item and the effects of higher commodity prices.
Cash flow from operations (net income plus noncash expenses) was $11.4 million
and earnings before interest, taxes, depreciation, depletion and amortization
("EBITDA") was $16.5 million in the current quarter.  Such results compare to
$12.0 million and $16.4 million, respectively, for the second quarter of 1996
which reflect the impact of higher commodity prices.

Modifying last year's quarter to reflect crude oil prices in effect during the
1997 quarter and to exclude the nonrecurring tax benefits results in normalized
net income of $3.0 million, or $.17 per share, for the prior year period.  On
this comparative basis, net income for the current year period represents a 10%
improvement over the prior year normalized quarterly results.  The prior year
period's higher crude oil price increased such quarter's cash flow and EBITDA by
approximately $1.5 million.  During the 1996 second quarter, the benchmark NYMEX
West Texas Intermediate crude oil price averaged $21.57 per barrel, $1.63 per
barrel or 8% higher than the $19.94 per barrel average for the current year
quarter.

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,
                                        ----------------------------------
                                              1997              1996
                                        ----------------  ----------------
<S>                                     <C>               <C>
                                          (IN THOUSANDS, EXCEPT PER UNIT
                                                      DATA)
                                                   (UNAUDITED)
AVERAGE DAILY PRODUCTION VOLUMES
   BARRELS OF OIL EQUIVALENT ("BOE")
   LA Basin (89% oil).................              10.8               9.2
   S. Florida (100% oil)..............               5.6               5.2
   Illinois Basin (100% oil)..........               3.4               3.4
   Other properties...................               0.2                --
                                                  ------            ------
   Total (93% oil)....................              20.0              17.8
                                                  ======            ======
 
UNIT ECONOMICS
   Average sales price per BOE........            $14.44            $15.47
   Production expenses per BOE........              5.92              5.74
                                                  ------            ------
   Gross margin per BOE...............              8.52              9.73
   Upstream G&A expense per BOE.......              0.69              0.79
                                                  ------            ------
   Gross profit per BOE...............            $ 7.83            $ 8.94
                                                  ======            ======
</TABLE>

Oil and natural gas production for the second quarter of 1997 increased
approximately 12% to an average of 20,000 BOE per day as compared to the second
quarter 1996 average of 17,800 BOE per day.  Total

                                  Page 9 of 21
<PAGE>
 
production for the three month periods ended June 30, 1997 and 1996, was 1.82
million BOE and 1.62 million BOE, respectively.  Upstream, the Company's unit
gross margin was $8.52 per BOE, a 12% decrease compared to $9.73 per BOE
recorded in last year's second quarter primarily due to the decrease in product
prices.  Unit gross profit, which deducts all pre-interest cash costs
attributable to the upstream segment, was $7.83 per BOE, also down 12% from the
1996 amount of $8.94 per BOE.

The increase in production volumes is attributable to the Company's ongoing
exploitation activities on its three core properties and the acquisition of
Chevron USA's ("Chevron") interest in the Montebello Field (the "Montebello
Acquisition") during the first quarter of 1997.  The Montebello Field
contributed approximately 89,000 BOE to the Company's production during the 1997
second quarter, or an average of approximately 980 BOE per day.

Net daily production in the LA Basin increased approximately 17% to 10,800 BOE
in the second quarter of 1997 compared to 9,200 BOE in the same quarter of 1996.
Excluding the production from the Montebello Field, production was 9,800 BOE per
day which represents a 7% increase over the comparative prior year quarter.  Net
daily production in the Illinois Basin averaged approximately 3,400 barrels per
day during the second quarter of 1997 which is flat with the 1996 second
quarter.  Net daily production in the Sunniland Trend of South Florida averaged
approximately 5,600 barrels per day during the second quarter of 1997, an 8%
increase over the 5,200 barrels per day averaged during the second quarter of
1996.  Last year's quarter benefitted from initial production rates from the
Raccoon Point #34-5 well, which averaged 3,100 barrels per day gross (2,600 net)
compared to approximately 2,400 barrels per day gross (2,000 net) during the
second quarter of this year.  Due to the high volume of production that is
generated by a few wells in the Sunniland Trend, abrupt or abnormal declines or
downtime due to mechanical, marketing, or other conditions on any of the
properties in this area could have a significant impact on production.  During
July 1997, the Company experienced an unusually high amount of production loss
due to downtime in South Florida.  Although substantially all of the production
is back on line or anticipated to be back on line soon, the anticipated total
loss of production from all South Florida fields is estimated at approximately
22,000 barrels of oil, or approximately 200 barrels of oil per day, averaged
over the third quarter of 1997.

Oil and natural gas revenues increased 5% to $26.3 million for the second
quarter of 1997 due to increased production volumes.  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 $14.44 per BOE, down 7% from the 1996 second quarter average
price of $15.47 per BOE.  An increase in the current quarter's average hedge
price partially offset the comparative decline in commodity prices and an
increase in the price differential off of NYMEX for the Company's South Florida
production.  The Company had hedges on approximately 14,000 barrels per day or
70% of its total production in the second quarter of 1997 at an average NYMEX
benchmark price of approximately $19.25 per barrel.  During last year's second
quarter, approximately 10,000 barrels per day or 57% of total production was
hedged at an average NYMEX benchmark price of $18.04 per barrel.  Hedging
transactions had the effect of decreasing the Company's average price per BOE by
$.60 and $2.03 in the second quarter of 1997 and 1996, respectively.

Unit production expenses increased approximately 3% to $5.92 per BOE during the
quarter from the $5.74 per BOE for the 1996 quarter primarily as a result of the
current year impact of the Montebello Field production expenses which averaged
$6.89 per BOE.  In addition, last year's expenses included the effects of a
$230,000 refund for electricity overcharges which reduced production expenses by
$.14 per BOE in the 1996 second quarter.  Total production expenses increased to
$10.8 million from $9.3 million for the second quarter of 1996 primarily due to
the Montebello Acquisition and increased production levels.

                                 Page 10 of 21
<PAGE>
 
Unit general and administrative ("G&A") expense in the upstream segment declined
13% to $.69 per BOE from $.79 per BOE in the second quarter of 1996 due to
increased production levels and to the Company's ongoing focus on cost control.
Depreciation, depletion and amortization ("DD&A") per BOE declined to $2.85 for
the second quarter of 1997 from $3.00 per BOE in the 1996 comparative quarter.
Such reduction is attributable to the increase in proved reserves from the
Company's acquisition and exploitation activities.

Downstream Results

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

<TABLE>
<CAPTION>
 
                                            THREE MONTHS ENDED
                                                 JUNE 30,
                                            ------------------
                                              1997      1996
                                            --------  --------
<S>                                         <C>       <C>
                                              (IN THOUSANDS)
OPERATING RESULTS
   Gross margin...........................    $3,064    $2,502
   G&A expense............................       869       707
                                              ------    ------
   Gross profit...........................    $2,195    $1,795
                                              ======    ======
 
AVERAGE DAILY VOLUMES
   Crude oil barrels marketed.............        71        59
   Crude oil terminal throughput barrels..        80        51
 
</TABLE>

Despite significant downward pressure on marketing margins throughout the
industry generally, strength in the Company's storage and terminalling
activities enabled this segment to generate its strongest quarterly results to
date.  The Company's downstream segment reported gross margin (marketing,
transportation and storage revenues less purchases, transportation and storage
expenses) of $3.1 million for the second quarter of 1997, reflecting a 22%
increase over the $2.5 million reported for the 1996 quarter.  Gross revenues
were $162.2 million and $130.8 million for the respective periods.  Gross profit
(gross margin less downstream G&A expenses) increased 22% to $2.2 million versus
$1.8 million in the second quarter of 1996.  Downstream G&A expenses increased
from $707,000 to $869,000 in the current year quarter primarily as a result of
additional personnel added to further expand marketing activities.  Average
crude oil volumes marketed increased approximately 20% to 71,000 barrels per day
from the 59,000 barrels per day averaged during the 1996 quarter.  Throughput
activity at the Company's Cushing, Oklahoma, storage and terminal facility (the
"Cushing Terminal") increased 57% to an average of 80,000 barrels per day.  The
1996 second quarter throughput averaged approximately 51,000 barrels per day.

A strong backward market for crude oil existed during 1996 and the first quarter
of 1997.  However, during the second quarter of 1997, such market was a flat to
slightly contango market.  Typically, margins for crude oil marketing are
strongest in a backward market.  During a contango market, when marketing
margins are generally smaller, the Company's terminalling and storage operations
at the Cushing Terminal typically become more profitable due to (i) the
Company's ability to take delivery on crude oil which is simultaneously
purchased and resold at a profit for delivery in a subsequent month and (ii) the
increased demand by third parties for storage capacity.

                                 Page 11 of 21
<PAGE>
 
General

Total G&A expenses increased slightly to $2.1 million for the second quarter of
1997, as a result of increased G&A expenses in the downstream segment.  Interest
expense for the quarter ended June 30, 1997, increased to $5.2 million from $4.3
million for the comparative prior year quarter primarily due to higher
outstanding debt levels as a result of capital expenditures related to Company's
acquisition and exploitation activities.  In addition, capitalized interest
decreased to $.8 million for the three months ended June 30, 1997, from $.9
million for the 1996 quarter.

During the second quarter of 1997, the Company recognized a deferred tax
provision of $2.1 million and a current tax provision of $.1 million.  During
the second quarter of 1996, the Company recognized a deferred tax provision of
$1.9 million and an offsetting $1.9 million deferred tax benefit reported as an
extraordinary item.  Such deferred tax benefit is attributable to the first
quarter 1996 extraordinary loss from the early redemption of the Company's $100
million of 12% Senior Subordinated Notes (the "12% Notes").

In February 1997, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 128 ("SFAS 128"), Earnings Per Share ("EPS").
SFAS 128 replaces the presentation of primary EPS with a presentation of basic
EPS and requires a dual presentation of basic and diluted EPS on the face of the
income statement for all entities with complex capital structures. Basic EPS
excludes dilutive securities and is computed by dividing income available to
common stockholders by the weighted-average number of common shares outstanding
for the period.  Diluted EPS reflects the potential dilution that could occur if
dilutive securities were converted into common stock and is computed similarly
to fully diluted EPS pursuant to previous accounting pronouncements.  SFAS 128
is effective for periods ending after December 15, 1997, including interim
periods, although earlier application is not permitted.  SFAS 128 requires
restatement of all prior period EPS data presented.

The Company reported primary EPS of $.18 per share and $.37 per share for the
three months ended June 30, 1997 and 1996, respectively.  Under SFAS 128, basic
EPS would have been $.20 per share and $.40 per share for the three months ended
June 30,1997 and 1996, respectively, and diluted EPS would have been $.18 per
share and $.37 per share for the same respective periods.

Six month periods ended June 30, 1997 and 1996

For the six months ended June 30, 1997, the Company reported net income of $7.1
million, or $.40 per share, compared to net income for the same period of 1996
of $7.2 million, or $.42 per share, which includes the extraordinary item and
nonrecurring tax benefits.  Pretax income for the first half of 1997 was $11.9
million as compared to $4.7 million for the first six months of 1996.  For the
first half of 1997, cash flow from operations increased 21% to $23.1 million and
EBITDA increased 19% to $33.0 million.  The 1997 amounts reflect increases of
$4.0 million in cash flow and $5.3 million in EBITDA over 1996's respective
amounts of $19.1 million and $27.7 million.  The improvement in operating
results is primarily attributable to increased production volumes in the
upstream segment and continued expansion of marketing and terminalling
activities in the downstream segment.  Net cash provided by operating
activities, as reported in the consolidated statements of cash flows, decreased
to $3.4 million for the six months ended June 30, 1997, as compared to $18.3
million for the 1996 comparative period due to crude oil inventory purchases at
the Cushing Terminal.  Excluding such crude oil inventory purchases, net cash
provided by operating activities would have been $36.2 million for the 1997
period.  Such inventory has been hedged against price risk.

                                 Page 12 of 21
<PAGE>
 
Upstream Results

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

<TABLE>
<CAPTION>
 
                                             SIX MONTHS ENDED
                                                 JUNE 30,
                                    ----------------------------------
                                          1997              1996
                                    ----------------  ----------------
<S>                                 <C>               <C>
                                      (IN THOUSANDS, EXCEPT PER UNIT
                                                  DATA)
                                               (UNAUDITED)
AVERAGE DAILY PRODUCTION VOLUMES
   BARRELS OF OIL EQUIVALENT
   LA Basin (89% oil).............              10.5               9.0
   S. Florida (100% oil)..........               5.4               4.2
   Illinois Basin (100% oil)......               3.4               3.4
   Sold properties................               0.1               0.1
                                              ------            ------
   Total (94% oil)................              19.4              16.7
                                              ======            ======
 
UNIT ECONOMICS
   Average sales price per BOE....            $14.96            $15.04
   Production expenses per BOE....              5.97              6.12
                                              ------            ------
   Gross margin per BOE...........              8.99              8.92
   Upstream G&A expenses per BOE..              0.71              0.85
                                              ------            ------
   Gross profit per BOE...........            $ 8.28            $ 8.07
                                              ======            ======
</TABLE>

Production for the first six months of 1997 averaged approximately 19,400 BOE
per day, a 16% increase over the 16,700 BOE per day averaged during the first
half of 1996.  Total production for the first six months of 1997 increased to
3.5 million BOE versus the 3.0 million BOE produced in the 1996 comparative
period.  The Company's unit gross margin increased to $8.99 per BOE, a 1%
improvement over the $8.92 per BOE recorded in last year's first half.  Unit
gross profit, which deducts all pre-interest cash costs attributable to the
upstream segment, was $8.28 per BOE, up 3% over 1996's first half average of
$8.07 per BOE.

The significant increase in production volumes is attributable to the Company's
acquisition and exploitation activities.  Net daily production from the
Company's LA Basin properties for the first half of 1997 increased to
approximately 10,500 BOE per day, up 1,500 BOE per day, or 17% over last year's
comparative period.  Excluding the production from the Montebello Field,
production was 9,700 BOE per day which represents an 8% increase over the
comparative prior year period.  Net daily production in the Illinois Basin
averaged approximately 3,400 barrels per day during the first half of 1997 which
is flat with the 1996 period.  Net production from the Company's South Florida
Sunniland Trend properties increased approximately 29% to average 5,400 barrels
of oil per day in the first half of 1997 as compared to 4,200 barrels per day in
last year's comparative period.

Oil and natural gas revenues increased 15% to $52.6 million for the first six
months of 1997 due to increased production volumes.  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 prices, decreased 1% to $14.96 per BOE primarily due to an increase in the
price differential off of NYMEX for the Company's South Florida production which
offset higher commodity prices.  During the current year, the NYMEX benchmark
price averaged $21.38 per barrel, up 4% as compared to an average of $20.56 in
the correlative period of 1996.  Approximately 82% of the 

                                 Page 13 of 21
<PAGE>
 
Company's oil production was hedged during the first half of 1997 at an average
NYMEX price of $19.41 per barrel. Financial swap arrangements and futures
transactions entered into by the Company to hedge production are included in the
foregoing product prices. Such transactions (which do not include fixed price,
physical delivery arrangements) had the effect of decreasing the average price
per BOE by $2.03 and $1.54 in the first half of 1997 and 1996, respectively.

Unit production expenses declined approximately 2% to $5.97  per BOE for the six
months ended June 30, 1997, from the $6.12 per BOE for the 1996 period primarily
due to increased production levels in South Florida.  Unit production expenses
declined slightly in each of the Company's three core areas from the 1996 six
month levels, with the LA Basin averaging $6.21 per BOE, the Sunniland Trend
$3.92 per BOE, and the Illinois Basin $8.47 per BOE.  Total production expenses
increased to $21.0 million from $18.6 million for the first half of 1996
primarily due to the Montebello Acquisition and increased production levels.

Downstream Results

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

<TABLE>
<CAPTION>
                                            SIX MONTHS ENDED
                                                JUNE 30,
                                            ----------------
                                             1997     1996
                                            -------  -------
<S>                                         <C>      <C>
                                             (IN THOUSANDS)
OPERATING RESULTS
   Gross margin...........................   $5,530   $4,451
   G&A expense............................    1,706    1,470
                                             ------   ------
   Gross profit...........................   $3,824   $2,981
                                             ======   ======
 
AVERAGE DAILY VOLUMES
   Crude oil barrels marketed.............       67       56
   Crude oil terminal throughput barrels..       75       55
</TABLE>

Despite significant downward pressure on marketing margins throughout the
industry generally, strength in the Company's storage and terminalling
activities enabled this segment to report a gross margin (marketing,
transportation and storage revenues less purchases, transportation and storage
expenses) of $5.5 million for the first half of 1997, reflecting an approximate
24% increase over the $4.5 million reported for the 1996 period.  Gross revenues
were $343.0 million and $233.6 million for the respective periods. Downstream
G&A expenses increased from $1.5 million to $1.7 million in the current year
period primarily as a result of additional personnel added to further expand
marketing activities.    Total average daily crude oil volumes marketed and
terminalled during the 1997 first half were 67,000 barrels and 75,000 barrels,
respectively.  Such amounts represent respective increases of 20% and 36% as
compared with average daily volumes of 56,000 barrels and 55,000 barrels in last
year's first half.  Gross profit (gross margin less downstream G&A expenses)
increased 28%, totaling $3.8 million versus $3.0 million in first six months of
last year.

A strong backward market for crude oil existed during 1996 and the first quarter
of 1997.  However, during the second quarter of 1997, such market was a flat to
slightly contango market.  Typically, margins for crude oil marketing are
strongest in a backward market.  During a contango market, when marketing
margins are generally smaller, the Company's terminalling and storage operations
at the Cushing Terminal 

                                 Page 14 of 21
<PAGE>
 
typically become more profitable due to (i) the Company's ability to take
delivery on crude oil which is simultaneously purchased and resold at a profit
for delivery in a subsequent month and (ii) the increased demand by third
parties for storage capacity.

General

For the first half of 1997, upstream unit G&A expenses decreased 16% to $.71 per
BOE as compared to $.85 per BOE in last year's first half.  Total G&A expenses,
including downstream activities, were $4.2 million for the six months ended June
30, 1997, compared to $4.0 million for the 1996 period.  The increase is
primarily attributable to increased expenses associated with the Company's
downstream activities.

DD&A expense increased to $11.3 million from $10.4 million reported in the first
half of 1996 due primarily to higher production volumes.  The Company's DD&A
rate was $2.80 and $3.00 per BOE for the six months ended June 30, 1997 and
1996, respectively.  Interest expense for the six months ended June 30, 1997,
increased to $9.9 million from $8.5 million reported for the comparative prior
year period primarily due to higher outstanding debt levels as a result of
capital expenditures related to the Company's acquisition and exploitation
activities.  The effect of higher debt levels was partially offset by a slightly
lower overall average interest rate.  Capitalized interest was $1.5 million and
$1.8 million for the six months ended June 30, 1997 and 1996, respectively.

For the six months ended June 30, 1997, the Company recognized a deferred tax
provision of $4.6 million and a current tax provision of $.2 million. For the
1996 period, the Company recognized a net deferred tax benefit before
extraordinary item of $9.1 million. Such amount consists of a $1.9 million
deferred tax provision on the Company's income before extraordinary item and an
$11 million benefit related to the reversal of a portion of the valuation
reserve against the Company's deferred tax asset. In addition, the Company
reported a $1.9 million deferred tax benefit as an extraordinary item related to
the first quarter 1996 extraordinary loss from the early redemption of the 12%
Notes.

The Company reported primary EPS of $.40 per share and $.42 per share for the
six months ended June 30, 1997 and 1996, respectively.  Under SFAS 128, basic
EPS would have been $.43 per share and $.44 per share for the six months ended
June 30, 1997 and 1996, respectively, and diluted EPS would have been $.40 per
share and $.42 per share for the same respective periods.

In July 1997, the FASB issued Statement of Financial Accounting Standards No.
131 ("SFAS 131"), Disclosures About Segments of an Enterprise and Related
Information, effective for fiscal years beginning after December 15, 1997.  This
statement introduces a new model for segment reporting and applies to public,
for-profit entities.  SFAS 131 requires disclosures for each segment that are
similar to those required under current standards with the addition of quarterly
disclosure requirements and a finer partitioning of geographic disclosures.
Reportable segments are based on products and services, geography, legal
structure, management structure or any manner in which management disaggregates
a company.  This statement replaces the notion of industry and geographic
segments in current FASB standards.  Management is currently evaluating the
impact of this statement on the Company's disclosures.

                                 Page 15 of 21
<PAGE>
 
CAPITAL RESOURCES, LIQUIDITY AND FINANCIAL CONDITION

In March 1997, the Company completed the acquisition of Chevron's interest in
the Montebello Field for $25 million, effective February 1, 1997.  The assets
acquired consist of a 100% working interest and a 99.2% net revenue interest in
55 producing oil wells and related facilities and also include approximately 450
acres of surface fee lands.  At the acquisition date, the Montebello Field,
which is located approximately 15 miles from the Company's existing LA Basin
operations, was producing approximately 800 barrels of oil and 800 Mcf of gas
per day and added approximately 23 million barrels of oil equivalent to the
Company's proved reserves.  The Montebello Acquisition was funded with proceeds
from the Company's revolving credit facility ("Revolving Credit Facility").

In March 1997, the Company's Revolving Credit Facility and borrowing base
thereunder was increased to $165 million from $125 million.  The Revolving
Credit Facility, as amended, converts to a term loan on July 1, 1999, with a
final maturity of July 1, 2004, and bears interest at the option of the Company
at LIBOR plus 1.375% or Base Rate (as defined therein).  The Revolving Credit
Facility is guaranteed by all of the Company's principal subsidiaries and is
secured by the oil and gas properties of the Company and its subsidiaries and
the stock of all subsidiaries.  At June 30, 1997, the Company had approximately
$109 million in borrowings and a $1 million standby letter of credit outstanding
under the Revolving Credit Facility.

On July 23, 1997, the Company sold $50 million of Senior Subordinated Notes due
2006, Series C, bearing a coupon rate of 10.25% (the "Series C 10.25% Notes").
Such notes were issued pursuant to a Rule 144A private placement at
approximately 107.21% of par to yield a minimum yield to worst of 8.79%, or
9.03% yield to maturity.  The stated coupon rate of interest and maturity date
are the same as those of the Company's existing $150 million principal amount of
senior subordinated notes currently outstanding (the "Series A/B 10.25% Notes").
The Series C 10.25% Notes are redeemable, at the option of the Company, on or
after March 15, 2001 at 105.13%, at decreasing prices thereafter prior to March
15, 2004, and thereafter at 100% plus, in each case, accrued interest to the
date of redemption.  In addition, prior to March 15, 1999, up to $15 million in
principal amount of the Series C 10.25% Notes are redeemable at the option of
the Company, in whole or in part, from time to time, at 110.25% of the principal
amount thereof, with the Net Proceeds (as defined in the Indenture) of any
Public Equity Offering (as defined in the Indenture).

Proceeds from the sale of the Series C 10.25% Notes, net of offering costs, were
approximately $53 million and were used to reduce the balance outstanding on the
Revolving Credit Facility.

Plains Marketing and Transportation Inc. ("Plains Marketing ") and PMCT Inc.,
wholly owned subsidiaries of the Company, have a $90 million Transactional
Facility with five banks.  The purpose of the Transactional Facility is to
provide standby letters of credit to support the purchase of crude oil for
resale and borrowings to finance crude oil inventory that has been hedged
against future price risk.  In August 1997, the sublimit for cash borrowings
under the Transactional Facility was increased to $25 million from $20 million.
Letters of credit under the Transactional Facility are generally issued for
seventy-day periods and bear fees of 1 1/8% per annum.  Borrowings incur
interest at the option of the borrower at (i) the Base Rate or (ii) LIBOR plus 
1 1/2%.  At June 30, 1997, approximately $38 million in letters of credit and
$16.5 million in borrowings were outstanding under the Transactional Facility.

At June 30, 1997, the Company had a working capital deficit of approximately
$10.4 million compared to a deficit of $4.8 million at December 31, 1996.  The
Company has historically operated with a working 

                                 Page 16 of 21
<PAGE>
 
capital deficit due primarily to ongoing capital expenditures that have been
financed through cash flow and the Revolving Credit Facility.


INVESTING AND FINANCING ACTIVITIES

Net cash flows used in investing activities were $54.4 million and $20.4 million
for the six months ended June 30, 1997 and 1996, respectively.  Investing
activities include payments for acquisition, exploration and development costs
of $50.8 million and $22.3 million for these same periods, respectively.
Included in the 1997 amount is approximately $25 million related to the
Montebello Acquisition.  Also included in investing activities are proceeds from
the sale of certain nonstrategic properties of $.2 million and $3.1 million for
the six months ended June 30, 1997 and 1996, respectively.

Net cash provided by financing activities amounted to $53.0 million and $1.6
million for the six months ended June 30, 1997 and 1996, respectively.
Approximately $25 million borrowed under the Revolving Credit Facility to fund
the Montebello Acquisition is included in proceeds from long-term debt in 1997.
Financing activities during 1996 include net proceeds of approximately $144.9
million from the sale of the Series A/B 10.25% Notes, approximately $107 million
for the repayment of the 12% Notes, including the 6% call premium and the net
defeasance costs, and approximately $42 million for the repayment of the
acquisition bridge indebtedness incurred to fund the acquisition of the Illinois
Basin properties.  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 during 1997 include proceeds of
$16.5 million from short-term borrowings to finance crude oil inventory
transactions at the Cushing Terminal.  Such borrowings were made under the
Plains Marketing Transactional Facility and all inventory acquired has been
hedged against price risk.

CHANGING OIL AND NATURAL GAS PRICES

The Company is heavily dependent on 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, future crude
oil price declines would have a negative impact on 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.
For the second half of 1997, the Company has entered into various fixed price
and floating price collar arrangements.  Such arrangements generally provide the
Company with downside price protection on approximately 14,000 barrels of oil
per day at a NYMEX benchmark price of approximately $19.25 per barrel, but
permit the Company to receive the benefit of increases in the NYMEX benchmark
price up to $24.00 per barrel on 4,000 of such barrels.  Thus based on the
Company's average second quarter 1997 oil production rate, these arrangements
generally provide the Company with downside price protection for 75% of its
production and upside price participation for 46% of its production up to $24.00
per barrel, while 25% of such production and excess volumes, if any, remain
unhedged.  In addition, the Company also has fixed price arrangements on
approximately 12,000 barrels per day for 1998 at a NYMEX benchmark price of
$19.80 per barrel.  The hedge prices are before deductions for quality and area
differentials.

FORWARD-LOOKING STATEMENTS AND ASSOCIATED RISKS

All statements, other than statements of historical facts, included in the
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 

                                 Page 17 of 21
<PAGE>
 
in estimating oil and gas reserves and other factors discussed in the Company's
Annual Report on Form 10-K for the year ended December 31, 1996.

                                 Page 18 of 21
<PAGE>
 
PART II.  OTHER INFORMATION

Item 1 - Legal Proceedings

As discussed in prior reports, since the Company acquired its South Florida
Sunniland Trend properties in 1993, substantially all crude oil production
therefrom had been transported by a third party pipeline company.  Despite
lengthy negotiations with the pipeline company to extend or modify the
transportation agreement, such agreement expired on June 30, 1997.  As a
safeguard against the failure to reach an agreement with the pipeline company
for the extension or modification of the transportation agreement, the Company
reached an agreement with the Miccosukee Tribe of Indians of Florida for an
amended lease (which has been approved by the Bureau of Indian Affairs) on which
the Company constructed facilities to transport its crude oil production by
trucks.  Upon termination of the pipeline transportation agreement on June
30,1997, the Company commenced transporting its Sunniland Trend crude oil
production by trucks at an average rate which is approximately $0.25 per barrel
lower than the rate at which it was previously paying to transport such
production by pipeline.


Item 2 - Material Modification of Rights of Registrant's Securities

None


Item 3 - Defaults on Senior Securities

None


Item 4 - Submission of Matters to a Vote of Security Holders

The 1997 Annual Meeting of Stockholders (the "Meeting") of the Company was held
on May 22, 1997.  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 16,538,649 shares of Common Stock entitled to vote at the Meeting,
there were 13,848,742 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 L. Armstrong                13,821,063    27,679
Jerry L. Dees                    13,823,441    25,301
Tom H. Delimitros                13,823,474    25,268
William H. Hitchcock             13,822,474    26,268
Dan M. Krausse                   13,823,474    25,268
John H. Lollar                   13,823,474    25,268
Robert V. Sinnott                13,823,474    25,268
J. Taft Symonds                  13,823,474    25,268
</TABLE>

                                 Page 19 of 21
<PAGE>
 
Item 5 - Other Information

None


Item 6 -

 A. Exhibits

     4     Indenture dated as of July 21, 1997, among the Company, the
           Subsidiary Guarantors named therein and Texas Commerce Bank National
           Association, as Trustee.

    10(a)  Third Amendment to the Third Amended and Restated Credit Agreement
           dated as of July 18, 1997, among the Company and ING (U.S.) Capital
           Corporation, et. al.

    10(b)  Second Amendment to the Company's 1992 Stock Incentive Plan.

    11(a)  Computation of per share earnings for the three months ended June 30,
           1997 and 1996

    11(b)  Computation of per share earnings for the six months ended June 30,
           1997 and 1996

    27.    Financial Data Schedule

 B. Report on Form 8-K

    None

                                 Page 20 of 21
<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 12, 1997            By: /s/  Cynthia A. Feeback
                                    --------------------------------------
                                    Cynthia A. Feeback, Controller and
                                    Principal Accounting Officer
                                    (Principal Accounting Officer)

                                 Page 21 of 21