AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON JUNE 21, 2002.

REGISTRATION NO. 333-


SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

FORM S-1
REGISTRATION STATEMENT UNDER THE SECURITIES ACT OF 1933

PLAINS EXPLORATION & PRODUCTION COMPANY, L.P.(1)
(Exact name of registrant as specified in its charter)

          DELAWARE(1)                            1311                            33-0430755
(State or other jurisdiction of      (Primary Standard Industrial             (I.R.S. Employer
 incorporation or organization)      Classification Code Number)            Identification No.)

500 DALLAS STREET
HOUSTON, TEXAS 77002
(713) 654-1414

(Address, including zip code, and telephone number, including area code, of registrant's principal executive offices)

TIMOTHY T. STEPHENS

EXECUTIVE VICE PRESIDENT OF ADMINISTRATION, SECRETARY AND GENERAL COUNSEL

500 DALLAS STREET
HOUSTON, TEXAS 77002

TELEPHONE: (713) 739-6700 (Name, address, including zip code, and telephone number, including area code, of agent for service)

COPIES TO:

        MICHAEL E. DILLARD, P.C.                              GARY L. SELLERS, ESQ.
         JULIEN R. SMYTHE, ESQ.                            SIMPSON THACHER & BARTLETT
         RICHARD J. WILKIE, ESQ.                              425 LEXINGTON AVENUE
AKIN, GUMP, STRAUSS, HAUER & FELD, L.L.P.                   NEW YORK, NEW YORK 10017
 711 LOUISIANA STREET, SUITE 1900-SOUTH                     TELEPHONE: (212) 455-2000
          HOUSTON, TEXAS 77002
        TELEPHONE: (713) 220-5800

Approximate date of commencement of proposed sale to the public: AS SOON AS
PRACTICABLE AFTER THE EFFECTIVE DATE OF THIS REGISTRATION STATEMENT.

If any of the securities being registered on this form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box: [ ]

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

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

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

If delivery of the prospectus is expected to be made pursuant to Rule 434, check the following box. [ ]

CALCULATION OF REGISTRATION FEE

------------------------------------------------------------------------------------------------------------------
------------------------------------------------------------------------------------------------------------------
                 TITLE OF EACH CLASS OF                        PROPOSED MAXIMUM
              SECURITIES TO BE REGISTERED                AGGREGATE OFFERING PRICE(2)   AMOUNT OF REGISTRATION FEE
------------------------------------------------------------------------------------------------------------------
Common stock, par value $0.01 per share.................         $100,000,000                    $9,200
------------------------------------------------------------------------------------------------------------------
------------------------------------------------------------------------------------------------------------------

(1) The registrant is currently a California limited partnership named "Plains Exploration & Production Company, L.P." which on or prior to the effective date of this registration statement will convert to a Delaware corporation named "Plains Exploration & Production Company."

(2) Estimated solely for the purpose of computing the amount of the registration fee pursuant to Rule 457(o).

THE REGISTRANT HEREBY AMENDS THIS REGISTRATION STATEMENT ON SUCH DATE OR DATES AS MAY BE NECESSARY TO DELAY ITS EFFECTIVE DATE UNTIL THE REGISTRANT SHALL FILE A FURTHER AMENDMENT WHICH SPECIFICALLY STATES THAT THIS REGISTRATION STATEMENT SHALL THEREAFTER BECOME EFFECTIVE IN ACCORDANCE WITH SECTION 8(a) OF THE SECURITIES ACT OF 1933, OR UNTIL THE REGISTRATION STATEMENT SHALL BECOME EFFECTIVE ON SUCH DATE AS THE COMMISSION, ACTING PURSUANT TO SAID SECTION 8(a), MAY DETERMINE.



The information in this preliminary prospectus is not complete and may be changed. These securities may not be sold until the registration statement filed with the Securities and Exchange Commission is effective. This preliminary prospectus is not an offer to sell these securities nor does it seek an offer to buy these securities in any jurisdiction where the offer or sale is not permitted.

Subject to Completion. Dated June 21, 2002.

Shares

PLAINS EXPLORATION & PRODUCTION COMPANY

Common Stock

This is an initial public offering of shares of common stock of Plains Exploration & Production Company. All of the shares of common stock are being sold by Plains Exploration & Production Company.

Prior to this offering, there has been no public market for the common stock. Plains Exploration & Production Company intends to list the common stock on the New York Stock Exchange under the symbol "PXP".

Upon completion of this offering, Plains Resources will own shares representing approximately % of our common stock, or approximately % if the underwriters exercise their option to purchase additional shares of common stock in full, and will effectively control all matters put to a vote of our stockholders. See "Description of Capital Stock" on page 60.

See "Risk Factors" beginning on page 9 to read about certain factors you should consider before buying shares of the common stock.


NEITHER THE SECURITIES AND EXCHANGE COMMISSION NOR ANY OTHER REGULATORY BODY HAS APPROVED OR DISAPPROVED OF THESE SECURITIES OR PASSED UPON THE ACCURACY OR ADEQUACY OF THIS PROSPECTUS. ANY REPRESENTATION TO THE CONTRARY IS A CRIMINAL OFFENSE.


                                                              Per Share    Total
                                                              ---------    -----
Initial public offering price...............................  $           $
Underwriting discount.......................................  $           $
Proceeds, before expenses, to Plains Exploration &
  Production Company........................................  $           $

To the extent that the underwriters sell more than shares of common stock, the underwriters have the option to purchase up to an additional shares from Plains Exploration & Production Company at the initial public offering price less the underwriting discount.


The underwriters expect to deliver the shares against payment in New York, New York on , 2002.

GOLDMAN, SACHS & CO.

Prospectus dated , 2002.


SUMMARY

This summary highlights information contained elsewhere in this prospectus. This summary does not contain all of the information you should consider before investing in the common stock. You should read this entire prospectus carefully, especially the risks of investing in the common stock discussed under "Risk Factors" beginning on page 9 and the historical combined financial statements and notes included in this prospectus, before making an investment decision. In this prospectus, the terms "Plains Exploration & Production", "we", "us" and "our" refer to Plains Exploration & Production Company, its predecessor and subsidiaries, unless otherwise stated or the context requires. Although we are currently a California limited partnership named "Plains Exploration & Production Company, L.P.", we will convert into a Delaware corporation named "Plains Exploration & Production Company" prior to the completion of this offering. Our discussion in this prospectus assumes we have completed this conversion and changed our name.

OUR COMPANY

We are an independent oil and gas company primarily engaged in the upstream activities of acquiring, exploiting, developing and producing oil and gas in the United States. We are 100% owned by Plains Resources Inc. Our core areas of operation are:

- onshore California, primarily in the Los Angeles Basin, and offshore California in the Point Arguello unit; and

- the Illinois Basin in southern Illinois.

We own a 100% working interest in and operate all of our properties, except for offshore California, in which we own a 26.3% working interest and where we are the operator. Our reserves are generally mature but underdeveloped, have produced significant volumes since initial discovery and have significant estimated remaining reserves. We opportunistically hedge portions of our oil production to manage our exposure to commodity price risk. For the twelve months ended March 31, 2002 we generated revenues of $191.0 million and EBITDA, as defined, of $118.0 million.

The following table sets forth information with respect to our oil and gas properties as of and for the year ended December 31, 2001:

                                                     CALIFORNIA          ILLINOIS
                                                --------------------    BASIN AND
                                                 ONSHORE    OFFSHORE      OTHER       TOTAL
                                                ---------   --------   ------------   ------
                                                           (DOLLARS IN MILLIONS)
Proved reserves
  MMBOE.......................................      211.8(1)     5.0        22.5       239.3
  Percent oil.................................        93%       98%          98%         93%
Proved developed reserves (MMBOE).............      112.0       3.8         13.3       129.1
Production (MBOE).............................      6,347     1,431        1,000       8,778
PV-10(2)......................................  $   577.7    $  6.9       $ 58.6      $643.2


(1) Approximately 8.8 MMBOE of our proved reserves in the Los Angeles Basin properties are subject to a 50% net profits interest.

(2) Based on year-end 2001 spot market prices of $19.84 per Bbl of oil and $2.58 per Mcf of gas. We have reduced the PV-10 of proved reserves of certain properties to reflect applicable abandonment costs and, with respect to the Los Angeles Basin properties, the net profits interest referenced in note 1.

During the five-year period ended December 31, 2001 we drilled 561 development wells with a 99.5% success rate. During this period, we incurred aggregate oil and gas acquisition, exploitation, development and exploration costs of $442.9 million, resulting in proved reserve

1

additions of 177.9 MMBOE, at an average reserve replacement cost of $2.49 per BOE, which we believe to be among the lowest of our peer group. Approximately 99% of our oil and gas capital expenditures was for acquisition, exploitation and development activities.

OUR COMPETITIVE STRENGTHS

QUALITY ASSET BASE WITH LONG RESERVE LIFE. We had estimated total proved reserves of 239.3 MMBOE as of December 31, 2001, of which 93% was comprised of oil and 54% was proved developed. We have a reserve life of over 27 years and a proved developed reserve life of over 14 years. We believe our long-lived, low production decline reserve base combined with our active hedging strategy should provide us with relatively stable and recurring cash flow. As of December 31, 2001 and based on year-end 2001 spot market prices of $19.84 per Bbl of oil and $2.58 per Mcf of gas, our reserves had a PV-10 of $643.2 million.

EFFICIENT OPERATIONS WITH 100% OPERATORSHIP. We own a 100% working interest in and operate all of our properties, except for offshore California, in which we own a 26.3% working interest and where we are the operator. As a result, we benefit from economies of scale and control the level, timing and allocation of substantially all of our capital expenditures and expenses. We believe this gives us more flexibility than many of our peers to opportunistically pursue exploitation and development projects relating to our properties.

LARGE EXPLOITATION AND DEVELOPMENT INVENTORY. We have a large inventory of projects in our core areas that we believe will support at least five years of exploitation and development activity. Over the last five years, we have achieved a high success rate on these types of projects, drilling a total of 561 development wells with a 99.5% success rate. In addition, we have completed numerous other production enhancement projects, such as recompletions, workovers and upgrades. The results of these activities over the last five years have been additions to proved reserves, excluding reserves added through acquisition activities, totaling 120.6 MMBOE, or approximately 332% of cumulative net production for this period. Reserve replacement costs, excluding acquisitions, have averaged approximately $3.17 per BOE for the same period.

EXPERIENCED AND PROVEN MANAGEMENT AND OPERATIONS TEAM. Our executive management team has an average of 20 years of experience in the oil and gas industry. The Chief Executive Officer of our parent, Plains Resources, is James Flores, who founded Flores & Rucks Incorporated, a predecessor of Ocean Energy, Inc., and was President and Chief Executive Officer of Ocean Energy from July 1995 until March 1999. Mr. Flores served as Chairman of the Board of Ocean Energy from March 1999 until January 2000, and as Vice Chairman from January 2000 until January 2001. The executive management of Plains Resources is supported by a core team of 23 technical and operating managers who have worked with our properties for many years and have an average of 22 years of experience in the oil and gas industry.

STRATEGY

Our strategy is to continue to grow our cash flow from operations and to use this cash flow to increase our proved developed reserves and production, acquire additional underdeveloped oil and gas properties and make other strategic acquisitions. We intend to implement our strategy as follows:

CONTINUE EXPLOITATION AND DEVELOPMENT OF CURRENT ASSET BASE. We believe that we have a proven track record of exploiting underdeveloped properties to increase reserves and cash flow. We focus on implementing improved production practices and recovery techniques, and relatively low-risk development drilling. An example of our success in exploiting underdeveloped properties can be found in our Montebello field located in the Los Angeles, or LA, Basin. Since our acquisition of this field in March 1997, our exploitation and development activities have resulted in an increase in our net average production from approximately 930 BOE per day at the time of

2

acquisition to approximately 2,400 BOE per day during the first quarter of 2002, representing a compound annual growth rate of over 20%.

PURSUE ADDITIONAL GROWTH OPPORTUNITIES. We believe we can continue our strong reserve and production growth through the exploitation and development of our existing inventory of projects relating to our properties. We also intend to be opportunistic in pursuing selective acquisitions of oil or gas properties or exploration projects, for example, during periods of weak commodity prices. We will consider opportunities located in our current core areas of operation as well as projects in other areas in North America that meet our investment criteria.

MAINTAIN LONG-TERM HEDGING PROGRAM. We actively manage our exposure to commodity price fluctuations by hedging significant portions of our oil production through the use of swaps, collars and purchased puts and calls. The level of our hedging activity depends on our view of market conditions, available hedge prices and our operating strategy. Under our hedging program, we typically hedge approximately 70-75% of our production for the current year, 40- 50% of our production for the next year and up to 25% of our production for the following year. For example, as of March 31, 2002 we had hedged approximately 80% of forecasted production for the remainder of 2002 and approximately 50% of forecasted production for 2003.

RECENT DEVELOPMENTS

Our parent is Plains Resources Inc., which, in addition to owning us, owns an aggregate 29% ownership interest in Plains All American Pipeline, L.P., or PAA, including 44% of the general partner of PAA. PAA is a publicly traded master limited partnership that is engaged in the midstream activities of marketing, transportation and terminalling of oil and marketing liquified petroleum gas. Plains Resources also owns interests in oil and gas properties in Florida, which included 17.3 MMBOE of proved oil reserves as of December 31, 2001.

On May 22, 2002 Plains Resources received a favorable private letter ruling from the Internal Revenue Service, or IRS, stating that, for United States federal income tax purposes, a distribution by Plains Resources of the Plains Exploration & Production capital stock owned by it to its stockholders will generally be tax-free to both Plains Resources and its stockholders. We call this proposed distribution the "spin-off". Prior to completing the spin-off, we intend to seek a supplemental private letter ruling from the IRS that this offering will not affect our earlier ruling. If we complete this offering, we expect the spin-off will occur within the following twelve months. If we do not complete this offering, Plains Resources may still decide to proceed with the spin-off.

The spin-off will, among other things:

- generally divide Plains Resources' midstream and upstream assets into two separate platforms;

- allow Plains Resources and us to focus corporate strategies and management teams for each business; and

- simplify Plains Resources' and our corporate structure.

Any decision to pursue the spin-off is subject to obtaining a number of regulatory and contractual third-party consents and permits, including a supplemental private letter ruling from the IRS. Accordingly, we cannot provide any assurance that the spin-off will occur.

Plains Resources will contribute to us all of the capital stock of its subsidiaries that own oil and gas properties offshore California and in Illinois. As a result, we will indirectly own our offshore California and Illinois properties in addition to our onshore California properties that we directly own. Plains Resources and its management will continue to manage our operations under the terms of a transition services agreement. If we complete a debt financing of approximately $250.0 million, Plains Resources will also contribute to us intercompany payables that we or our

3

subsidiaries owe to it, which were $249.6 million as of March 31, 2002. We call this series of transactions our "reorganization".

Although Plains Resources has historically owned and operated the offshore California and Illinois properties through subsidiaries, our discussion in this prospectus assumes we owned and operated these properties since the time Plains Resources acquired them. For example, if Plains Resources through our subsidiaries drilled a well in 1999 on an Illinois property, in this prospectus we will state that we drilled the well in 1999.

OUR EXECUTIVE OFFICES

Our principal executive offices are located at 500 Dallas Street, Houston Texas 77002, and our telephone number at that address is (713) 739-6700.

4

THE OFFERING

The following information assumes that the underwriters do not exercise the option we granted them to purchase additional shares of common stock in this offering.

Shares offered.......................                      shares

Shares to be outstanding after this
offering.............................                      shares

Shares to be held by Plains Resources
after the offering...................                      shares

Use of proceeds......................       We estimate that the proceeds from
                                            this offering will be approximately
                                            $      , after deducting fees and
                                            estimated expenses. We intend to use
                                            a portion of these net proceeds to
                                            repay amounts outstanding under our
                                            revolving credit facility. We intend
                                            to use the excess net proceeds and
                                            the borrowing capacity under our
                                            credit facility, together with
                                            internally generated cash flow, to
                                            pursue development, exploitation and
                                            acquisition activities, and for
                                            general corporate purposes.

Proposed New York Stock Exchange
symbol...............................       PXP

5

SUMMARY FINANCIAL INFORMATION

The following table sets forth our summary combined historical financial information that has been derived from (i) the audited combined statements of income and cash flows for our business for each of the years ended December 31, 2001, 2000 and 1999, (ii) the unaudited combined statements of income and cash flows for our business for the three months ended March 31, 2002 and 2001 and the twelve months ended March 31, 2002 and (iii) our unaudited combined balance sheets as of March 31, 2002 and 2001. As adjusted data gives effect to this offering and the application of the net proceeds. You should read this financial information in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations" and our historical combined financial statements and notes included elsewhere in this prospectus. The information set forth below is not necessarily indicative of our future results.

                                                  TWELVE
                                                  MONTHS     THREE MONTHS ENDED
                                                   ENDED          MARCH 31,           YEAR ENDED DECEMBER 31,
                                                 MARCH 31,   -------------------   ------------------------------
                                                   2002        2002       2001       2001       2000       1999
                                                 ---------   --------   --------   --------   --------   --------
                                                          (DOLLARS IN THOUSANDS, EXCEPT PER SHARE DATA)
STATEMENT OF INCOME DATA:
Revenues:
  Oil and liquids..............................  $170,979    $ 38,685   $ 42,601   $174,895   $126,434   $102,390
  Gas..........................................    19,587       1,988     11,172     28,771     16,017      5,095
  Other operating revenues.....................       473          --         --        473         --         --
                                                 --------    --------   --------   --------   --------   --------
                                                  191,039      40,673     53,773    204,139    142,451    107,485
                                                 --------    --------   --------   --------   --------   --------
Costs and expenses:
  Production expenses..........................    67,654      17,229     13,370     63,795     56,228     50,527
  General and administrative(1)................     9,876       2,452      2,786     10,210      6,308      4,367
  Depreciation, depletion and amortization.....    25,432       6,691      5,364     24,105     18,859     13,329
                                                 --------    --------   --------   --------   --------   --------
                                                  102,962      26,372     21,520     98,110     81,395     68,223
                                                 --------    --------   --------   --------   --------   --------
Income from operations.........................    88,077      14,301     32,253    106,029     61,056     39,262
Other income (expense)
  Interest expense.............................   (17,912)     (4,692)    (4,191)   (17,411)   (15,885)   (14,912)
  Interest and other (expense) income..........       (77)         18        558        463        343         87
                                                 --------    --------   --------   --------   --------   --------
Income before income taxes and cumulative
  effect of accounting change..................    70,088       9,627     28,620     89,081     45,514     24,437
Income tax expense:
  Current......................................    (6,127)     (2,045)    (1,932)    (6,014)    (2,431)      (505)
  Deferred.....................................   (20,977)     (1,718)    (9,115)   (28,374)   (14,334)    (4,827)
                                                 --------    --------   --------   --------   --------   --------
Income before cumulative effect of accounting
  change.......................................    42,984       5,864     17,573     54,693     28,749     19,105
Cumulative effect of accounting change, net of
  tax benefit..................................        --          --     (1,522)    (1,522)        --         --
                                                 --------    --------   --------   --------   --------   --------
Net income.....................................  $ 42,984    $  5,864   $ 16,051   $ 53,171   $ 28,749   $ 19,105
                                                 ========    ========   ========   ========   ========   ========
Net income per common share:
  Basic........................................  $           $          $          $          $          $
  Diluted......................................
Weighted average common shares outstanding:
  Basic........................................
  Diluted......................................
OTHER FINANCIAL DATA:
EBITDA(2)......................................  $117,986    $ 21,343   $ 39,277   $135,920   $ 80,786   $ 52,591
Net cash provided by operating activities......    92,598       9,538     35,958    119,018     79,464      4,609
Net cash used in investing activities..........   122,867      23,961     26,974    125,880     70,871     59,362
Net cash provided by (used in) financing
  activities...................................    29,150      14,411     (8,400)     6,339    (13,132)    59,690
Oil and gas capital expenditures...............   122,806      23,941     26,888    125,753     70,505     59,167

(footnotes on following page)

6

                                                                   AS OF MARCH 31, 2002
                                                              ------------------------------
                                                                ACTUAL        AS ADJUSTED
                                                              -----------   ----------------
BALANCE SHEET DATA:
Cash and cash equivalents...................................    $     1         $
Working capital.............................................    (24,048)
Total assets................................................    508,354
Total debt..................................................    251,105
Stockholder's equity........................................    162,773


(1) General and administrative expenses consist of our direct expenses plus amounts allocated from Plains Resources for various operational, financial, accounting and administrative services provided to us. We estimate that our annual general and administrative expenses will increase by approximately $3.5 million under the terms of the transition services agreement we entered into with Plains Resources in connection with the reorganization.

(2) EBITDA means earnings before interest, taxes, depreciation, depletion, amortization, noncash compensation expense, interest and other income and amortization of hedge option premiums. EBITDA is not a measurement presented in accordance with generally accepted accounting principles, or GAAP, and is not intended to be used in lieu of GAAP presentations of results of operations and cash provided by operating activities. EBITDA is commonly used by debt holders and financial statement users as a measurement to determine the ability of an entity to meet its interest obligations. EBITDA is calculated as follows:

                                    TWELVE MONTHS     THREE MONTHS
                                        ENDED        ENDED MARCH 31,      YEAR ENDED DECEMBER 31,
                                      MARCH 31,     -----------------   ----------------------------
                                        2002         2002      2001       2001      2000      1999
                                    -------------   -------   -------   --------   -------   -------
                                                         (DOLLARS IN THOUSANDS)
Income before income taxes and
  cumulative effect of accounting
  change..........................    $ 70,088      $ 9,627   $28,620   $ 89,081   $45,514   $24,437
Interest and other income
  (expense).......................          77          (18)     (558)      (463)     (343)      (87)
Interest expense..................      17,912        4,692     4,191     17,411    15,885    14,912
Depreciation, depletion and
  amortization....................      25,432        6,691     5,364     24,105    18,859    13,329
Noncash compensation..............       2,826          209         2      2,619        --        --
Amortization of hedge premiums....       1,651          142     1,658      3,167       871        --
                                      --------      -------   -------   --------   -------   -------
EBITDA............................    $117,986      $21,343   $39,277   $135,920   $80,786   $52,591
                                      ========      =======   =======   ========   =======   =======

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SUMMARY RESERVE AND PRODUCTION DATA

The following table sets forth certain of our combined historical reserve and operating data. You should read the historical data in conjunction with our historical combined financial statements and notes included elsewhere in this prospectus. The information set forth below is not necessarily indicative of our future results.

                                     THREE MONTHS
                                         ENDED
                                       MARCH 31,             YEAR ENDED DECEMBER 31,
                                  -------------------   ----------------------------------
                                    2002       2001       2001        2000         1999
                                    ----       ----       ----        ----         ----
                                      (DOLLARS IN THOUSANDS, EXCEPT PER UNIT AMOUNTS)
ESTIMATED PROVED RESERVES (AT
  END OF PERIOD):
  Oil (MBbl)(1).................                         223,293      204,387      195,213
  Gas(MMcf).....................                          96,217       93,486       90,873
          Total (MBOE)..........                         239,329      219,968      210,359
Percent oil.....................                             93%          93%          93%
Percent proved developed........                             54%          52%          52%
PV-10 (AT END OF PERIOD) (2)....                        $643,220   $1,304,182   $1,106,358
RESERVE ADDITIONS (MBOE)........                          28,140       17,770       92,554
RESERVE LIFE (YEARS)............                            27.3         27.0         27.6
PRODUCTION:
  Oil (MBbl)(1).................     2,033      1,920      8,219        7,654        7,081
  Gas (MMcf)....................       877        745      3,355        3,042        3,163
          Total (MBOE)..........     2,179      2,044      8,778        8,161        7,608
COSTS INCURRED:
  Exploitation and
     development................  $ 23,066   $ 25,981   $123,778   $   68,186   $   54,996
  Exploration...................        --         11        286          293          796
  Acquisition...................       875        896      1,689        2,026        3,375
          Total costs
            incurred............    23,941     26,888    125,753       70,505       59,167
RESERVE REPLACEMENT COST PER
  BOE...........................                        $   4.47   $     3.97   $     0.64
RESERVE REPLACEMENT RATIO.......                            321%         218%       1,216%
AVERAGE SALES PRICE PER UNIT:
  Oil ($/Bbl)...................  $  19.03   $  22.19   $  21.28   $    16.52   $    14.46
  Gas ($/Mcf)...................      2.27      15.00       8.58         5.26         1.61
  BOE...........................     18.67      26.31      23.20        17.46        14.13
EXPENSE PER BOE:
  Production expenses...........  $   7.91   $   6.54   $   7.27   $     6.89   $     6.64
  General and
     administrative(3)..........      1.03       1.36       0.86         0.77         0.57


(1) Includes natural gas liquids and condensate.

(2) Based on year-end spot market prices of: (a) $19.84 per Bbl of oil and $2.58 per Mcf of gas for 2001; (b) $26.80 per Bbl of oil and $13.70 per Mcf of gas for 2000; and (c) $25.60 per Bbl of oil and $2.37 per Mcf of gas for 1999.

(3) Excludes noncash compensation.

8

RISK FACTORS

You should carefully consider the risks described below and all other information contained in this prospectus before making an investment decision. If any of the following risks actually occur, our business could be harmed, the trading price of our common stock could decline and you may lose all or part of your investment.

RISKS RELATING TO OUR BUSINESS

VOLATILE OIL AND GAS PRICES COULD ADVERSELY AFFECT OUR FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

Our success is largely dependent on oil and gas prices, which are extremely volatile for both seasonal and cyclical reasons. Any substantial or extended decline in the price of oil and gas below current levels will have a material adverse effect on our business operations and future revenues. Moreover, oil and gas prices depend on factors we cannot control, such as:

- supply and demand for oil and gas and expectations regarding supply and demand;

- weather;

- actions by the Organization of Petroleum Exporting Countries, or OPEC;

- political conditions in other oil-producing and gas-producing countries;

- general economic conditions in the United States and worldwide; and

- governmental regulations.

With respect to our business, prices of oil and gas will affect:

- our revenues, cash flows and earnings;

- our ability to attract capital to finance our operations and the cost of such capital;

- the amount that we are allowed to borrow; and

- the value of our oil and gas properties.

ANY PROLONGED, SUBSTANTIAL REDUCTION IN THE DEMAND FOR OIL AND GAS, OR DISTRIBUTION PROBLEMS IN MEETING THIS DEMAND, COULD ADVERSELY AFFECT OUR BUSINESS.

Our success is materially dependent upon the demand for oil and gas. The availability of a ready market for our oil and gas production depends on a number of factors beyond our control, including the demand for and supply of oil and gas, the availability of alternative energy sources, the proximity of reserves to, and the capacity of, oil and gas gathering systems, pipelines or trucking and terminal facilities. If there is no market for the oil and gas which we produce, we will be unable to sell it. We may also have to shut-in some of our wells temporarily due to a lack of market. If the demand for oil and gas diminishes, our financial results would be negatively impacted.

In addition, there are limited methods of transportation for our production. Substantially all of our oil and gas production is transported by pipelines, trucks and barges owned by third parties. The inability or unwillingness of these parties to provide transportation services to us for a reasonable fee could result in our having to find transportation alternatives, increased transportation costs or involuntary curtailment of a significant portion of our oil and gas production, any of which could have a negative impact on our results of operation and cash flows.

9

OUR EQUITY OIL PRODUCTION IS DEDICATED TO A SINGLE CUSTOMER AND, AS A RESULT, OUR CREDIT EXPOSURE TO THAT CUSTOMER IS SIGNIFICANT.

We have entered into an oil marketing agreement with PAA, an affiliate of both ours and Plains Resources, under which PAA is the exclusive purchaser of all of our equity oil production. We generally do not require letters of credit or other collateral from PAA to support our trade receivables. Accordingly, a material adverse change in PAA's financial condition could adversely impact our ability to collect our receivables from PAA and thereby affect our financial condition.

IF WE ARE UNABLE TO REPLACE THE RESERVES THAT WE HAVE PRODUCED, OUR RESERVES AND REVENUES WILL DECLINE.

Our future success depends on our ability to find, develop and acquire additional oil and gas reserves that are economically recoverable which, in itself, is dependent on oil and gas prices. Without continued successful exploitation, acquisition or exploration activities, our reserves and revenues will decline as a result of our current reserves being depleted by production. We cannot assure you that we will be able to find or acquire additional reserves at acceptable costs.

WE MAY NOT BE SUCCESSFUL IN ACQUIRING, EXPLOITING, DEVELOPING OR EXPLORING FOR OIL AND GAS PROPERTIES.

The successful acquisition, exploitation or development of or exploration for oil and gas properties requires an assessment of recoverable reserves, future oil and gas prices and operating costs, potential environmental and other liabilities, and other factors. These assessments are necessarily inexact. As a result, we may not recover the purchase price of a property from the sale of production from the property, or may not recognize an acceptable return from properties we do acquire. In addition, we cannot assure you that our exploitation and development operations will result in any increases in reserves. Our operations may be curtailed, delayed or canceled as a result of:

- inadequate capital or other factors, such as title problems;

- weather;

- compliance with governmental regulations or price controls;

- mechanical difficulties; or

- shortages or delays in the delivery of equipment.

In addition, exploitation and development costs may greatly exceed initial estimates. In that case, we will be required to make unanticipated expenditures of additional funds to develop these projects, which could materially adversely affect our business, financial condition and results of operations.

In the future, we may focus on exploration opportunities onshore and offshore. Exploration for oil and gas has inherent and historically high risk. Exploration may involve unprofitable efforts, not only with respect to dry wells, but also with respect to wells that are productive but do not produce sufficient net revenues to return a profit after drilling, operating and other costs. Future reserve increases and production may be dependent on our success in these exploration efforts and no assurances can be given of such success.

ESTIMATES OF OIL AND GAS RESERVES MAY BE UNRELIABLE.

The proved oil and gas reserve information included in this prospectus represents only estimates. These estimates are based on reports prepared by independent petroleum engineers. The estimates were calculated using oil and gas prices in effect on the date indicated in the

10

reports. Any significant price changes will have a material effect on the present value of our reserves.

Petroleum engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact manner. Estimates of economically recoverable oil and gas reserves and of future net cash flows depend upon a number of variable factors and assumptions, including:

- historical production from the area compared with production from other comparable producing areas;

- the assumed effects of regulations by governmental agencies;

- assumptions concerning future oil and gas prices; and

- assumptions concerning future operating costs, severance and excise taxes, development costs and workover and remedial costs.

Because all reserve estimates are to some degree subjective, each of the following items may differ materially from those assumed in estimating reserves:

- the quantities of oil and gas that are ultimately recovered;

- the timing of the recovery of oil and gas reserves;

- the production and operating costs incurred; and

- the amount and timing of future development expenditures.

Furthermore, different reserve engineers may make different estimates of reserves and cash flows based on the same available data. Actual production, revenues and expenditures with respect to reserves will vary from estimates and the variances may be material.

The discounted future net revenues included in this prospectus should not be considered as the market value of the reserves attributable to our properties. As required by the SEC, the estimated discounted future net revenues from proved reserves are generally based on prices and costs as of the date of the estimate, while actual future prices and costs may be materially higher or lower. Actual future net revenues will also be affected by factors such as:

- the amount and timing of actual production;

- supply and demand for oil and gas; and

- changes in governmental regulations or taxation.

In addition, the 10% discount factor, which the SEC requires to be used to calculate discounted future net revenues for reporting purposes, is not necessarily the most appropriate discount factor based on the cost of capital in effect from time to time and risks associated with our business and the oil and gas industry in general.

OPERATING HAZARDS, NATURAL DISASTERS OR OTHER INTERRUPTIONS OF OUR OPERATIONS COULD RESULT IN POTENTIAL LIABILITIES, WHICH MAY NOT BE FULLY COVERED BY OUR INSURANCE.

The oil and gas business involves certain operating hazards such as:

- well blowouts;

- cratering;

- explosions;

- uncontrollable flows of oil, gas or well fluids;

- fires;

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- pollution; and

- releases of toxic gas.

In addition, our operations in California are especially susceptible to damage from natural disasters such as earthquakes and fires and involve increased risks of personal injury, property damage and marketing interruptions because of the population density of southern California. Any of these operating hazards could cause serious injuries, fatalities or property damage, which could expose us to liabilities. The payment of any of these liabilities could reduce, or even eliminate, the funds available for exploration, development, and acquisition, or could result in a loss of our properties.

Consistent with insurance coverage generally available to the industry, our insurance policies provide limited coverage for losses or liabilities relating to pollution, with broader coverage for sudden and accidental occurrences. Although we maintain insurance against some of these operating risks, our insurance might be inadequate to cover our liabilities. For example, we are not fully insured against earthquake risk in California because of high premium costs. We cannot assure you that insurance covering earthquakes or other risks will be available at premium levels that justify its purchase in the future, if at all. The insurance market in general and the energy insurance market in particular has been a difficult market over the past several years. Upon renewal in June 2002, our cost of insurance increased substantially over the prior year's amount. In addition, we increased deductibles and decreased or eliminated certain types of coverages to mitigate the cost increase. Insurance costs are expected to continue to increase over the next few years and we may decrease coverage and retain more risk to mitigate future cost increases. If we incur substantial liability and the damages are not covered by insurance or are in excess of policy limits, or if we incur liability at a time when we are not able to obtain liability insurance, then our business, results of operations and financial condition could be materially adversely affected.

GOVERNMENTAL AGENCIES AND OTHER BODIES, INCLUDING THOSE IN CALIFORNIA, MIGHT IMPOSE REGULATIONS THAT INCREASE OUR COSTS AND MAY TERMINATE OR SUSPEND OUR OPERATIONS.

Our business is subject to federal, state and local laws and regulations as interpreted by governmental agencies and other bodies, including those in California, vested with such authority relating to the exploration for, and the development, production and transportation of, oil and gas, as well as environmental and safety matters.

Under certain circumstances, the United States Minerals Management Service may require that our operations on federal leases be suspended or terminated. These circumstances include our failure to pay royalties or our failure to comply with safety and environmental regulations. Any such suspension or termination could have a material adverse effect on our financial condition and operations. The requirements imposed by these laws and regulations are frequently changed and subject to new interpretations. It is likely that the costs of compliance could increase the cost of operating offshore drilling equipment or significantly limit drilling activity.

WE ARE VULNERABLE TO RISKS ASSOCIATED WITH OPERATING OFFSHORE CALIFORNIA.

We conduct operations offshore California. Our offshore California activities are subject to more extensive governmental regulation than our other oil and gas activities. In addition, we are vulnerable to the risks associated with operating offshore, including risks relating to:

- adverse weather conditions;

- oil field service and distribution costs and availability;

- compliance with environmental and other laws and regulations;

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- remediation and other costs resulting from oil spills or releases of hazardous materials; and

- failure of equipment or facilities.

If we experience any of these risks, we may incur substantial liabilities, which could adversely affect our operations and financial results.

ENVIRONMENTAL LIABILITIES COULD ADVERSELY AFFECT OUR FINANCIAL CONDITION.

The oil and gas business is subject to environmental hazards, such as oil spills, gas leaks and ruptures and discharges of petroleum products and hazardous substances, and historic disposal activities. These environmental hazards could expose us to material liabilities for property damages, personal injuries or other environmental harm, including costs of investigating and remediating contaminated properties. In addition to any environmental damages that we may cause, we also may be liable for environmental damages caused by the previous owners or operators of properties we have purchased or are currently operating. A variety of stringent federal, state and local laws and regulations govern the environmental aspects of our business. These laws and regulations impose strict requirements for, among other things:

- well development, operation and abandonment;

- waste management;

- land reclamation;

- financial assurance under the Oil Pollution Act of 1990; and

- controlling air, water and waste emissions.

Any noncompliance with these laws and regulations could subject us to material administrative, civil or criminal penalties or other liabilities. Additionally, our compliance with these laws may, from time to time, result in increased costs to our operations or decreased production, and may affect our costs of acquisitions.

We cannot assure you that environmental laws will not, in the future, cause a decrease in our production or cause an increase in our costs of production, development or exploration. Pollution and similar environmental risks generally are not fully insurable.

With respect to our onshore California and Illinois properties, although we have obtained environmental studies on these properties and we believe that these properties have been operated in accordance with standard oil field practices, some fields have been in operation for more than 90 years, and current or future local, state and federal environmental laws and regulations may require substantial expenditures to remediate the properties or to otherwise comply with these rules and regulations. For example, in December 1995, we negotiated an agreement with a unit of ChevronTexaco, a prior owner of our LA Basin properties, to remediate sections of the properties impacted by prior drilling and production operations. Under this agreement, ChevronTexaco agreed to investigate contamination at the LA Basin properties and potentially remediate specific areas contaminated with hazardous substances, such as volatile organic substances and heavy metals, and we agreed to excavate and remediate nonhazardous oil contaminated soils. We are obligated to construct and operate, for the next nine years, at least a five-acre parcel of land as bioremediation cells for oil contaminated soils designated for excavation and treatment by ChevronTexaco. Although we believe that we do not have any material obligations for operations conducted before our acquisition of the properties from ChevronTexaco other than our obligation to plug existing wells and those normally associated with customary oil field operations of similarly situated properties (such as our agreement with ChevronTexaco described above), there can be no assurance that current or future local, state or federal laws and regulations will not require us to spend material amounts to comply with

13

these laws and regulations or that any amounts will be recoverable from ChevronTexaco, either under our agreement or the limited indemnity from ChevronTexaco contained in the original purchase agreement.

In addition, approximately 183 acres of our 450 acres in the Montebello field have been designated as California Coastal Sage Scrub, a known habitat for the gnatcatcher, which is a species of bird designated as a federal threatened species under the Endangered Species Act, or ESA. A variety of existing laws, rules and guidelines govern activities that can be conducted on properties that contain Coastal Sage Scrub and gnatcatchers. These laws, rules and guidelines generally limit the scope of operations that we can conduct on this property to those activities that do not materially interfere with this vegetation, the gnatcatcher or its habitat. There are criminal penalties for willful violations of the ESA. Other statutes that provide protection to animal and plant species and which may apply to our operations include, but are not necessarily limited to, the Marine Mammal Protection Act, the Marine Protection, Research and Sanctuaries Act, the Fish and Wildlife Coordination Act, the Fishery Conservation and Management Act, the Migratory Bird Treaty Act and the National Historic Preservation Act. There can be no assurance that the presence of Coastal Sage Scrub and gnatcatchers on the Montebello field and existing or future laws, rules and guidelines will not prohibit or limit our operations and our planned activities for this property.

OUR ACQUISITION STRATEGY COULD FAIL OR PRESENT UNANTICIPATED PROBLEMS FOR OUR BUSINESS IN THE FUTURE, WHICH COULD ADVERSELY AFFECT OUR ABILITY TO MAKE ACQUISITIONS OR REALIZE ANTICIPATED BENEFITS OF THOSE ACQUISITIONS.

Our growth strategy may include acquiring oil and gas businesses and properties. We cannot assure you that we will be able to identify suitable acquisition opportunities or finance and complete any particular acquisition successfully. Furthermore, acquisitions involve a number of risks and challenges, including:

- diversion of management's attention;

- the need to integrate acquired operations;

- potential loss of key employees and customers of the acquired companies;

- potential lack of operating experience in a geographic market of the acquired business; and

- an increase in our expenses and working capital requirements.

Any of these factors could adversely affect our ability to achieve anticipated levels of cash flows from our acquired businesses or realize other anticipated benefits of those acquisitions.

WE INTEND TO CONTINUE HEDGING A PORTION OF OUR PRODUCTION, WHICH MAY RESULT IN OUR MAKING CASH PAYMENTS OR PREVENT US FROM RECEIVING THE FULL BENEFIT OF INCREASES IN PRICES FOR OIL AND GAS.

We reduce our exposure to the volatility of oil and gas prices by actively hedging a portion of our production. Hedging will also prevent us from receiving the full advantage of increases in oil or gas prices above the fixed amount specified in the hedge agreement. In a typical hedge transaction, we have the right to receive from the hedge counterparty the excess of the fixed price specified in the hedge agreement over a floating price based on a market index, multiplied by the quantity hedged. If the floating price exceeds the fixed price, we are required to pay the counterparty this difference multiplied by the quantity hedged even if we had insufficient production to cover the quantities specified in the hedge agreement. Accordingly, any production shortfalls that result in us having significantly less production than we have hedged when the floating price exceeds the fixed price would result in us being required to make payments where

14

we had no offsetting sales of production. If these payments become too large, the remainder of our business may be adversely affected. In addition, our hedging agreements expose us to risk of financial loss in circumstances where our counter party to a hedging contract could default on its contract obligations.

LOSS OF KEY EXECUTIVES AND FAILURE TO ATTRACT QUALIFIED MANAGEMENT COULD LIMIT OUR GROWTH AND NEGATIVELY IMPACT OUR OPERATIONS.

The successful implementation of our strategies will depend, in part, on Plains Resources' management team and, after the spin-off, our management team. The loss of members of Plains Resources' management or, after the spin-off, our management team could have an adverse effect on our business. Our exploitation success and the success of other activities integral to our operations will depend, in part, on Plains Resources' ability, and after our spin-off our ability, to attract and retain experienced engineers and other professionals. Competition for experienced professionals is extremely intense. If we or Plains Resources cannot attract or retain experienced technical personnel, our ability to compete could be harmed.

PLAINS RESOURCES AND ITS SUBSIDIARIES HAVE CONFLICTS OF INTEREST WITH US AND, ACCORDINGLY, WITH YOU.

We and Plains Resources and its subsidiaries share and, therefore will compete for, the time and effort of Plains Resources personnel who provide services to us, including directors, officers and other personnel. Officers of Plains Resources and its subsidiaries do not, and will not be required to, spend any specified percentage or amount of time on our business. Since these officers and directors function as both our representatives and those of Plains Resources and its subsidiaries, conflicts of interest could arise between Plains Resources and its subsidiaries, on the one hand, and us or you, on the other.
Additionally, some of these officers and directors own and are awarded from time to time financial shares, or options to purchase shares, of Plains Resources; accordingly, their financial interests may not always be aligned with ours or yours.

Some other situations in which an actual or potential conflict of interest arises between us, on the one hand, and Plains Resources or its subsidiaries, on the other hand, and there is a benefit to Plains Resources or its subsidiaries in which neither we nor you will share include payments made under our transition services agreement to Plains Resources consisting principally of reimbursements for general and administrative expenses and employee costs.

We cannot assure you that Plains Resources and its subsidiaries will always act in your best interest, even though doing so may appear to:

- protect and enhance Plains Resources' investment in us;

- generate substantial cash flows to Plains Resources; and

- provide Plains Resources with efficiently priced capital for its planned acquisitions.

We have entered into a number of agreements with Plains Resources including agreements concerning management of our business and employee and tax matters. See "Certain Transactions."

RISKS RELATING TO THE REORGANIZATION AND SPIN-OFF

IF WE ARE UNABLE TO OBTAIN THIRD-PARTY CONSENTS OR GOVERNMENTAL APPROVALS FOR THE ASSIGNMENT OR REISSUANCE OF CERTAIN CONTRACTS, PERMITS AND LICENSES ARISING FROM THE PROPOSED REORGANIZATION OR SPIN-OFF, WE WILL NOT COMPLETE THE REORGANIZATION OR SPIN-OFF.

The completion of the reorganization and spin-off will require prior consent by third parties and various approvals, filings and recordings with governmental entities to transfer existing

15

contracts and arrangements to us. In addition, several government-issued permits and licenses that are important to our business, including permits issued by city and county of Los Angeles and the county of Santa Barbara, may require reapplication by us and reissuance in our name. If we are unable to obtain these third-party consents to the assignment or reissuance of any contract, license or permit being transferred, we and Plains Resources will develop alternative approaches so that, to the extent possible, we will receive the benefits of the contract, license or permit and will discharge the duties and bear the costs and risks under such contract, license or permit. However, we cannot assure you that we will be able to obtain all third-party consents to the assignment or reissuance of any contract, license or permit being transferred, or that any alternative arrangements will provide us with the full benefits of the contract, license or permit. Accordingly, if we are required but unable to develop satisfactory alternative approaches, we may not complete the reorganization and/or spin-off.

OUR HISTORICAL FINANCIAL RESULTS AS SUBSIDIARIES OF PLAINS RESOURCES MAY NOT BE REPRESENTATIVE OF OUR RESULTS AS A SEPARATE COMPANY.

The historical financial information included in this prospectus does not necessarily reflect what our financial position, results of operations and cash flows would have been had we been a separate, stand-alone entity during the periods presented. Our costs and expenses reflect charges from Plains Resources for centralized corporate services and infrastructure costs. These allocations have been determined based on what we and Plains Resources considered to be reasonable reflections of the utilization of services provided to us or for the benefits received by us. This historical financial information is not necessarily indicative of what our results of operations, financial position and cash flows will be in the future. We may experience significant changes in our cost structure, funding and operations as a result of our reorganization and spin-off from Plains Resources, including increased costs associated with reduced economies of scale, and increased costs associated with being a publicly traded, stand-alone company.

UNDER OUR TAX ALLOCATION AGREEMENT, IF WE TAKE ACTIONS THAT CAUSE THE DISTRIBUTION OF OUR STOCK BY PLAINS RESOURCES TO ITS STOCKHOLDERS TO FAIL TO QUALIFY AS A TAX-FREE TRANSACTION, WE WILL BE REQUIRED TO INDEMNIFY PLAINS RESOURCES FOR ANY RESULTING TAXES. THIS POTENTIAL OBLIGATION TO INDEMNIFY PLAINS RESOURCES MAY PREVENT OR DELAY A CHANGE OF CONTROL OF US AFTER PLAINS RESOURCES DISTRIBUTES OUR COMMON STOCK TO ITS STOCKHOLDERS.

Plains Resources intends to distribute its shares of our common stock to its stockholders pursuant to the spin-off and has obtained a ruling from the IRS stating that, for United States federal income tax purposes, the spin-off will be generally tax-free to Plains Resources and its stockholders.

We have agreed with Plains Resources that we will not take any action inconsistent with any information, covenant or representation provided to the IRS in connection with obtaining the tax ruling and have further agreed to be liable for any taxes arising from a breach of that agreement. In addition, we have agreed that, during the three-year period following the spin-off, we will not engage in transactions that could adversely affect the tax treatment of the spin-off without the prior written consent of Plains Resources, unless we obtain a supplemental tax ruling from the IRS or a tax opinion acceptable to Plains Resources of nationally recognized tax counsel to the effect that the proposed transaction would not adversely affect the tax treatment of the spin-off. Moreover, we will be liable to Plains Resources for any corporate level taxes incurred by Plains Resources as a result of the spin-off or to specified transactions involving us following the spin-off including the acquisition of 50% of our common stock by any person or persons. To the extent the taxes arise as a result of a change of control of Plains Resources, failure of Plains Resources to continue the active conduct of its trade or business or failure of Plains Resources to comply with the representations underlying its tax ruling or a supplemental tax ruling relating to the spin-off, Plains Resources will be solely responsible for the taxes resulting from the spin-

16

off. If there are any corporate level taxes incurred by Plains Resources as a result of the spin-off and not due to any of the factors discussed in the two preceding sentences, we would be responsible for 50% of any such liability. The amount of any indemnification payments would be substantial, and we likely would not have sufficient financial resources to achieve our growth strategy or, possibly, repay our indebtedness after making these payments.

Current tax law provides that, depending on the facts and circumstances, the distribution of our stock by Plains Resources, if it occurs, may be taxable to Plains Resources if we undergo a 50% or greater change in stock ownership within two years after the distribution. Under agreements between us and Plains Resources, Plains Resources is entitled to require us to reimburse any tax costs incurred by Plains Resources as a result of a transaction resulting in a change in control of us. These costs may be so great that they delay or prevent a strategic acquisition or change in control of us.

RISKS RELATED TO THIS OFFERING

SINCE OUR COMMON STOCK HAS NOT TRADED PUBLICLY, THE INITIAL PUBLIC OFFERING PRICE MAY NOT BE INDICATIVE OF THE MARKET PRICE OF OUR COMMON STOCK AFTER THIS OFFERING, AND THE MARKET PRICE OF OUR COMMON STOCK MAY FLUCTUATE SIGNIFICANTLY.

There is currently no public market for our common stock, and an active trading market may not develop or be sustained after this offering. The initial public offering price has been determined through negotiation between us and representatives of the underwriters and may not be indicative of the market price for our common stock after this offering.

The market price of our common stock could fluctuate significantly as a result of:

- economic and stock market conditions generally and specifically as they may impact participants in the oil and gas industry;

- changes in financial estimates and recommendations by securities analysts following our stock;

- earnings and other announcements by, and changes in market evaluations of, participants in the oil and gas industry;

- changes in business or regulatory conditions affecting participants in the oil and gas industry;

- announcements or implementation by us or our competitors of technological innovations or new products; and

- trading volume of our common stock.

PLAINS RESOURCES WILL BE ABLE TO EXERT SIGNIFICANT INFLUENCE OVER OUR OPERATIONS.

After this offering, Plains Resources will own approximately % of our outstanding common stock, or % if the underwriter's option to purchase additional shares of common stock is exercised in full. As a result, Plains Resources will be able to significantly influence our board of directors and effectively control all matters that our stockholders vote upon, even if other directors or stockholders oppose them. These matters include the election of directors and significant transactions, such as business combinations. Such concentration of ownership may have the effect of delaying, deterring or preventing a change of control or other business combinations which would be economically beneficial to us or our stockholders.

WE DO NOT ANTICIPATE PAYING ANY DIVIDENDS ON OUR COMMON STOCK IN THE FORESEEABLE FUTURE.

We anticipate that we will retain all future earnings and other cash resources for the future operation and development of our business. Accordingly, we do not intend to declare or pay any

17

cash dividends in the foreseeable future. Payment of any future dividends will be at the discretion of our board of directors after taking into account many factors, including our operating results, financial condition, current and anticipated cash needs and plans for expansion. Any future dividends also may be restricted by future agreements with our lenders.

THE ACTUAL OR POSSIBLE SALE OF OUR SHARES BY PLAINS RESOURCES COULD DEPRESS OR REDUCE THE MARKET PRICE OF OUR COMMON STOCK OR CAUSE OUR SHARES TO TRADE BELOW THE PRICES AT WHICH THEY WOULD OTHERWISE TRADE.

Upon the completion of this offering, there will be shares of our common stock outstanding, assuming the underwriters do not exercise their option to purchase additional shares from us. Based on the same assumption, after this offering Plains Resources will beneficially own % of our outstanding common stock. The shares of our common stock sold in this offering will be freely tradable without restriction, except for any shares acquired by an affiliate of our company (which can be sold under Rule 144 under the Securities Act, subject to various volume and other limitations). Plains Resources is not obligated to retain these shares, except that subject to limited exceptions, it has agreed not to sell or otherwise dispose of any shares of common stock for 180 days after the completion of this offering without the consent of Goldman, Sachs & Co. except for a spin-off which is allowed after 120 days after the completion of this offering. After the expiration of this 180 or 120-day period, as applicable, Plains Resources could dispose of its shares of our common stock through a public offering, spin-off or other transaction and has indicated its intention to do so through a spin-off.

The market price of our common stock could drop as a result of sales of a large number of shares of our common stock in the market after this offering or the perception that these sales could occur. These factors also could make it more difficult for us to raise funds through future offerings of our common stock.

ANTI-TAKEOVER PROVISIONS UNDER OUR CERTIFICATE OF INCORPORATION, BYLAWS AND DELAWARE LAW MAY ADVERSELY AFFECT THE PRICE OF OUR COMMON STOCK, DISCOURAGE THIRD PARTIES FROM MAKING A BID FOR OUR COMPANY OR REDUCE ANY PREMIUMS PAID TO OUR STOCKHOLDERS FOR THEIR COMMON STOCK.

Amendments we intend to make to our certificate of incorporation, our bylaws and various provisions of the Delaware General Corporation Law may make it more difficult to effect a change in control of our company. These amendments, our bylaws and the various provisions of Delaware General Corporation Law may adversely affect the price of our common stock, discourage third parties from making a bid for our company or reduce any premiums paid to our stockholders for their common stock. See "Description of Capital Stock" for a more complete description of our capital stock, our certificate of incorporation and the effects of the Delaware General Corporation Law that could hinder a third party's attempts to acquire control of us.

YOU WILL EXPERIENCE IMMEDIATE AND SUBSTANTIAL DILUTION.

If you purchase common stock in this offering, you will pay more for your shares than the amounts paid by Plains Resources for its shares. As a result, you will experience immediate and substantial dilution of approximately $ per share, representing the difference between the assumed initial public offering price of $ per share and our net tangible book value per share as of , 2002 after giving effect to this offering. In addition, you may experience further dilution to the extent that shares of our common stock are issued upon the exercise of stock options or under our employee stock purchase plan. The shares initially issuable under our employee stock purchase plan will be issued at a purchase price less than the public offering price per share in this offering. In addition, some of the stock options we may issue in the future may have exercise prices below the initial public offering price. See "Dilution" for a more complete description of how the value of your investment in our common stock will be diluted upon the completion of this offering.

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SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

This prospectus includes forward-looking statements within the meaning of
Section 27A of the Securities Act, Section 21E of the Securities Exchange Act of 1934, which we will call the Exchange Act, and the Private Securities Litigation Reform Act of 1995. We have based these forward-looking statements on our current expectations and projections about future events. Statements that are predictive in nature, that depend upon or refer to future events or conditions, or that include words such as "should", "plans", "likely", "expects", "anticipates", "intends", "believes", "estimates", "thinks", "may", and similar expressions, are forward-looking statements. These statements involve known and unknown risks, uncertainties and other factors that may cause our actual results and performance to be materially different from any future results or performance expressed or implied by these forward-looking statements. These factors include, among other things, those matters discussed under the caption "Risk Factors," as well as the following:

- the consequences of any potential change in control of us or other change in the relationship between us and Plains Resources, including Plains Resources' contemplated spin-off of us;

- uncertainties inherent in the development and production of and exploration for oil and gas and in estimating reserves;

- unexpected future capital expenditures (including the amount and nature thereof);

- impact of oil and gas price fluctuations;

- the effects of competition;

- the success of our risk management activities;

- the availability (or lack thereof) of acquisition or combination opportunities;

- the impact of current and future laws and governmental regulations;

- environmental liabilities that are not covered by an effective indemnity or insurance; and

- general economic, market or business conditions.

All forward-looking statements in this prospectus are made as of the date hereof, and you should not rely on these statements without also considering the risks and uncertainties associated with these statements and our business that are addressed in this prospectus. Moreover, although we believe the expectations reflected in the forward-looking statements are based upon reasonable assumptions, we can give no assurance that we will attain these expectations or that any deviations will not be material.

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USE OF PROCEEDS

We estimate the net proceeds from our sale of shares of common stock will be $ million, after deducting underwriting discounts and commissions and estimated expenses of this offering. If the underwriters' option to purchase additional shares of common stock is exercised in full, we estimate the net proceeds will be $ million. We intend to use a portion of these net proceeds to repay amounts outstanding under our new revolving credit facility. We intend to use the excess net proceeds and the borrowing capacity under our credit facility, together with internally generated cash flow, to pursue development, exploitation and acquisition activities, and for general corporate purposes.

We intend to enter into a $300.0 million revolving credit facility with JPMorgan Chase Bank as sole administrative agent. We expect our initial borrowings under this credit facility, together with proceeds under our anticipated debt financing, to be distributed to Plains Resources. Plains Resources intends to use these proceeds to repay amounts outstanding under its revolving credit facility and to redeem its 10.25% senior subordinated notes due 2006. Our credit facility will initially provide for a borrowing base of $225.0 million that will be reviewed every six months, with the parties having the right to one annual interim unscheduled redetermination, and adjusted based on our oil and gas properties, reserves, other indebtedness and other relevant factors, and will mature in 2005. Additionally, the credit facility contains a $30.0 million sub-limit on letters of credit. Amounts borrowed under this credit facility bear an annual interest rate, at our election, equal to either:

- the Eurodollar rate, plus from 1.375% to 1.75%; or

- the greatest of (1) the prime rate, as determined by JPMorgan Chase Bank,
(2) the certificate of deposit rate, plus 1.0%, or (3) the federal funds rate, plus 0.5%; plus an additional 0.125% to 0.5% for each of (1)-(3).

DIVIDEND POLICY

We have not declared or paid any cash dividends and do not anticipate declaring or paying any cash dividends. We intend to retain our earnings to finance the expansion of our business and for general corporate purposes. Our board of directors will have the authority to declare and pay dividends on our common stock in its discretion, as long as we have funds legally available to do so. We expect that our new credit facility will limit us in paying cash dividends.

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CAPITALIZATION

The following table sets forth our capitalization as of March 31, 2002 on a historical combined basis, and on an as adjusted basis to reflect completion of this offering and the application of the net proceeds as described in "Use of Proceeds".

You should read the adjusted capitalization data set forth in the table below in conjunction with "Use of Proceeds", "Selected Historical Combined Financial and Other Data", "Management's Discussion and Analysis of Financial Condition and Results of Operations" and our historical combined financial statements and the notes appearing elsewhere in this prospectus.

                                                             AS OF MARCH 31, 2002
                                                         ----------------------------
                                                         HISTORICAL
                                                          COMBINED      AS ADJUSTED
                                                         ----------     -----------
                                                            (DOLLARS IN THOUSANDS)
Cash and cash equivalents..............................   $      1        $
                                                          ========        ======
Total debt:
  Revolving credit facility............................   $     --        $
  Long-term debt.......................................         --
  Other................................................      1,533
  Payable to Plains Resources(1).......................    249,572
                                                          --------        ------
     Total debt........................................    251,105
                                                          --------        ------
Stockholder's equity...................................    162,773
                                                          --------        ------
Total capitalization...................................   $413,878        $
                                                          ========        ======


(1) Amount payable to Plains Resources represents cumulative amounts advanced to us and our subsidiaries less all repayments of those advances. We anticipate completing a financing which would increase total debt by $66.7 million which would result in an increase in interest expense of $0.5 million and $3.3 million and amortization expense of $0.3 million and $1.0 million and a decrease to net income of $0.5 million and $2.6 million for the three months ended March 31, 2002 and for the year ended December 31, 2001, respectively. See "Summary -- Recent Developments". Historically, all financing activity of Plains Resources and its subsidiaries occurred at Plains Resources. As of March 31, 2002 Plains Resources had $31.0 million outstanding under its revolving credit facility and $267.5 of its 10.25% notes outstanding.

21

DILUTION

Our net tangible book value as of March 31, 2002 was approximately $ million, or $ per share. Net tangible book value per share is equal to our total tangible assets minus our total liabilities divided by the number of shares of our common stock outstanding. Assuming we had sold the shares of common stock offered by this prospectus at an assumed initial public offering price of $ per share, and after deducting underwriting discounts and commissions and estimated offering expenses and the distributions to Plains Resources referred to above under "Capitalization" totaling $ million, our pro forma net tangible book value at March 31, 2002 would have been approximately $ million, or $ per share. This represents an immediate decrease in net tangible book value of $ per share to Plains Resources and an immediate dilution of $ to new investors. Dilution is determined by subtracting net tangible book value per share after the offering from the amount of cash paid by a new investor for a share of common stock. The following table illustrates the substantial and immediate per share dilution to new investors:

Assumed public offering price per share.....................             $
  Net tangible book value per share as of March 31, 2002....  $
  Dividend payment to Plains Resources......................
                                                              --------
  Increase in pro forma net tangible book value attributable
     to the offering........................................
                                                              --------
  Pro forma net tangible book value per share as of March
     31, 2002 after giving effect to the offering...........
                                                                         --------
Dilution per share to new investors.........................
                                                                         ========

The following table shows, as of March 31, 2002, the difference between our existing stockholder and new investors with respect to the number of shares purchased from us, the total consideration paid and the average price paid per share. The table assumes that the public offering price will be $ per share.

                              SHARES PURCHASED    TOTAL CONSIDERATION    AVERAGE
                              -----------------   -------------------     PRICE
                              NUMBER    PERCENT   AMOUNT($)   PERCENT   PER SHARE
                              ------    -------   ---------   -------   ---------
Existing stockholder........                 %                     %     $
New investors...............                 %                     %
                              -------     ---     --------      ---      ------
     Total..................                 %                     %
                              =======     ===     ========      ===      ======

The foregoing table assumes no exercise of the underwriters' overallotment option and no exercise of outstanding stock options or warrants.

If the underwriters exercise their overallotment option in full, the net tangible book value per share of common stock as of March 31, 2002 would have been $ per share, which would result in dilution to the new investors of $ per share, and the number of shares held by the new investors will increase to , or % of the total number of shares to be outstanding after this offering, and the number of shares held by Plains Resources will be shares, or % of the total number of shares to be outstanding after this offering.

22

SELECTED HISTORICAL COMBINED FINANCIAL AND OTHER DATA

The following table summarizes the combined statements of income and combined balance sheets data for our business since January 1, 1997. These data have been derived from (i) the audited combined statements of income for our business for each of the years ended December 31, 2001, 2000, and 1999 and combined balance sheets for our business as of December 31, 2001 and 2000, (ii) the unaudited combined statements of income for our business for each of the years ended December 31, 1998 and 1997 and combined balance sheets for our business as of December 31, 1999, 1998 and 1997 and (iii) the unaudited combined statements of income and balance sheets of our business as of and for each of the three months ended March 31, 2002 and 2001. You should read this information in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations" and our historical combined financial statements and notes included elsewhere in this prospectus. The information set forth below is not necessarily indicative of our future results.

                                THREE MONTHS ENDED
                                     MARCH 31,                      YEAR ENDED DECEMBER 31,
                                -------------------   ----------------------------------------------------
                                  2002       2001       2001       2000       1999       1998       1997
                                --------   --------   --------   --------   --------   --------   --------
                                                (DOLLARS IN THOUSANDS, EXCEPT OTHER DATA)
STATEMENT OF INCOME DATA:
Revenues:
  Oil and liquids.............  $ 38,685   $ 42,601   $174,895   $126,434   $102,390   $ 81,416   $ 81,381
  Gas.........................     1,988     11,172     28,771     16,017      5,095      4,091      3,805
  Other operating revenues....        --         --        473         --         --         --         --
                                --------   --------   --------   --------   --------   --------   --------
         Total revenues.......    40,673     53,773    204,139    142,451    107,485     85,507     85,186
                                --------   --------   --------   --------   --------   --------   --------
Costs and expenses:
  Production expenses.........    17,229     13,370     63,795     56,228     50,527     42,823     36,571
  General and
    administrative............     2,452      2,786     10,210      6,308      4,367      3,218      2,724
  Depreciation, depletion and
    amortization..............     6,691      5,364     24,105     18,859     13,329     13,901     10,453
  Reduction of carrying cost
    of oil and gas
    properties(1).............        --         --         --         --         --     42,920         --
                                --------   --------   --------   --------   --------   --------   --------
         Total costs and
           expenses...........    26,372     21,520     98,110     81,395     68,223    102,862     49,748
                                --------   --------   --------   --------   --------   --------   --------
Income (loss) from
  operations..................    14,301     32,253    106,029     61,056     39,262    (17,355)    35,438
  Interest expense............    (4,692)    (4,191)   (17,411)   (15,885)   (14,912)    (8,828)    (5,113)
  Interest and other income...        18        558        463        343         87         74         88
                                --------   --------   --------   --------   --------   --------   --------
Income (loss) before income
  taxes and cumulative effect
  of accounting change........     9,627     28,620     89,081     45,514     24,437    (26,109)    30,413
Income tax (expense) benefit
  Current.....................    (2,045)    (1,932)    (6,014)    (2,431)      (505)    (4,435)   (10,916)
  Deferred....................    (1,718)    (9,115)   (28,374)   (14,334)    (4,827)    11,510     (1,364)
                                --------   --------   --------   --------   --------   --------   --------
Income (loss) before
  cumulative effect of
  accounting change...........     5,864     17,573     54,693     28,749     19,105    (19,034)    18,133
Cumulative effect of
  accounting change, net of
  tax benefit(2)..............        --     (1,522)    (1,522)        --         --         --         --
                                --------   --------   --------   --------   --------   --------   --------
Net income (loss).............  $  5,864   $ 16,051   $ 53,171   $ 28,749   $ 19,105   $(19,034)  $ 18,133
                                ========   ========   ========   ========   ========   ========   ========

23

                                  AS OF MARCH 31,                      AS OF DECEMBER 31,
                                -------------------   ----------------------------------------------------
                                  2002       2001       2001       2000       1999       1998       1997
                                --------   --------   --------   --------   --------   --------   --------
                                                    (IN THOUSANDS, EXCEPT OTHER DATA)
BALANCE SHEET DATA:
Cash and cash equivalents.....  $      1   $  1,120   $     13   $    536   $  5,075   $    138   $    207
Working capital...............   (24,048)    (2,485)       932     (6,861)    16,169    (12,148)    (7,142)
Total assets..................   508,354    427,853    516,755    401,035    360,964    277,792    239,712
Total debt....................   251,105    219,471    236,694    227,040    240,172    180,483    122,331
Combined owners' equity.......   162,773    127,806    180,087    111,032     82,283     63,177     85,776


(1) Noncash charge related to a ceiling test write-down of the capitalized costs of our proved oil and gas properties due to low oil prices at December 31, 1998.

(2) Cumulative effect of adopting Statement of Financial Accounting Standards No. 133--"Accounting for Derivatives," or SFAS 133.

24

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

GENERAL

We are an independent oil and gas company primarily engaged in the upstream activities of acquiring, exploiting, developing and producing oil and gas in the United States. We are 100% owned by Plains Resources Inc. Our core areas of operation are:

- onshore California, primarily in the LA Basin, and offshore California in the Point Arguello unit; and

- the Illinois Basin in southern Illinois.

We follow the full cost method of accounting whereby all costs associated with property acquisition, exploration, exploitation and development activities are capitalized. Our revenues are derived from the sale of oil, gas and natural gas liquids. We recognize revenues when our production is sold and title is transferred. Our revenues are highly dependent upon the prices of, and demand for, oil and gas. Historically, the markets for oil and gas have been volatile and are likely to continue to be volatile in the future. The prices we receive for our oil and gas and our levels of production are subject to wide fluctuations and depend on numerous factors beyond our control, including supply and demand, seasonality, economic conditions, foreign imports, the actions of OPEC, political conditions in other oil-producing countries, and governmental regulation, legislation and policies. Decreases in oil and gas prices have had, and will likely have in the future, an adverse effect on the carrying value of our proved reserves and our revenues, profitability and cash flow.

To manage our exposure to commodity price risks, we use various derivative instruments to hedge our exposure to oil sales price fluctuations. Our hedging arrangements provide us protection on the hedged volumes if oil prices decline below the prices at which these hedges are set. However, if oil prices increase, ceiling prices in our hedges may cause us to receive less revenues on the hedged volumes than we would receive in the absence of hedges. We do not currently have any gas hedges. Gains and losses from hedging transactions are recognized as revenues when the associated production is sold.

Our oil and gas production expenses include salaries and benefits of field personnel, electric utilities, maintenance costs, production, ad valorem and severance taxes, and other costs necessary to operate our producing properties. Depletion of capitalized costs of producing oil and gas properties is provided using the units of production method based upon proved reserves. For the purposes of computing depletion, proved reserves are redetermined as of the end of each year and on an interim basis when deemed necessary. General and administrative expenses consist primarily of salaries and related benefits of administrative personnel, office rent, systems costs and other administrative costs. We estimate that our annual general and administrative expenses will increase by approximately $3.5 million in connection with the reorganization.

Tax expense and effective tax rates have been calculated based on what we believe such expense would have been had we been a taxable entity on a combined basis for such periods.

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RESULTS OF OPERATIONS

The following table reflects the components of our oil and gas sales prices and sets forth our operating revenues and costs and expenses on a BOE basis:

                                               THREE MONTHS
                                                  ENDED
                                                MARCH 31,         YEAR ENDED DECEMBER 31,
                                             ----------------    --------------------------
                                              2002      2001      2001      2000      1999
                                             ------    ------    ------    ------    ------
Average oil sales price ($/Bbl)
  Average NYMEX............................  $21.63    $28.67    $26.01    $30.25    $19.25
  Hedging gain (loss)......................    1.68     (1.91)     0.03     (9.51)    (1.06)
  Differential.............................   (4.28)    (4.57)    (4.76)    (4.22)    (3.73)
                                             ------    ------    ------    ------    ------
  Net realized.............................  $19.03    $22.19    $21.28    $16.52    $14.46
                                             ======    ======    ======    ======    ======
Average gas sales price ($/Mcf)............  $ 2.27    $15.00    $ 8.58    $ 5.26    $ 1.61
                                             ======    ======    ======    ======    ======
Average sales price per BOE................  $18.67    $26.31    $23.20    $17.46    $14.13
Average production expenses per BOE........   (7.91)    (6.54)    (7.27)    (6.89)    (6.64)
                                             ------    ------    ------    ------    ------
Gross margin per BOE.......................   10.76     19.77     15.93     10.57      7.49
G&A per BOE(1).............................   (1.03)    (1.36)    (0.86)    (0.77)    (0.57)
                                             ------    ------    ------    ------    ------
Gross profit per BOE.......................  $ 9.73    $18.41    $15.07    $ 9.80    $ 6.92
                                             ======    ======    ======    ======    ======
DD&A per BOE (oil and gas properties)......  $ 3.04    $ 2.58    $ 2.70    $ 2.25    $ 1.72

(1) Excludes noncash compensation.

COMPARISON OF THREE MONTHS ENDED MARCH 31, 2002 TO THREE MONTHS ENDED MARCH 31,
2001

OPERATING REVENUES Our operating revenues decreased 24%, or $13.1 million, to $40.7 million for the three months ended March 31, 2002 from $53.8 million for the three months ended March 31, 2001. The decrease was primarily due to lower realized prices for oil and gas.

Our daily oil sales volumes increased 6%, or 1.3 MBbls, to 22.6 MBbls for the three months ended March 31, 2002 from 21.3 MBbls for the three months ended March 31, 2001. Our daily gas sales volumes increased 18%, or 1.4 MMcf, to 9.7 MMcf for the three months ended March 31, 2002 from 8.3 MMcf for the three months ended March 31, 2001. Production increases were primarily attributable to the continuing development of our onshore California properties.

Our average realized price for oil and natural gas liquids decreased 14%, or $3.16, to $19.03 per Bbl for the three months ended March 31, 2002 from $22.19 per Bbl for the three months ended March 31, 2001. The average NYMEX oil price decreased 25%, or $7.04, to $21.63 per Bbl for the three months ended March 31, 2002 from $28.67 per Bbl for the three months ended March 31, 2001. The NYMEX decrease was partially offset by a $3.59 per Bbl increase in our hedging margin and a $0.29 per Bbl improvement in location and quality differentials. The average realized price for gas decreased 85%, or $12.73, to $2.27 per Mcf for the three months ended March 31, 2002 from $15.00 per Mcf in 2001. Gas prices were unusually high in 2001, particularly in California.

PRODUCTION EXPENSES. Our production expenses increased 29%, or $3.8 million, to $17.2 million for the three months ended March 31, 2002 from $13.4 million for the three months ended March 31, 2001. On a per unit basis, production expenses increased 21%, or $1.37, to $7.91 per BOE for the three months ended March 31, 2002 from $6.54 per BOE for the three months ended March 31, 2001. Production expenses for 2001 were reduced by approximately $1.07 per BOE as a result of nonrecurring credits (primarily the sale of certain California emissions credits). Excluding these credits, production expenses increased 4% per BOE during the same period primarily due to higher electricity costs in California.

26

GENERAL AND ADMINISTRATIVE EXPENSE. Our general and administrative, or G&A expense, decreased 12%, or $0.3 million, to $2.5 million for the three months ended March 31, 2002 from $2.8 million for the three months ended March 31, 2001. This decrease was primarily due to reduced costs for third-party legal and reserve engineering services.

DEPRECIATION, DEPLETION AND AMORTIZATION. Our depreciation, depletion and amortization, or DD&A, expense increased 26%, or $1.3 million, to $6.7 million for the three months ended March 31, 2002 from $5.4 million for the three months ended March 31, 2001. An increase in the oil and gas DD&A rate to $3.04 per BOE for the three months ended March 31, 2002 from $2.58 per BOE for the three months ended March 31, 2001 was primarily due to increased estimated future development costs of our proved reserves.

INTEREST EXPENSE. Our interest expense increased 12%, or $0.5 million, to $4.7 million for the three months ended March 31, 2002 from $4.2 million for the three months ended March 31, 2001, reflecting higher amounts owed to Plains Resources.

INCOME TAX EXPENSE. Our income tax expense decreased 65%, or $7.2 million, to $3.8 million for the three months ended March 31, 2002 from $11.0 million for the three months ended March 31, 2001. The decrease was primarily due to a decrease in pre-tax income, partially offset by an increase in our effective tax rate to 39.1% for the three months ended March 31, 2002 from 38.6% for the three months ended March 31, 2001. The rate increase was primarily due to increased state income taxes in California.

CUMULATIVE EFFECTS. The cumulative effects of accounting change recognized for the three months ended March 31, 2001 reflects the adoption of Statement of Financial Accounting Standards No. 133 "Accounting for Derivative Instruments and Hedging Activities," as amended.

COMPARISON OF YEAR ENDED DECEMBER 31, 2001 TO YEAR ENDED DECEMBER 31, 2000

OPERATING REVENUES. Our operating revenues increased 43%, or $61.6 million, to $204.1 million in 2001 from $142.5 million in 2000. The increase primarily reflects higher realized oil and gas prices. Increased prices contributed $46.7 million in additional revenues, and increased sales volumes contributed $14.9 million.

Our daily oil sales volumes increased 8%, or 1.6 MBbls, to 22.5 MBbls in 2001 from 20.9 MBbls in 2000. Our daily gas sales volumes increased 11%, or 0.9 MMcf, to 9.2 MMcf in 2001 from 8.3 MMcf in 2000. Production increases were primarily attributable to the continuing development of our onshore California properties.

Our average realized price for oil increased 29%, or $4.76, to $21.28 per Bbl in 2001 from $16.52 per Bbl in 2000. The average NYMEX oil price decreased 14%, or $4.24, to $26.01 per Bbl in 2001 from $30.25 per Bbl in 2000. The NYMEX decrease was more than offset by a $9.54 per Bbl increase in our hedging margin. The average realized price for gas increased 63%, or $3.32, to $8.58 per Mcf in 2001 from $5.26 per Mcf in 2000. Gas prices were unusually high in 2001, particularly in California.

PRODUCTION EXPENSES. Our production expenses increased 13%, or $7.6 million, to $63.8 million in 2001 from $56.2 million in 2000. Expenses for 2001 were reduced by $2.2 million due to the sale of certain California emission credits. Excluding the credits, on a BOE basis production expenses increased 9%, or $0.63, to $7.52 per BOE in 2001 from $6.89 per BOE in 2000. The increase is primarily due to increased volumes and higher electricity costs in California.

GENERAL AND ADMINISTRATIVE EXPENSE. Our G&A expense increased 62%, or $3.9 million, to $10.2 million in 2001 from $6.3 million in 2000. This increase was primarily due to a $3.7 million increase in G&A expenses allocated by Plains Resources. The increase in Plains Resources' G&A expenses was primarily due to costs related to its 2001 corporate reorganization.

27

DEPRECIATION, DEPLETION AND AMORTIZATION. Our DD&A expense increased 28%, or $5.2 million, to $24.1 million in 2001 from $18.9 million in 2000. An increase in the oil and gas DD&A rate of 20%, or $0.45, to $2.70 per BOE in 2001 from $2.25 per BOE in 2000 was primarily due to increased estimated future development costs.

INTEREST EXPENSE. Our interest expense increased 10%, or $1.5 million, to $17.4 million in 2001 from $15.9 million in 2000, reflecting higher amounts owed to Plains Resources which were partially offset by lower interest rates.

INCOME TAX EXPENSE. Our income tax expense increased 105%, or $17.6 million, to $34.4 million in 2001 from $16.8 million in 2000. The increase was primarily due to the increase in our operating income.

CUMULATIVE EFFECT. The cumulative effect of accounting change recognized for the year ended December 31, 2001 was for the adoption of Statement of Financial Accounting Standards No. 133 "Accounting for Derivative Instruments and Hedging Activities," as amended.

COMPARISON OF YEAR ENDED DECEMBER 31, 2000 TO YEAR ENDED DECEMBER 31, 1999

OPERATING REVENUES. Our operating revenues increased 33%, or $35.0 million, to $142.5 million in 2000 from $107.5 million in 1999. The increase was primarily due to higher realized oil and gas prices. Increased prices contributed $25.3 million in additional revenues and increased sales volumes contributed $9.7 million.

Our daily oil sales volumes increased 8%, or 1.5 MBbls, to 20.9 MBbls in 2000 from 19.4 MBbls in 1999. The volume increase is primarily due to a full year of production from our offshore California property, which was acquired in mid-1999. Our daily gas sales volumes decreased 4%, or 0.4 MMcf, to 8.3 MMcf in 2000 from 8.7 MMcf in 1999.

Our average realized price for oil increased 14%, or $2.06, to $16.52 per Bbl in 2000 from $14.46 per Bbl in 1999. The average NYMEX oil price increased 57%, or $11.00, to $30.25 per Bbl in 2000 from $19.25 per Bbl in 1999. We did not participate in the full amount of this increase, as hedges that we put into place in the latter part of 1999, when oil prices were significantly lower, decreased our realized price by $9.51 per Bbl in 2000. The average realized price for gas increased 227%, or $3.65, to $5.26 per Mcf in 2000 from $1.61 per Mcf in 1999.

PRODUCTION EXPENSES. Our production expenses increased 11%, or $5.7 million, to $56.2 million in 2000 from $50.5 million in 1999. Increased volumes accounted for $3.8 million of the increase. On a BOE basis, production expenses increased 4%, or $0.25, to $6.89 per BOE in 2000 from $6.64 per BOE in 1999, primarily reflecting a full year of production from our offshore California property, increased gas fuel costs and higher oilfield service costs.

GENERAL AND ADMINISTRATIVE EXPENSE. Our G&A expense increased 44%, or $1.9 million, to $6.3 million in 2000 from $4.4 million in 1999. This increase was primarily due to an increase in the number of employees in the latter part of 1999 and an increase in G&A expenses allocated by Plains Resources.

DEPRECIATION, DEPLETION AND AMORTIZATION. Our DD&A expense increased 41%, or $5.6 million, to $18.9 million in 2000 from $13.3 million in 1999. An increase in the oil and gas DD&A rate of 31%, or $0.53, to $2.25 per BOE in 2000 from $1.72 per BOE in 1999 was primarily due to an increase in estimated future development costs.

INTEREST EXPENSE. Our interest expense increased 7%, or $1.0 million, to $15.9 million in 2000 from $14.9 million in 1999, primarily reflecting higher interest rates.

INCOME TAX EXPENSE. Our income tax expense increased 214%, or $11.4 million, to $16.7 million in 2000 from $5.3 million in 1999. Our income tax expense in 1999 was reduced by $3.8 million as a result of the reversal of a valuation allowance established with respect to the

28

deferred tax benefit related to the $42.9 million reduction on carrying costs of oil and gas properties recognized in 1998. Excluding this benefit, our income tax expense for 1999 was $9.1 million. Our effective tax rate was 36.8% in 2000 compared to 37.2% in 1999.

LIQUIDITY AND CAPITAL RESOURCES

Historically, our primary sources of liquidity have been cash generated from our operations and financing activity through our parent, Plains Resources. After entering into a proposed revolving credit facility and a debt financing, we believe that we will have sufficient liquidity through our cash from operations and borrowing capacity under our new revolving credit facility to meet our short-term and long-term normal recurring operating needs, debt service obligations, contingencies and anticipated capital expenditures.

We intend to make aggregate capital expenditures of approximately $73.0 million in 2002. In addition, we intend to continue to pursue the acquisition of underdeveloped producing properties. We believe that we will have sufficient cash from operating activities and borrowings under our new credit facility to fund our capital expenditures.

During 2002, we expect to spend approximately $61.0 million on maintaining, developing and exploiting our oil and gas properties and pursuing acquisition opportunities. We expect approximately $45.0 million of these capital expenditures will be for exploitation projects in onshore California. The 2002 capital program incorporates the results of various analyses and field studies and includes our drilling approximately 87 total wells, including 10 injection wells and numerous injection realignment related workovers. In addition, our 2002 estimated capital expenditures include $12.0 million of capitalized interest and general and administrative costs allocable directly to acquisition, exploitation and development activities. During the three months ended March 31, 2002 capital expenditures for these activities was $23.9 million.

CRITICAL ACCOUNTING POLICIES

Based on the accounting policies which we have in place, certain factors may impact our future financial results. The most significant of these factors and their effect on certain of our accounting policies are discussed below.

COMMODITY PRICING AND RISK MANAGEMENT ACTIVITIES. Prices for oil and gas have historically been volatile. Decreases in oil and gas prices from current levels will adversely affect our revenues, results of operations, cash flows and proved reserves. If the industry experiences significant prolonged future price decreases, this could be materially adverse to our operations and our ability to fund planned capital expenditures.

Periodically, we enter into hedging arrangements relating to a portion of our oil production to achieve a more predictable cash flow, as well as to reduce our exposure to adverse price fluctuations. Hedging instruments used are typically fixed price swaps and collars and purchased puts and calls. While the use of these types of hedging instruments limits our downside risk to adverse price movements, we are subject to a number of risks, including instances in which the benefit to revenues is limited when commodity prices increase. For a further discussion concerning our risks related to oil and gas prices and our hedging programs, see "--Quantitative and Qualitative Disclosures about Market Risks".

WRITE-DOWNS UNDER FULL COST CEILING TEST RULES. Under the SEC's full cost accounting rules we review the carrying value of our proved oil and gas properties each quarter. Under these rules, capitalized costs of proved oil and gas properties (net of accumulated depreciation, depletion and amortization, and deferred income taxes) may not exceed a "ceiling" equal to:

- the standardized measure (including, for this test only, the effect of any related hedging activities); plus

29

- the lower of cost or fair value of unproved properties included in the costs being amortized (net of related tax effects).

These rules generally require that we price our future oil and gas production at the oil and gas prices in effect at the end of each fiscal quarter and require a write-down if our capitalized costs exceed this "ceiling," even if prices declined for only a short period of time. We have had no write-downs due to these ceiling test limitations since 1998. Given the volatility of oil and gas prices, it is likely that our estimate of discounted future net revenues from proved oil and gas reserves will change in the near term. If oil and gas prices decline significantly in the future, even if only for a short period of time, write-downs of our oil and gas properties could occur. Write-downs required by these rules do not directly impact our cash flows from operating activities.

OIL AND GAS RESERVES. The proved reserve information included in this prospectus is based on estimates prepared by outside engineering firms. Estimates prepared by others may be higher or lower than these estimates. Because these estimates depend on many assumptions, all of which may substantially differ from actual results, reserve estimates may be different from the quantities of oil and gas that are ultimately recovered. In addition, results of drilling, testing and production after the date of an estimate may justify material revisions to the estimate.

You should not assume that PV-10 is the current market value of our estimated proved oil and gas reserves. In accordance with SEC requirements, we base the estimated discounted future net revenues from proved reserves on prices and costs on the date of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of the estimate.

Our rate of recording DD&A is dependent upon our estimate of proved reserves. If the estimates of proved reserves decline, the rate at which we record DD&A expense increases, reducing our net income. This decline may result from lower market prices, which may make it uneconomic to drill for and produce higher cost fields. In addition, the decline in proved reserve estimates may impact the outcome of the "ceiling" test discussed above.

OPERATING RISKS AND INSURANCE COVERAGE. Our operations are subject to all of the risks normally incident to the exploration for and the production of oil and gas, including well blowouts, cratering, explosions, spills of oil, gas or well fluids, fires, pollution and releases of toxic gas, each of which could result in damage to or destruction of oil and gas wells, production facilities or other property, or injury to persons. Our operations in California, including transportation of oil by pipelines within the city and county of Los Angeles, are especially susceptible to damage from earthquakes and involve increased risks of personal injury, property damage and marketing interruptions because of the population density of southern California. Although we maintain insurance coverage considered to be customary in the industry, we are not fully insured against some risks, including earthquake risk in California, either because insurance is not available or because of high premium costs. The occurrence of a significant event that is not fully insured against could have a material adverse effect on our financial position. Our insurance does not cover every potential risk associated with operating our pipelines, including the potential loss of significant revenues. Consistent with insurance coverage generally available to the industry, our insurance policies provide limited coverage for losses or liabilities relating to pollution, with broader coverage for sudden and accidental occurrences.

ENVIRONMENTAL MATTERS. As an owner or lessee and operator of oil and gas properties, we are subject to various federal, state, and local laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liabilities on us for the cost of pollution clean-up resulting from operations, subject us to liability for pollution damages, and require suspension or cessation of operations in affected areas. We maintain insurance coverage, which we believe is customary in the industry, although we are not fully insured against all environmental risks. We have established policies for continuing compliance with environmental laws and regulations and have made and will continue

30

to make expenditures in our efforts to comply with these requirements, which we believe are necessary business costs in the oil and gas industry.

Although we obtained environmental studies on our properties in California and the Illinois Basin, and we believe that these properties have been operated in accordance with standard oil field practices, certain of the fields have been in operation for over 90 years, and current or future federal, state and local environmental laws and regulations may require substantial expenditures to remediate our properties or otherwise comply with these rules and regulations. While we do not believe that the cost of remediation and other compliance with current federal, state or local environmental laws and regulations will have a material adverse effect on our capital expenditures, results of operations or competitive position; there is no assurance that changes in or additions to these laws or regulations will not have such an impact.

Consistent with normal industry practices, substantially all of our oil and gas leases require that, upon termination of economic production, the working interest owners plug and abandon non-producing wellbores, remove tanks, production equipment and flow lines and restore the wellsite. We have estimated that the cost to perform these tasks is currently approximately $12.0 million, net of salvage value and other considerations. These estimated amortized costs are included in expenses through the unit-of-production method as a component of accumulated DD&A. Results from operations for 2001, 2000 and 1999 each include $0.5 million, $0.2 million and $0.2 million, respectively, of expense associated with these estimated future costs.

RECENT ACCOUNTING PRONOUNCEMENTS

In June 2001 Statement of Accounting Standards, or SFAS, No. 143, "Accounting for Asset Retirement Obligations" was issued. SFAS No. 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. After recording, the asset retirement cost will be allocated to expense using a systematic and rational method. SFAS No. 143 is effective for fiscal years beginning after June 15, 2002. We are currently assessing the impact of SFAS No. 143 and at this time we cannot reasonably estimate the effect of this statement on our consolidated financial position, results of operations or cash flows.

QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISKS

We are exposed to various market risks, including volatility in oil and gas commodity prices and interest rates. Although we have routinely hedged a substantial portion of our oil production and intend to continue this practice, substantial future oil and gas price declines would adversely affect our overall results, and therefore our liquidity. Furthermore, low oil and gas prices could affect our ability to raise capital on favorable terms. Decreases in the prices of oil and gas have had, and could have in the future, an adverse effect on the carrying value of our proved reserves and our revenues, profitability and cash flow. To manage our exposure, we monitor current economic conditions and our expectations of future commodity prices and interest rates when making decisions with respect to risk management. We do not enter into derivative transactions for speculative trading purposes. Substantially all of our derivative contracts are exchanged or traded with major financial institutions and the risk of credit loss is considered remote.

SFAS NO. 133. For purposes of our combined financial statements, on January 1, 2001 we implemented SFAS No. 133 "Accounting for Derivative Instruments and Hedging Activities" as amended by SFAS 137 and SFAS 138, or SFAS 133. Under SFAS 133, all derivative instruments are recorded on the balance sheet at fair value. If the derivative does not qualify as a hedge or is not designated as a hedge, the gain or loss on the derivative is recognized currently in earnings. To qualify for hedge accounting, the derivative must qualify either as a fair value hedge, cash flow hedge or foreign currency hedge. Currently, we use only cash flow hedges and the remaining discussion will relate exclusively to this type of derivative instrument. If the derivative

31

qualifies for hedge accounting, the gain or loss on the derivative is deferred in accumulated Other Comprehensive Income, or OCI, a component of our stockholders' equity, to the extent the hedge is effective.

The relationship between the hedging instrument and the hedged item must be highly effective in achieving the offset of changes in cash flows attributable to the hedged risk both at the inception of the contract and on an ongoing basis. Hedge accounting is discontinued prospectively when a hedge instrument becomes ineffective. Gains and losses deferred in OCI related to cash flow hedges that become ineffective remain unchanged until the related product is delivered. If it is probable that a hedged forecasted transaction will not occur, deferred gains or losses on the hedging instrument are recognized in earnings immediately.

We formally document all relationships between hedging instruments and hedged items, as well as our risk management objectives and strategy for undertaking the hedge. Hedge effectiveness is measured on a quarterly basis. This process includes specific identification of the hedging instrument and the hedged item, the nature of the risk being hedged and the manner in which the hedging instrument's effectiveness will be assessed. At the inception of the hedge and on an ongoing basis, we assess whether the derivatives used in hedging transactions are highly effective in offsetting changes in cash flows of hedged items. As of March 31, 2002 all open positions related to production from our oil and gas properties qualified for hedge accounting.

Unrealized gains and losses on hedging instruments reflected in OCI, and adjustments to carrying amounts on hedged volumes, are included in oil and gas revenues in the period that the related volumes are delivered. Gains and losses of hedging instruments that represent hedge ineffectiveness, as well as any amounts excluded from the assessment of hedge effectiveness, are recognized currently in oil and gas revenues. For purposes of our combined financial statements, effective October 2001 we implemented Derivatives Implementation Group, Issue G20, "Cash Flow Hedges: Assessing and Measuring the Effectiveness of a Purchased Option Used in a Cash Flow Hedge," or DIG Issue G20, which provides guidance for assessing the effectiveness on total changes in an option's cash flows rather than only on changes in the option's intrinsic value. Implementation of DIG Issue G20 has reduced earnings volatility since it allows us to include changes in the time value of purchased options and collars in the assessment of hedge effectiveness. Time value changes were previously recognized in current earnings since we excluded them from the assessment of hedge effectiveness. Oil and gas revenues for the year ended December 31, 2001 include a $3.1 million non-cash loss related to the ineffective portion of the cash flow hedges representing the fair value change in the time value of options for the nine months before the implementation of DIG Issue G20.

We utilize various derivative instruments to hedge our exposure to price fluctuations on oil sales. The derivative instruments consist primarily of cash-settled oil option and swap contracts entered into with financial institutions. We do not currently have any gas hedges. In the future, we may use interest rate swaps to manage the interest rate exposure on our long-term debt, but we do not currently do so.

On January 1, 2001, in accordance with the transition provisions of SFAS 133, we recorded a gain of $7.0 million in OCI representing the cumulative effect of an accounting change to recognize at fair value all cash flow derivatives. We recorded cash flow hedge derivative assets and liabilities of $9.7 million and $4.2 million, respectively, and a net-of-tax non-cash charge of $1.5 million was recorded in earnings as a cumulative effect adjustment.

For the three months ended March 31, 2002 net unrealized gains of $3.5 million were relieved from OCI and the fair value of open positions decreased $19.7 million.

As of March 31, 2002 net unrealized losses on our option and swap contracts included in OCI was $7.3 million. The related assets and liabilities were included in current assets ($0.7 million), current liabilities ($10.1 million), other liabilities ($1.8 million) and deferred

32

income taxes ($4.7 million). As of March 31, 2002 $5.8 million of deferred net losses on derivative instruments recorded in OCI were expected to be reclassified to earnings during the next twelve-month period.

COMMODITY PRICE RISK. As of May 31, 2002, we had the following open oil hedge positions with respect to our oil properties:

                                                                BBLS PER DAY
                                                --------------------------------------------
                                                                            2002
                                                                 ---------------------------
                                                2004     2003    4TH QTR   3RD QTR   2ND QTR
                                                -----   ------   -------   -------   -------
Puts:
  Average price $22.00/Bbl....................     --    2,000       --        --        --
Calls:
  Average price $35.17/Bbl....................     --       --    9,000     9,000     9,000
  Average price $27.04/Bbl....................     --    2,000       --        --        --
Swaps:
  Average price $24.14/Bbl....................     --       --       --        --    19,000
  Average price $24.10/Bbl....................     --       --       --    19,000        --
  Average price $24.09/Bbl....................     --       --   19,000        --        --
  Average price $23.31/Bbl....................     --   14,750       --        --        --
  Average price $23.02/Bbl....................  5,000       --       --        --        --

These positions provide for us to receive for the nine months ended December 31, 2002 an average fixed NYMEX price of approximately $24.11 per Bbl on 19,000 Bbls per day with upside participation above $35.17 per Bbl on 47% of those hedged barrels. For example, if the NYMEX index average is $30.00 per Bbl, we will receive $24.11 per Bbl and if the NYMEX index average were to fall to $15.00 per Bbl, we would receive $24.11 per Bbl, on all the hedged barrels. For 2003, we have entered into various arrangements that entitle us to receive an average minimum NYMEX price of $23.15 per Bbl on 16,750 Bbls per day, with full upside participation to $27.04 per Bbl on 12% of those hedged barrels. For 2004, we have entered into various arrangements that entitle us to receive an average fixed NYMEX price of $23.02 per Bbl on 5,000 Bbls per day, regardless of the NYMEX index average. Location and quality differentials attributable to our properties and the cost of the hedges are not included in the foregoing prices. Because of the quality and location of our oil production, these adjustments will reduce our net price per Bbl.

The agreements provide for monthly cash settlement based on the differential between the agreement price and the actual NYMEX price. Gains or losses are recognized in the month of related production and are included in oil and gas sales revenues. These contracts resulted in an increase in revenues of $3.4 million in the first quarter of 2002 and a reduction in revenues of $3.7 million in the first quarter of 2001, as well as an increase (decrease) in revenues of $0.3 million, $(72.8) million and $(7.5) million for the years ended December 31, 2001, 2000 and 1999, respectively. As of March 31, 2002 we had an unrealized loss of $7.3 million, net of tax, with respect to these contracts. The estimated fair value of the hedges is included in our balance sheet as of March 31, 2002.

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The fair value of outstanding oil derivative commodity instruments and the change in fair value that would be expected from a 10% price decrease are shown in the table below (in millions):

                                                        AS OF MARCH 31,
                                   ---------------------------------------------------------
                                              2002                          2001
                                   ---------------------------   ---------------------------
                                      FAIR      EFFECT OF 10%       FAIR      EFFECT OF 10%
                                     VALUE      PRICE DECREASE     VALUE      PRICE DECREASE
                                   ----------   --------------   ----------   --------------
Swaps and options contracts......   $(11,285)      $23,342         $4,352        $17,529

The fair value of the swaps and option contracts are estimated based on quoted prices from independent reporting services compared to the contract price of the swap, and approximate the gain or loss that would have been realized if the contracts had been closed out at quarters end. All hedge positions offset physical positions exposed to the cash market. None of these offsetting physical positions are included in the above table. Price risk sensitivities were calculated by assuming an across-the-board 10% decrease in price regardless of term or historical relationships between the contractual price of the instruments and the underlying commodity price. In the event of an actual 10% change in prompt month oil prices, the fair value of our derivative portfolio would typically change less than that shown in the table due to lower volatility in out-month prices.

The contract counterparties for our derivative commodity contracts are all major financial institutions with Standard & Poor's ratings of A or better. Two of the financial institutions will be participating lenders in our revolving credit facility, with one counterparty holding contracts that represent approximately 33% of the fair value of all open positions as of March 31, 2002.

Our management intends to continue to maintain hedging arrangements for a significant portion of our production. These contracts may expose us to the risk of financial loss in certain circumstances. Our hedging arrangements provide us protection on the hedged volumes if oil prices decline below the prices at which these hedges are set, but ceiling prices in our hedges may cause us to receive less revenues on the hedged volumes than we would receive in the absence of hedges.

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BUSINESS

OVERVIEW

We are an independent oil and gas company primarily engaged in the upstream activities of acquiring, exploiting, developing and producing oil and gas in the United States. We are 100% owned by Plains Resources Inc. Our core areas of operation are:

- onshore California, primarily in the LA Basin, and offshore California in the Point Arguello unit; and

- the Illinois Basin in southern Illinois.

We own a 100% working interest in and operate all of our properties, except for offshore California, in which we own a 26.3% working interest and where we are the operator. Our reserves are generally mature but underdeveloped, have produced significant volumes since initial discovery and have significant estimated remaining reserves. We opportunistically hedge portions of our oil production to manage our exposure to commodity price risk. For the twelve months ended March 31, 2002 we generated revenues of $191.0 million and EBITDA, as defined, of $118.0 million.

The following table sets forth information with respect to our oil and gas properties as of and for the year ended December 31, 2001:

                                                     CALIFORNIA
                                                 -------------------   ILLINOIS BASIN
                                                 ONSHORE    OFFSHORE     AND OTHER      TOTAL
                                                 -------    --------   --------------   -----
                                                             (DOLLARS IN MILLIONS)
Proved reserves
  MMBOE........................................   211.8(1)      5.0              22.5    239.3
  Percent oil..................................     93%         98%               98%      93%
Proved developed reserves (MMBOE)..............   112.0         3.8              13.3    129.1
Production (MBOE)..............................   6,347       1,431             1,000    8,778
PV-10(2).......................................  $577.7      $  6.9            $ 58.6   $643.2

(1) Approximately 8.8 MMBOE of our proved reserves in the LA Basin properties are subject to a 50% net profits interest.

(2) Based on year-end 2001 spot market prices of $19.84 per Bbl of oil and $2.58 per Mcf of gas. We have reduced the PV-10 of proved reserves of certain properties to reflect applicable abandonment costs and, with respect to the LA Basin properties, the net profits interest referenced in note 1.

During the five-year period ended December 31, 2001 we drilled 561 development wells with a 99.5% success rate. During this period, we incurred aggregate oil and gas acquisition, exploitation, development and exploration costs of $442.9 million, resulting in proved reserve additions of 177.9 MMBOE, at an average reserve replacement cost of $2.49 per BOE, which we believe to be among the lowest of our peer group. Approximately 99% of our oil and gas capital expenditures was for acquisition, exploitation and development activities.

COMPETITIVE STRENGTHS

QUALITY ASSET BASE WITH LONG RESERVE LIFE. We had estimated total proved reserves of 239.3 MMBOE as of December 31, 2001, of which 93% was comprised of oil and 54% was proved developed. We have a reserve life of over 27 years and a proved developed reserve life of over 14 years. We believe our long-lived, low production decline reserve base combined with our active hedging strategy should provide us with relatively stable and recurring cash flow. As of December 31, 2001 and based on year-end 2001 spot market prices of $19.84 per Bbl of oil and $2.58 per Mcf of gas, our reserves had a PV-10 of $643.2 million.

EFFICIENT OPERATIONS WITH 100% OPERATORSHIP. We own a 100% working interest in and operate all of our properties, except for offshore California, in which we own a 26.3% working

35

interest and where we are the operator. As a result, we benefit from economies of scale and control the level, timing and allocation of substantially all of our capital expenditures and expenses. We believe this gives us more flexibility than many of our peers to opportunistically pursue exploitation and development projects relating to our properties.

LARGE EXPLOITATION AND DEVELOPMENT INVENTORY. We have a large inventory of projects in our core areas that we believe will support at least five years of exploitation and development activity. Over the last five years, we have achieved a high success rate on these types of projects, drilling a total of 561 development wells with a 99.5% success rate. In addition, we have completed numerous other production enhancement projects, such as recompletions, workovers and upgrades. The results of these activities over the last five years have been additions to proved reserves, excluding reserves added through acquisition activities, totaling 120.6 MMBOE, or approximately 332% of cumulative net production for this period. Reserve replacement costs, excluding acquisitions, have averaged approximately $3.17 per BOE for the same period.

EXPERIENCED AND PROVEN MANAGEMENT AND OPERATIONS TEAM. Our executive management team has an average of 20 years of experience in the oil and gas industry. The Chief Executive Officer of our parent, Plains Resources, is James Flores, who founded Flores & Rucks Incorporated, a predecessor of Ocean Energy, Inc., and was President and Chief Executive Officer of Ocean Energy from July 1995 until March 1999. Mr. Flores served as Chairman of the Board of Ocean Energy from March 1999 until January 2000, and as Vice Chairman from January 2000 until January 2001. The executive management of Plains Resources is supported by a core team of 23 technical and operating managers who have worked with our properties for many years and have an average of 22 years of experience in the oil and gas industry.

STRATEGY

Our strategy is to continue to grow our cash flow from operations and to use this cash flow to increase our proved developed reserves and production, acquire additional underdeveloped oil and gas properties and make other strategic acquisitions. We intend to implement our strategy as follows:

CONTINUE EXPLOITATION AND DEVELOPMENT OF CURRENT ASSET BASE. We believe that we have a proven track record of exploiting underdeveloped properties to increase reserves and cash flow. We focus on implementing improved production practices and recovery techniques, and relatively low-risk development drilling. An example of our success in exploiting underdeveloped properties can be found in our Montebello field located in the LA Basin. Since our acquisition of this field in March 1997, our exploitation and development activities have resulted in an increase in our net average production from approximately 930 BOE per day at the time of acquisition to approximately 2,400 BOE per day during the first quarter of 2002, representing a compound annual growth rate of over 20%.

PURSUE ADDITIONAL GROWTH OPPORTUNITIES. We believe we can continue our strong reserve and production growth through the exploitation and development of our existing inventory of projects relating to our properties. We also intend to be opportunistic in pursuing selective acquisitions of oil or gas properties or exploration projects, for example, during periods of weak commodity prices. We will consider opportunities located in our current core areas of operation as well as projects in other areas in North America that meet our investment criteria.

MAINTAIN LONG-TERM HEDGING PROGRAM. We actively manage our exposure to commodity price fluctuations by hedging significant portions of our oil production through the use of swaps, collars and purchased puts and calls. The level of our hedging activity depends on our view of market conditions, available hedge prices and our operating strategy. Under our hedging program, we typically hedge approximately 70-75% of our production for the current year, 40- 50% of our production for the next year and up to 25% of our production for the following year.

36

For example, as of March 31, 2002 we had hedged approximately 80% of forecasted production for the remainder of 2002 and approximately 50% of forecasted production for 2003.

RECENT DEVELOPMENTS

Our parent is Plains Resources Inc., which, in addition to owning us, owns an aggregate 29% ownership interest in PAA, including 44% of the general partner of PAA. PAA is a publicly traded master limited partnership that is engaged in the midstream activities of marketing, transportation and terminalling of oil and marketing liquified petroleum gas. Plains Resources also owns interests in oil and gas properties in Florida, which included 17.3 MMBOE of proved oil reserves as of December 31, 2001.

On May 22, 2002 Plains Resources received a favorable private letter ruling from the IRS stating that, for United States federal income tax purposes, a distribution by Plains Resources of the Plains Exploration & Production capital stock owned by it to its stockholders will generally be tax-free to both Plains Resources and its stockholders. Prior to completing the spin-off, we intend to seek a supplemental private letter ruling from the IRS that this offering will not affect our earlier ruling. If we complete this offering, we expect the spin-off to occur within the following twelve months. If we do not complete this offering, Plains Resources may still decide to proceed with the spin-off.

The spin-off will, among other things:

- generally divide Plains Resources' midstream and upstream assets into two separate platforms;

- allow Plains Resources and us to focus corporate strategies and management teams for each business; and

- simplify Plains Resources' and our corporate structure.

Any decision to pursue the spin-off is subject to obtaining a number of regulatory and contractual third-party consents and permits, including a supplemental private letter ruling from the IRS. Accordingly, we cannot provide any assurance that the spin-off will occur.

Plains Resources will contribute to us all of the capital stock of its subsidiaries that own oil and gas properties offshore California and in Illinois. As a result, we will indirectly own our offshore California and Illinois properties in addition to our onshore California properties that we directly own. Plains Resources and its management will continue to manage our operations under the terms of a transition services agreement. If we complete a debt financing of approximately $250.0 million, Plains Resources will also contribute to us intercompany payables that we or our subsidiaries owe to it, which were $249.6 million as of March 31, 2002.

OIL AND GAS RESERVES

The following tables set forth certain information with respect to our reserves based upon reserve reports prepared by the independent petroleum consulting firms of Netherland, Sewell & Associates, Inc. and Ryder Scott Company in 2001, and H.J. Gruy and Associates, Inc., Netherland, Sewell & Associates, Inc. and Ryder Scott Company in 2000 and 1999. The reserve volumes and values were determined under the method prescribed by the SEC, which requires

37

the application of year-end prices for each year, held constant throughout the projected reserve life.

                                                              YEAR ENDED DECEMBER 31,
                                                         ----------------------------------
                                                           2001        2000         1999
                                                         --------   ----------   ----------
                                                               (DOLLARS IN THOUSANDS)
OIL (MBBLS):
Proved developed.......................................   119,248      105,679      100,758
Proved undeveloped.....................................   104,045       98,708       94,455
                                                         --------   ----------   ----------
  Total................................................   223,293      204,387      195,213
                                                         ========   ==========   ==========
GAS (MMCF):
Proved developed.......................................    59,101       52,184       49,255
Proved undeveloped.....................................    37,116       41,302       41,618
                                                         --------   ----------   ----------
  Total................................................    96,217       93,486       90,873
                                                         ========   ==========   ==========
TOTAL (MBOE)...........................................   239,329      219,968      210,359
                                                         ========   ==========   ==========
PV-10:(1)
Proved developed.......................................  $454,095   $  982,752   $  628,451
Proved undeveloped.....................................   189,125      321,430      477,907
                                                         --------   ----------   ----------
  Total................................................  $643,220   $1,304,182   $1,106,358
                                                         ========   ==========   ==========

(1) Based on year-end spot market prices of: (a) $19.84 per Bbl of oil and $2.58 per Mcf of gas for 2001; (b) $26.80 per Bbl of oil and $13.70 per Mcf of gas for 2000; and (c) $25.60 per Bbl of oil and $2.37 per Mcf of gas for 1999.

There are numerous uncertainties inherent in estimating quantities and values of proved reserves, and in projecting future rates of production and timing of development expenditures. Many of the factors that impact these estimates are beyond our control. Reservoir engineering is a subjective process of estimating the recovery from underground accumulations of oil and gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation, and judgment. Because all reserve estimates are to some degree speculative, the quantities of oil and gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures, and future oil and gas sales prices may all differ from those assumed in these estimates. In addition, different reserve engineers may make different estimates of reserve quantities and cash flows based upon the same available data. Therefore, the PV-10 shown above represents estimates only and should not be construed as the current market value of the estimated oil and gas reserves attributable to our properties.

In accordance with SEC guidelines, the reserve engineers' estimates of future net revenues from our properties, and the present value of the properties, are made using oil and gas sales prices in effect as of the dates of such estimates and are held constant throughout the life of the properties, except where the guidelines permit alternate treatment, including the use of fixed and determinable contractual price escalations but excluding the effect of any hedges we have in place. The prices used in our reserve reports as of December 31, 2001 of $15.31 per Bbl of oil and $2.56 per Mcf of gas reflect the year-end spot market prices of $19.84 per Bbl of oil and $2.58 per Mcf of gas, as adjusted for variations based on location and quality of oil. Historically, the prices for oil and gas have been volatile and are likely to continue to be volatile in the future.

EXPLOITATION AND DEVELOPMENT

EXPLOITATION STRATEGY. We implement our exploitation plan with respect to our properties by:

- enhancing product price realizations;

- optimizing production practices;

- realigning and expanding injection processes;

38

- drilling wells; and

- performing stimulations, recompletions, artificial lift upgrades and other operating margin and reserve enhancements.

After we acquire a property, we may also seek to increase our interest in the property by acquiring offsetting acreage, pursuing farm-in drilling arrangements and purchasing minority interests in the property.

By implementing our exploitation plan, we seek to increase cash flows and enhance the value of our asset base. In doing so, we add to and enhance our proved reserves. During the five-year period ended December 31, 2001 our additions to proved reserves totaled 120.6 MMBOE, or approximately 332% of cumulative net production for this period. We added these reserves at an aggregate average cost of $3.17 per BOE, excluding reserves added as a result of our acquisition activities. Reserve additions related solely to our acquisition activities totaled 57.3 MMBOE and were added at an aggregate average cost of $1.06 per BOE.

We believe that our properties in our core areas hold potential for additional increases in production, reserves and cash flow. However, we can give no assurance that increases will be achieved.

During 2002, we expect to spend approximately $61.0 million maintaining, developing and exploiting our oil and gas properties and pursuing acquisition opportunities. We expect approximately $45.0 million of these capital expenditures will be for exploitation projects in onshore California. The 2002 capital program incorporates the results of various analyses and field studies and includes our drilling approximately 87 total wells, including 10 injection wells and numerous injection realignment related workovers. During the three months ended March 31, 2002 capital expenditures for these activities was $23.9 million.

EXPLOITATION PROJECTS. The following table sets forth information with respect to our oil and gas properties (dollars in millions):

                                                ONSHORE CALIFORNIA PROPERTIES
                                          -----------------------------------------
                                                                  ARROYO               OFFSHORE    ILLINOIS BASIN
                                          LA BASIN   MONTEBELLO   GRANDE   MT. POSO   CALIFORNIA     AND OTHER
                                          --------   ----------   ------   --------   ----------   --------------
                                                                  (DOLLARS IN THOUSANDS)
Year(s) discovered......................  1924-66        1917       1906      1926       1981            1905
Year acquired...........................     1992        1997       1997      1998       1999            1995
Proved reserves at acquisition (MMBOE)..     17.7        23.3       19.9       7.7        6.4            17.3
AS OF DECEMBER 31, 2001:
Proved reserves MMBOE...................    114.0(1)     27.6       60.8       9.3        5.0            21.1
  Percent oil...........................      91%         97%        93%      100%        98%             98%
Proved developed reserves (MMBOE).......     79.9        15.5       12.0       4.6        3.8            13.3
PV-10(2)................................  $ 357.7      $ 71.4     $126.1    $ 22.5      $ 6.9          $ 58.6

(1) Approximately 8.8 MMBOE of our proved reserves in the LA Basin properties as of December 31, 2001 were subject to a 50% net profits interest.

(2) Based on year-end 2001 spot market prices of $19.84 per Bbl of oil and $2.58 per Mcf of gas. We have reduced the PV-10 of proved reserves of certain properties to reflect applicable abandonment costs and, with respect to the LA Basin properties, the net profits interest referenced in note 1.

ONSHORE CALIFORNIA

LA BASIN. In 1992 we acquired from Chevron U.S.A., Inc. substantially all of its producing oil properties in the LA Basin. These interests included the Inglewood, East Beverly Hills, San Vicente and South Salt Lake fields. Following the initial acquisition we expanded our holdings in this area by acquiring additional interests within the existing fields, including all of Texaco Exploration and Production, Inc.'s interest in its Vickers lease, which further consolidated our holdings in the Inglewood field. We refer to all of our properties in the LA Basin acquired

39

before 1997 collectively as the "LA Basin properties". We hold a 100% working interest in the LA Basin properties.

The LA Basin properties consist of oil reserves discovered at various times between 1924 and 1966. We have performed various exploitation activities, including drilling additional production and injection wells, returning previously marginal wells to economic production, optimizing pre-existing waterflood operations, initiating new waterfloods, optimizing artificial lift, increasing the capacity and efficiency of facilities, upgrading facilities to maintain regulatory compliance, reducing unit production expenses and improving marketing margins. Additionally, we continuously update and perform technical studies to identify new investment opportunities on these properties. Through these acquisition and exploitation activities, our net average daily production from this area has increased from approximately 6,700 BOE per day in 1992 to 11,700 BOE per day in the first quarter of 2002.

In 2001 we spent $66.8 million on capital projects on the LA Basin properties, the most significant of which were drilling 42 production and 15 injection wells. In 2002 we expect to spend $32.0 million on capital projects, which will include drilling 22 production wells and four injection wells, performing numerous recompletions and workovers, and modifying various production and injection facilities.

In March 1997 we expanded our operations in the LA Basin by acquiring Chevron USA's interest in the Montebello field, which included a 100% working interest (99.2% net revenue interest) in 55 producing oil wells and related facilities and approximately 450 acres of surface fee land. Our net average daily production from this field has increased from 930 BOE per day at the time of acquisition to 2,400 BOE per day in the first quarter of 2002. Since the acquisition, we have drilled a total of 48 producing wells and 22 injection wells. During 2000, we evaluated the field reservoir information and prepared a comprehensive waterflood development plan. In 2001 we spent $13.0 million on capital projects in the Montebello field, the most significant of which was drilling 17 production and six injection wells. In 2002 we expect to spend $11.0 million on capital projects, which include drilling 12 production wells and six injection wells, performing numerous workovers and increasing the capacity of the production and injection facilities.

ARROYO GRANDE. In November 1997 we acquired a 100% working interest (97% net revenue interest) in the Arroyo Grande field located in San Luis Obispo County, California, from subsidiaries of Shell Oil Company. We also acquired surface and related development rights to approximately 1,000 acres included in the 1,500-acre producing unit. The field is primarily under continuous steam injection and, at our acquisition date, was producing approximately 1,600 BOE per day (approximately 1,500 BOE net to our interest) of 14 degree API gravity oil from 70 wells. Since acquiring this property, we have drilled additional wells to downsize the injection patterns in the currently developed area from five acres to one and a quarter acres to accelerate recoveries, and realigned steam injection within these areas to increase the efficiency of the recovery process. We also curtailed steam injection by about 50% immediately following the acquisition due to low oil prices. Although oil prices subsequently rebounded, we maintained injection at this low rate pending our analysis of the saturation inputs provided by the infill drilling program, and in 2001 due to excessive gas fuel costs. As a result, base volumes declined considerably, but this decline was offset by the wells we drilled to downsize the injection patterns.

In 2001 we spent $10.6 million on capital projects in the Arroyo Grande field, the most significant of which was drilling 19 production and 11 injection wells and installing a gas processing facility to reduce third-party fuel gas purchases. In 2002 we expect to spend $1.0 million on capital projects, which include recompleting five wells. We also plan to increase steam injection to near pre-acquisition levels in 2002. Our net average daily production from this field was approximately 2,000 BOE per day during the first quarter of 2002.

40

MT. POSO. During 1998 we acquired the Mt. Poso field from Aera Energy LLC. The Mt. Poso field is located near Bakersfield, California, in Kern County. When we acquired the field, it was producing 900 BOE per day of 15 to 17 degree API gravity oil and added 7.7 MMBOE to our proved reserves. Since our acquisition, we have undertaken an aggressive recompletion and drilling program targeting the Pyramid Hills formation. In 2001 we spent $10.3 million on capital projects in the Mt. Poso field, the most significant of which was drilling 43 production wells and recompleting 38 wells. In 2002 we expect to spend $1.0 million on capital projects to optimize the producing infrastructure. Our net average daily production from this field was 1,800 BOE during the first quarter of 2002.

OFFSHORE CALIFORNIA

POINT ARGUELLO. In July 1999 we acquired Chevron USA's 26.3% working interest in the Point Arguello unit and the various partnerships owning the related transportation, processing and marketing infrastructure. We are the operator for the Point Arguello unit which consists of three offshore platforms. Chevron USA retained abandonment costs, including: (1) removing, dismantling and disposing of the existing offshore platforms; (2) removing and disposing of all existing pipelines; and (3) removing, dismantling, disposing and remediating all existing onshore facilities. We assumed Chevron USA's 26.3% share of all other abandonment costs. We estimate the approximate cost of our abandonment obligations to be $7.4 million.

In 2001 we spent $5.6 million on capital projects in the Point Arguello unit, the most significant of which was drilling six production wells and a number of recompletion and stimulation workovers. In 2002 we expect to spend $5.0 million on capital projects, which include converting five wells to electric submersible lift systems, and various recompletions and stimulations.

At the time we acquired our interest in Point Arguello, our net average daily production from this unit was 5,200 BOE. During the first quarter of 2002 our net average daily production was 3,700 Bbls.

ROCKY POINT. In July 1999 we also acquired Chevron USA's 26.3% leasehold interest in the Rocky Point unit, which is adjacent to the Point Arguello unit. We are the operator for the Rocky Point unit. We are currently seeking regulatory approval to allow near-term development of the Rocky Point unit by drilling extended-reach wells from the Point Arguello platforms. While we must obtain a larger rig and several regulatory permits and other agreements among the working interest owners, we believe that if we resolve these issues, we may be able to drill in the Rocky Point unit. There can be no assurance, however, that any such drilling can or will occur.

ILLINOIS BASIN

In December 1995 we acquired our properties in the Illinois Basin, which produced an average of 2,700 Bbls of oil per day in 2001 and accounted for 11% of our total sales volumes. In 2001 we spent $12.5 million on capital projects in the Illinois Basin, the most significant of which was drilling 42 production and nine injection wells and various water injection realignment projects. In 2002, we expect to spend $6.0 million on capital projects, which include drilling 38 development wells. Our production from the Illinois Basin averaged 2,600 Bbls of oil per day in the first quarter of 2002.

OTHER

Our 2001 capital expenditures includes $13.9 million of capitalized interest and general and administrative costs allocable directly to acquisition, exploitation and development activities and $2.0 million related to other projects. Our 2002 estimated capital expenditures include $12.0 million of capitalized interest and general and administrative costs allocable directly to acquisition, exploitation and development activities and $5.0 million attributable to other projects.

41

EXPLORATION AND ACQUISITION EXPENDITURES

The following table summarizes the costs incurred during the last three years for our exploitation and development, exploration and acquisition activities.

                                                               YEAR ENDED DECEMBER 31,
                                                            ------------------------------
                                                              2001       2000       1999
                                                            --------   --------   --------
                                                                (DOLLARS IN THOUSANDS)
Exploitation and development costs........................  $123,778   $ 68,186   $ 54,996
Exploration costs.........................................       286        293        796
Property acquisition costs:
  Unproved properties.....................................        44         73        879
  Proved properties.......................................     1,645      1,953      2,496
                                                            --------   --------   --------
Total.....................................................  $125,753   $ 70,505   $ 59,167
                                                            ========   ========   ========

PRODUCTION AND SALES

The following table presents information with respect to oil and gas production attributable to our properties, the revenues we derived from the sale of this production, average sales prices we received and our average production expenses during the three months ended March 31, 2002 and 2001, and the years ended December 31, 2001, 2000 and 1999.

                                          THREE MONTHS
                                         ENDED MARCH 31,       YEAR ENDED DECEMBER 31,
                                        -----------------   ------------------------------
                                         2002      2001       2001       2000       1999
                                        -------   -------   --------   --------   --------
PRODUCTION:
Oil (MBbls)...........................    2,033     1,920      8,219      7,654      7,081
Gas (MMcf)............................      877       745      3,355      3,042      3,163
Total (MBOE)..........................    2,179     2,044      8,778      8,161      7,608
OIL AND GAS REVENUES (DOLLARS IN
  THOUSANDS):
Oil...................................  $38,685   $42,601   $174,895   $126,434   $102,390
Gas...................................    1,988    11,172     28,771     16,017      5,095
Other(1)..............................       --        --        473         --         --
                                        -------   -------   --------   --------   --------
     Total revenues...................  $40,673   $53,773   $204,139   $142,451   $107,485
                                        =======   =======   ========   ========   ========
AVERAGE REALIZED PRICES (HEDGED):
Oil...................................  $ 19.03   $ 22.19   $  21.28   $  16.52   $  14.46
Gas ($/Mcf)...........................     2.27     15.00       8.58       5.26       1.61
BOE...................................    18.67     26.31      23.20      17.46      14.13
EXPENSES ($/BOE):
Average production expenses...........  $  7.91   $  6.54   $   7.27   $   6.89   $   6.64
General and administrative(2).........     1.03      1.36       0.86       0.77       0.57
Depletion, depreciation and
  amortization........................     3.04      2.58       2.70       2.25       1.72

(1) Other revenues represents electricity related sales.

(2) Excludes noncash compensation.

Pursuant to an oil marketing agreement, PAA is the exclusive purchaser of all of our equity oil production. Plains Resources owns a 29% interest in PAA.

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PRODUCT MARKETS AND MAJOR CUSTOMERS

Our revenues are highly dependent upon the prices of, and demand for, oil and gas. Historically, the markets for oil and gas have been volatile and are likely to continue to be volatile in the future. The prices we receive for our oil and gas production and the levels of our production are subject to wide fluctuations and depend on numerous factors beyond our control, including seasonality, economic conditions, foreign imports, political conditions in other oil-producing and gas-producing countries, the actions of OPEC, and domestic government regulation, legislation and policies. Decreases in oil and gas prices have had, and could have in the future, an adverse effect on the carrying value of our proved reserves and our revenues, profitability and cash flow.

To manage our exposure to commodity price risks, we use various derivative instruments to hedge our exposure to price fluctuations on oil sales. Our hedging arrangements provide us protection on the hedged volumes if oil prices decline below the prices at which these hedges are set. However, ceiling prices in our hedges may cause us to receive less revenues on the hedged volumes than we would receive in the absence of hedges. We do not currently have any gas hedges.

Deregulation of gas prices has increased competition and volatility of gas prices. Prices received for our gas are subject to seasonal variations and other fluctuations. All of our gas production is currently sold under various arrangements at spot indexed prices.

Substantially all of our oil and gas production is transported by pipelines, trucks and barges owned by third parties. The inability or unwillingness of these parties to provide transportation services to us for a reasonable fee could result in our having to find transportation alternatives, increased transportation costs or involuntary decreases in a significant portion of our oil and gas production.

Pursuant to an oil marketing agreement, PAA is the exclusive purchaser of all of our equity oil production. If we were to lose PAA as the exclusive purchaser of our equity production, we believe such loss would not have a material adverse effect on our results of operations. We believe PAA could be replaced by other purchasers under contracts with similar terms and conditions.

PRODUCTIVE WELLS AND ACREAGE

As of December 31, 2001 we had working interests in 2,057 gross (2,031 net) active producing oil wells. The following table sets forth information with respect to our developed and undeveloped acreage as of December 31, 2001.

                                                                 DECEMBER 31, 2001
                                                        -----------------------------------
                                                        DEVELOPED ACRES   UNDEVELOPED ACRES
                                                        ---------------   -----------------
                                                        GROSS     NET      GROSS     NET(1)
                                                        ------   ------   -------    ------
Onshore California....................................   8,889    8,844     8,928     5,296
Offshore California(2)................................  15,326    4,033    41,720     1,449
Illinois and other....................................  17,777   15,482    69,360    49,101
                                                        ------   ------   -------    ------
  Total...............................................  41,992   28,359   120,008    55,846
                                                        ======   ======   =======    ======

(1) Less than 10% of total net undeveloped acres are covered by leases that expire from 2002 through 2004.

(2) Excludes 6,200 acres that we have the right to acquire a 26.315% interest in under an option agreement.

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DRILLING ACTIVITIES

Information with regard to our developmental well drilling activities during the years ended December 31, 2001, 2000 and 1999 is set forth below:

                                                         YEAR ENDED DECEMBER 31,
                                              ---------------------------------------------
                                                  2001            2000            1999
                                              -------------   -------------   -------------
                                              GROSS    NET    GROSS    NET    GROSS    NET
                                              -----   -----   -----   -----   -----   -----
Development wells:
Oil.........................................  168.0   163.4   156.0   154.0   105.0   105.0
Gas.........................................    --       --     --       --     --       --
Dry.........................................   1.0      1.0    2.0      2.0     --       --
                                              -----   -----   -----   -----   -----   -----
     Total..................................  169.0   164.4   158.0   156.0   105.0   105.0
                                              =====   =====   =====   =====   =====   =====

REAL ESTATE

We currently own surface and mineral rights in the following tracts of real property, portions of which are used in our oil and gas operations:

                                                                                  APPROXIMATE
PROPERTY                                                  LOCATION                  ACREAGE
--------                                                  --------                -----------
Inglewood..................................  Los Angeles County, California                40
Montebello.................................  Los Angeles County, California               450
Arroyo Grande..............................  San Luis Obispo County, California         1,045
Mt. Poso...................................  Kern County, California                    1,230
Gaviota....................................  Santa Barbara County, California             160

In the course of our business, certain of our properties may be subject to easements or other incidental property rights and legal requirements that may affect the use and enjoyment of our property. For instance, 183 of our acres in the Montebello field have been designated as California Coastal Sage Scrub.

TITLE TO PROPERTIES

Our properties are subject to customary royalty interests, liens incident to operating agreements, liens for current taxes and other burdens, including other mineral encumbrances and restrictions. We do not believe that any of these burdens materially interfere with our use of the properties in the operation of our business.

We believe that we have generally satisfactory title to or rights in all of our producing properties. As is customary in the oil and gas industry, we make minimal investigation of title at the time we acquire undeveloped properties. We make title investigations and receive title opinions of local counsel only before we commence drilling operations. We believe that we have satisfactory title to all of our other assets. Although title to our properties is subject to encumbrances in certain cases, we believe that none of these burdens will materially detract from the value of our properties or from our interest therein or will materially interfere with our use in the operation of our business.

COMPETITION

Our competitors include major integrated oil and gas companies and numerous independent oil and gas companies, individuals and drilling and income programs. Many of our larger competitors possess and employ financial and personnel resources substantially greater than ours. These competitors are able to pay more for productive oil and gas properties and exploratory prospects and to define, evaluate, bid for and purchase a greater number of

44

properties and prospects than our financial or human resources permit. Our ability to acquire additional properties and to discover reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, there is substantial competition for capital available for investment in the oil and gas industry.

REGULATION

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

OSHA. We are subject to the requirements of the federal Occupational Safety and Health Act, as amended, or OSHA, and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard, the United States Environmental Protection Agency community-right-to-know regulations, and similar state statutes require that we maintain certain information about hazardous materials used or produced in our operations and that we provide this information to our employees, state and local government authorities and citizens. We believe that our operations are in substantial compliance with OSHA requirements, including general industry standards, record keeping requirements and monitoring of occupational exposure to regulated substances.

Regulation of production. The production of oil and gas is subject to regulation under a wide range of federal and state statutes, rules, orders and regulations. State and federal statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations. The states in which we own and operate properties have regulations governing conservation matters, including provisions for the unitization or pooling of oil and gas properties, the establishment of maximum rates of production from oil and gas wells and the regulation of the spacing, plugging and abandonment of wells. Many states also restrict production to the market demand for oil and gas, and several states have indicated interest in revising applicable regulations. These regulations limit the amount of oil and gas we can produce from our wells and limit the number of wells or the locations at which we can drill. Also, each state generally imposes an ad valorem, production or severance tax with respect to production and sale of oil, gas and natural gas liquids within its jurisdiction.

Pipeline regulation. We have pipelines to deliver our production to sales points. Our pipelines are subject to regulation by the United States Department of Transportation with respect to the design, installation, testing, construction, operation, replacement, and management of pipeline facilities. In addition, we must permit access to and copying of records, and must make certain reports and provide information, as required by the Secretary of Transportation. The states in which we have pipelines have comparable regulations. Some of our pipelines related to the Point Arguello unit are also subject to regulation by the Federal Energy Regulatory Commission, or FERC. We believe that our pipeline operations are in substantial compliance with applicable requirements.

Sale of gas. The FERC regulates interstate gas pipeline transportation rates and service conditions. Although the FERC does not regulate gas producers such as us, the agency's actions are intended to foster increased competition within all phases of the gas industry. To date, the

45

FERC's pro-competition policies have not materially affected our business or operations. It is unclear what impact, if any, future rules or increased competition within the gas industry will have on our gas sales efforts.

The FERC, the United States Congress or state regulatory agencies may consider additional proposals or proceedings that might affect the gas industry. We cannot predict when or if these proposals will become effective or any effect they may have on our operations. We do not believe, however, that any of these proposals will affect us any differently than other gas producers with which we compete.

Environmental. Our operations and properties are subject to extensive and changing federal, state and local laws and regulations relating to safety, health and environmental protection, including the generation, storage, handling, emission and transportation of materials and the discharge of materials into the environment. These laws and regulations may require the acquisition of a permit or other authorization before construction or drilling commences and for certain other activities; limit or prohibit construction, drilling and other activities on certain lands lying within wilderness or wetlands and other protected areas; and impose substantial liabilities for pollution resulting from our operations. The permits required for various of our operations are subject to revocation, modification and renewal by issuing authorities.

As with our industry generally, our compliance with existing and anticipated laws and regulations increases our overall cost of business, including our capital costs to construct, maintain, upgrade and close equipment and facilities. Although these regulations affect our capital expenditures and earnings, we believe that they do not affect our competitive position because our competitors that comply with such laws and regulations are similarly affected, except as discussed in "Risk Factors--Environmental liabilities could adversely affect our financial condition". Environmental laws and regulations have historically been subject to change, and we are unable to predict the ongoing cost to us of complying with these laws and regulations or the future impact of these laws and regulations on our operations. If a person violates these environmental laws and regulations and any related permits, they may be subject to significant administrative, civil and criminal penalties, injunctions and construction bans or delays. If we were to discharge hydrocarbons or hazardous substances into the environment, we could, to the extent the event is not insured, incur substantial expense, including both the cost to comply with applicable laws and regulations and claims made by neighboring landowners and other third parties for personal injury and property damage. For additional information, see "Risk Factors--Environmental liabilities could adversely affect our financial condition".

LEGAL PROCEEDINGS

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

EMPLOYEES

As of March 31, 2002 we had 245 full-time employees, 197 of whom were field personnel involved in oil and gas producing activities. In addition, we use the services of 55 employees through a management agreement with Plains Resources. We believe our relationship with our employees is good. None of our or Plains Resources' employees is represented by a labor union.

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MANAGEMENT

PLAINS RESOURCES' EXECUTIVE OFFICERS AND DIRECTORS

All of the individuals who perform the day-to-day financial, administrative, and accounting functions for us, as well as those who are responsible for directing and controlling us, are currently employed by Plains Resources. In addition, a portion of our operational employees, generally those associated with our Arguello unit, are also employed by Plains Resources. Under a transition services agreement between us and Plains Resources, Plains Resources charges us for these services, which require substantially all of these persons' working time. The transition services will expire when the spin-off is completed. See "Certain transactions."

The following table sets forth certain information as of the date of this prospectus regarding Plains Resources' executive officers and directors. They hold office until their successors are duly elected and qualified, or until their earlier death, removal or resignation from office.

NAME                                  AGE                          TITLE
----                                  ---                          -----
James C. Flores.....................  42    Chairman of the Board and Chief Executive Officer
John T. Raymond.....................  31    President and Chief Operating Officer
Jere C. Overdyke, Jr. ..............  50    Executive Vice President and Chief Financial Officer
Timothy T. Stephens.................  50    Executive Vice President -- Administration,
                                            Secretary and General Counsel
Cynthia Feeback.....................  44    Senior Vice President -- Accounting and Treasurer
Thomas M. Gladney...................  49    Senior Vice President of Operations
Franklin R. Bay.....................  44    Senior Vice President of Corporate Development
Jerry L. Dees.......................  62    Director
Tom H. Delimitros...................  62    Director
William M. Hitchcock................  63    Director
John H. Lollar......................  63    Director
D. Martin Phillips..................  48    Director
Robert V. Sinnott...................  53    Director
J. Taft Symonds.....................  63    Director

The following biographies describe the business experience of Plains Resources' executive officers and directors:

JAMES C. FLORES, PLAINS RESOURCES' CHAIRMAN OF THE BOARD AND CHIEF EXECUTIVE OFFICER SINCE MAY 2001. He was President and Chief Executive Officer of Ocean Energy, Inc., an oil and gas company, from July 1995 until March 1999, and a director of Ocean Energy, Inc. from 1992 until March 1999. In March 1999 Ocean Energy, Inc. was merged into Seagull Energy Corporation, which was the surviving corporation of the merger, and which was renamed Ocean Energy, Inc. Mr. Flores served as Chairman of the Board of the new Ocean Energy, Inc. from March 1999 until January 2000, and as Vice Chairman from January 2000 until January 2001.

JOHN T. RAYMOND, PLAINS RESOURCES' PRESIDENT AND CHIEF OPERATING OFFICER
SINCE NOVEMBER 2001. Previously, he was its Executive Vice President and Chief Operating Officer from May 2001 to November 2001. In addition, Mr. Raymond served as Director of Corporate Development of Kinder Morgan, Inc. from January 2000 to May 2001, and as Vice President of Corporate Development of Ocean Energy, Inc. from April 1998 to January 2000. Mr. Raymond also served as Vice President of Howard Weil Labouisse Friedrichs, Inc. from 1992 to April 1998. In addition, Mr. Raymond is a director of Plains All American GP LLC, which is the general partner of Plains AAP, L.P.

47

JERE C. OVERDYKE, PLAINS RESOURCES' EXECUTIVE VICE PRESIDENT AND CHIEF FINANCIAL OFFICER SINCE MAY 2001. From 1991 to March 2001, Mr. Overdyke served in various capacities with Enron Corp., including Managing Director of Enron Global Markets, Enron North America, Enron International, and Enron Capital and Trade Resources.

TIMOTHY T. STEPHENS, PLAINS RESOURCES' EXECUTIVE VICE

PRESIDENT -- ADMINISTRATION, SECRETARY AND GENERAL COUNSEL SINCE MAY 2001. From March 2000 to May 2001 Mr. Stephens practiced as a private business consultant to various clients. In February 1998 Mr. Stephens was hired by the board of directors of Abacan Resources Corporation, an oil and gas company, to help the company overcome significant financial difficulties. He served as Chairman, President and Chief Executive Officer of Abacan until March 2000 when the company, after a two-year restructuring, was placed into statutory receivership with the agreement of its senior creditor. Previously, Mr. Stephens was President of Seven Seas Petroleum from February 1995 to May 1997, and Vice President of Enron Capital & Trade Resources Corp. from July 1991 to February 1995.

CYNTHIA FEEBACK, PLAINS RESOURCES' SENIOR VICE PRESIDENT -- ACCOUNTING AND
TREASURER SINCE JULY 2001. She was its Vice President -- Accounting and Assistant Treasurer from May 1999 to July 2001, and its Assistant Treasurer, Controller and Principal Accounting Officer from May 1998 to May 1999. Previously, Ms. Feeback served as its Controller and Principal Accounting Officer from 1993 to 1998, Controller from 1990 to 1993, and Accounting Manager from 1988 to 1990.

THOMAS M. GLADNEY, PLAINS RESOURCES' SENIOR VICE PRESIDENT OF OPERATIONS SINCE NOVEMBER 2001. He was President of Arguello, Inc., a subsidiary of ours, from December 1999 to November 2001. From 1992 to September 1998 he was Offshore Operations Manager for Oryx Energy Company. Previously, he served as Gulf Coast Reserve Development Manager of Oryx Energy/Sun E&P from 1988 to 1992.

FRANKLIN R. BAY, PLAINS RESOURCES' SENIOR VICE PRESIDENT OF CORPORATE DEVELOPMENT SINCE FEBRUARY 2002. Before joining Plains Resources, Mr. Bay served for five years in various capacities with Enron Corp., including Vice President of Commercial Operations for Northern Natural Gas Pipeline Company, General Counsel of the Gas Pipeline Group, and head of Enron Broadband Service's Emerging Businesses Group. His previous experience also includes serving in the first Bush Administration as the Deputy General Counsel at the Department of Energy and Deputy Legal Adviser at the State Department, and he previously served as a 2nd Lieutenant in the United States Marine Corps.

JERRY L. DEES, DIRECTOR OF PLAINS RESOURCES SINCE 1997. He retired in 1996
as Senior Vice President, Exploration and Land, for Vastar Resources, Inc. (previously ARCO Oil and Gas Company), a position he had held since 1991. From 1987 to 1991 he was Vice President of Exploration and Land for ARCO Alaska, Inc., and from 1985 to 1987 he held various positions as Exploration Manager of ARCO. From 1980 to 1985 Mr. Dees was Manager of Exploration Geophysics for Cox Oil and Gas Producers.

TOM H. DELIMITROS, DIRECTOR OF PLAINS RESOURCES SINCE 1998. He has been a General Partner of AMT Venture Funds, a venture capital firm, since 1989. He is also a director of Tetra Technologies, Inc., a specialty chemical and chemical process company. From 1983 to 1988, Mr. Delimitros was a General Partner of Sunwestern Investment Funds and Senior Vice President of Sunwestern Management, Inc.

WILLIAM H. HITCHCOCK, DIRECTOR OF PLAINS RESOURCES SINCE 1977. He is a partner and has been President, since December 1996, of Pembroke Capital LLC, an NASD investment firm. In addition, he is Chief Executive Officer of Camelot Oil & Gas, a private oil and gas company. He is also a director of Protalex Inc., a biotech company, Thoratec Laboratories Corporation, a medical device company, and Luna Imaging, Inc., a digital imaging company. From 1992 to 1995

48

Mr. Hitchcock served as President of Plains Resources International Inc., which is one of our and Plains Resources' affiliates. In addition, he was Plains Resources' Chairman of the Board from August 1981 to October 1992, except for the period from April 1987 to October 1987, when he served as its Vice Chairman.

JOHN H. LOLLAR, DIRECTOR OF PLAINS RESOURCES SINCE 1995. He has been the Managing Partner of Newgulf Exploration L.P. since December 1996. He is also a director of Lufkin Industries, Inc., a manufacturing firm. Mr. Lollar was Chairman of the Board, President and Chief Executive Officer of Cabot Oil & Gas Corporation from 1992 to 1995, and President and Chief Operating Officer of Transco Exploration Company from 1982 to 1992.

D. MARTIN PHILLIPS, DIRECTOR OF PLAINS RESOURCES SINCE 2001. He has been a Managing Director and principal of EnCap Investments L.L.C., or EnCap, a funds management and investment banking firm that focuses exclusively on the oil and gas industry, since November 1989. From 1978 to when he joined EnCap, Mr. Phillips served as Senior Vice President in the Energy Banking Group of NCNB Texas National Bank in Dallas, Texas. Mr. Phillips also serves as a director of Mission Resources Corporation, Breitburn Energy Company LLC, 3TEC Energy Corporation and the Houston Producers' Forum, of which he formerly served as president.

ROBERT V. SINNOTT, DIRECTOR OF PLAINS RESOURCES SINCE 1994. He has been Senior Vice President of Kayne Anderson Investment Management, Inc., an investment management firm, since 1992. He is also a director of Glacier Water Services, Inc., a vended water company, and Plains All American GP LLC. Mr. Sinnott was Vice President and Senior Securities Officer of the Investment Banking Division of Citibank from 1986 to 1992.

J. TAFT SYMONDS, DIRECTOR OF PLAINS RESOURCES SINCE 1987. He has been Chairman of the Board of Symonds Trust Co. Ltd., an investment firm, and Chairman of the Board of Maurice Pincoffs Company, Inc., an international marketing firm, since 1978. He is also Chairman of the Board of Tetra Technologies, Inc., a specialty chemical and chemical process company, and a director of Denali, Inc., a manufacturer of storage tanks and a product and service provider for handling of industrial fluids. Mr. Symonds is also a director of Plains All American GP LLC.

After the spin-off, we expect that Mr. Flores will become our Chairman of the Board, President and Chief Executive Officer. Mr. Overdyke will serve as Executive Vice President and Chief Financial Officer and Mr. Stephens will be our Vice President -- Administration, Secretary and General Counsel. Mr. Raymond is expected to become our Vice Chairman.

In addition, a number of existing Plains Resources' directors are expected to serve as members of our Board of Directors following the spin-off.

BOARD OF DIRECTORS

Our certificate of incorporation authorizes a board of directors consisting of at least three, but not more than nine, members, with the exact number of directors being the number within this range that may be determined from time to time by resolution of our board of directors.

COMMITTEES OF THE BOARD OF DIRECTORS

Our board of directors has established an audit committee and a compensation committee. Our board may establish other committees from time to time to facilitate our management.

Our audit committee recommends to our entire board the independent auditors to be engaged by us, reviews the plan, scope and results of our annual audit, and reviews our internal controls and financial management policies with our independent auditors. All of the members of our audit committee are non-employee directors.

49

Our compensation committee establishes guidelines and standards relating to the determination of executive compensation, reviews executive compensation policies and recommends to our entire board compensation for our executive officers and key employees. Our compensation committee also administers our equity compensation plan and determines the number of shares covered by, and terms of, grants to executive officers and key employees. All of the members of our compensation committee are non-employee directors.

COMPENSATION

COMPENSATION OF DIRECTORS

We will pay each of our directors who is not one of our employees an annual retainer of $ and we will reimburse all directors for reasonable expenses they incur while attending board and committee meetings.

EXECUTIVE COMPENSATION

Plains Resources paid all the compensation of its officers during 1999, 2000 and 2001. Under the transition services agreement between Plains Resources and us, we reimburse Plains Resources for costs incurred to provide us with management services, including general and administrative expenses and other employee costs.

OPTION GRANTS IN 2001

We did not grant any options or stock appreciation rights to our executive officers in 2001.

OPTION EXERCISES AND OPTION VALUES IN 2001

None of our executive officers held options as of the end of, or exercised options during, 2001.

We intend to enter into indemnity agreements with each of our directors and executive officers providing for the indemnification described above. We believe that these limitations on liability are essential to attracting and retaining qualified persons as directors and executive officers. We have obtained directors' and officers' liability insurance.

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PRINCIPAL STOCKHOLDER

The following table sets forth information with respect to the beneficial ownership of our common stock as of , 2002:

                                     SHARES OF         PERCENT BENEFICIALLY OWNED(1)
NAME AND ADDRESS                    COMMON STOCK      --------------------------------
OF BENEFICIAL OWNER              BENEFICIALLY OWNED   BEFORE OFFERING   AFTER OFFERING
-------------------              ------------------   ---------------   --------------
Plains Resources Inc...........                             100%                   %
500 Dallas Street
Houston, Texas 77002


(1) Assumes no exercise of the underwriters' overallotment option to purchase up to additional shares of common stock. If the underwriters' overallotment option is exercised in full, upon completion of this offering Plains Resources would beneficially own % of the outstanding common stock.

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CERTAIN TRANSACTIONS

OUR RELATIONSHIP WITH PAA

On March 31, 2002 Plains Resources owned 29% of PAA, including 44% of the general partner of PAA. We are party to the following agreements with PAA and Plains Resources:

- an omnibus agreement that provides (1) that we cannot engage in oil storage, terminalling, gathering, marketing or transportation activities in any state in the continental United States for any person other than us and (2) for the resolution of certain conflicts arising from our engaging in these activities, or with respect to marketing, at all.

- a marketing agreement that provides that PAA will purchase all of our equity oil production at market prices for a fee of $0.20 per Bbl. For the purchase of oil under the agreement, including the royalty share of production, in 2001, 2000 and 1999 PAA paid $202.1 million, $222.7 million and $114.6 million, respectively; and

- a letter agreement that provides that, if our marketing agreement with PAA terminates before the termination of PAA's oil sales agreement with Tosco Refining Co. pursuant to which PAA sells to Tosco all of the oil from our Arroyo Grande property it purchases from us, PAA will continue to purchase our equity production from our Arroyo Grande property under the same terms as our marketing agreement with PAA until the Tosco agreement terminates.

MASTER SEPARATION AGREEMENT

OVERVIEW. To effect our separation from Plains Resources, we will enter into a master separation agreement with Plains Resources simultaneous with entering into our financing. The master separation agreement provides for the separation of substantially all of the upstream assets and liabilities of Plains Resources, other than its Florida operations. The master separation agreement provides for, among other things:

- the separation;

- this offering;

- the spin-off;

- corporate governance provisions related to us;

- cross-indemnification provisions;

- allocation of fees related to these transactions between us and Plains Resources;

- other provisions governing our relationship with Plains Resources, including mandatory dispute arbitration, sharing information, confidentiality and other covenants;

- a noncompetition provision; and

- us entering into the ancillary agreements discussed below with Plains Resources.

SEPARATION. To effect the separation, prior to the Master Separation Agreement, Plains Resources will transfer to us assets and liabilities related to Plains Resources' upstream business other than its Florida operations, including the capital stock of Arguello Inc., Plains Illinois Inc., PMCT, Inc. and Plains Resources International Inc., miscellaneous upstream assets and related hedging agreements. We will assume the liabilities associated with the transferred assets and businesses. At a future date before the spin-off, Plains Resources will transfer to us additional assets and liabilities, including remaining upstream agreements and permits that require consent to transfer and office furniture and equipment, and we will sublease a portion of Plains Resources' office space. Except as set forth in the master separation agreement, no party is making any representation or warranty as to the assets or liabilities transferred as a part of the separation, and all assets are being transferred on an "as is, where is" basis.

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Plains Resources has agreed to take such further actions as we may reasonably request to more effectively complete the transfers of assets and liabilities described above, to protect and enjoy all rights and benefits Plains Resources had with respect thereto and as otherwise appropriate to carry out the transactions contemplated by the master separation agreement.

REORGANIZATION. The master separation agreement provides for an internal reorganization within Plains Resources, including:

- before this offering, our conversion into a Delaware corporation; and

- before the spin-off, the merger of Stocker Resources, Inc. into Plains Resources.

IPO. The master separation agreement provides that we and Plains Resources will use our reasonable efforts to consummate this offering. In connection with this offering, we will, among other things, file a registration statement with the SEC, enter into an underwriting agreement and list our common stock on the New York Stock Exchange. Also, we are obligated to consult with Plains Resources on pricing this offering, the timing of this offering and other material matters related to this offering. In addition, as a condition to this offering, Plains Resources must be satisfied in its sole discretion that it will own more than 80% of our outstanding common stock following this offering, control us within the meaning of Section 368(c) of the Internal Revenue Code of 1986, or the Code, and satisfy the stock ownership requirements of Section 1504(a)(2) of the Code with respect to our stock. Finally, if necessary we will enter into a registration rights agreement with Plains Resources that will provide Plains Resources with at least five demand rights, piggyback registration rights, and other ordinary and customary terms in registration rights agreements generally, including "blackout" and "lockup" provisions.

SPIN-OFF. The master separation agreement provides for the spin-off distribution by Plains Resources of our remaining common stock that it will own after completion of this offering. Plains Resources is not obligated to effect the spin-off. If Plains Resources decides to effect the spin-off, each holder of Plains Resources common stock on the record date would receive a pro rata share of the total shares of our common stock held by Plains Resources.

The master separation agreement contemplates that Plains Resources will file a supplemental private letter ruling request with the IRS to confirm that a distribution of at least 80% of the shares of our common stock following this offering would not affect the tax treatment in the original private letter ruling Plains Resources received from the IRS. If either the original ruling or the supplemental ruling is not in effect at any time before the spin-off, Plains Resources need not complete the spin-off.

CORPORATE GOVERNANCE. The master separation agreement contains several provisions regarding our corporate governance. First, after this offering, as long as Plains Resources owns shares representing at least a majority of our voting power, Plains Resources will have the right to designate for nomination by our board of directors, or a nominating committee of the board, a majority of the members of our board. If Plains Resources' beneficial ownership of our common stock is reduced to a level below 50% of our voting power but is at least 20% of our voting power, Plains Resources will have the right to designate for nomination a number of directors proportionate to its voting power. We also agree that following this offering and before the spin-off, we will obtain Plains Resources' consent before we issue any additional stock or securities convertible or exchangeable for our stock if the issuance would cause Plains Resources to fail to control us within the meaning of Section 368(c) of the Code or to satisfy the stock ownership requirements of Section 1504(a)(2) of the Code with respect to our stock.

INDEMNIFICATION. The master separation agreement provides for cross-indemnities intended to place sole financial responsibility on us for all liabilities associated with the current and historical businesses and operations we conduct after giving effect to the separation, regardless of the time those liabilities arise, and to place sole financial responsibility for liabilities associated with Plains Resources' other businesses with Plains Resources and its other subsidiaries. The

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master separation agreement also contains indemnification provisions under which we and Plains Resources each indemnify the other with respect to breaches by the indemnifying party of the master separation agreement or any of the ancillary agreements described below. We agree to indemnify Plains Resources and its other subsidiaries against liabilities arising from misstatements or omissions in the various offering documents for this offering, including this prospectus or in documents to be filed with the SEC in connection with this offering or the spin-off, except for information regarding Plains Resources provided by Plains Resources for inclusion in such documents. Plains Resources agrees to indemnify us against liabilities arising from misstatements or omissions in the various offering documents for this offering, including this prospectus or the spin-off if such information was provided by Plains Resources.

The master separation agreement contains a general release under which we will release Plains Resources and its subsidiaries, affiliates, successors and assigns, and Plains Resources will release us from any liabilities arising from events between us on the one hand, and Plains Resources or its subsidiaries on the other hand, occurring on or before the separation, including events in connection with activities to implement the separation, this offering and the spin-off. The general release does not apply to obligations under the master separation agreement or any ancillary agreement, to liabilities transferred to us, to future transactions between us and Plains Resources, or to specified contractual arrangements.

FEES. We will bear all out-of-pocket costs of the transfers of assets and liabilities in connection with the separation, including costs for providing notices of the transfers, costs for transferring licenses, permits or franchises or for issuing new licenses, permits or franchises in our name, fees or costs for the assignment or transfer of any agreements or contracts, and any recording or other fees, taxes or charges incurred in connection with transferring real property.

Except as noted above or otherwise specifically addressed in the master separation agreement or an ancillary agreement, we shall bear the out-of-pocket costs associated with preparing and consummating the transactions contemplated by the master separation agreement, the ancillary agreements, the separation, this offering and the spin-off.

OTHER PROVISIONS. The master separation agreement also provides for: (1) mandatory arbitration to settle disputes between us and Plains Resources and its subsidiaries; (2) exchange of information between Plains Resources and us for purposes of conducting our operations, meeting regulatory requirements, responding to regulatory or judicial proceedings, meeting SEC filing requirements, and other reasons; (3) coordination of the conduct of our annual audits and quarterly reviews so that we may both file our annual and quarterly reports in a timely manner; (4) preservation of legal privileges and (5) maintaining confidentiality of each other's information.

In addition, we and Plains Resources agree to use reasonable efforts to amend the omnibus agreement with PAA to terminate the noncompetition provisions therein and to enter into a new crude oil marketing agreement with PAA so that the agreement only applies to us and to add a definite term to the agreement, and other amendments.

NON-COMPETITION. The master separation agreement provides that for a period of three years, (1) Plains and its subsidiaries will be prohibited from engaging in or acquiring any business engaged in any of the "upstream" activities of acquiring, exploiting, developing, exploring for and producing crude oil and natural gas in any state in the United States (except Florida), and (2) we will be prohibited from engaging in any of the "midstream" activities of marketing, gathering, transporting, terminalling and storing crude oil and natural gas (except to the extent any such activities are ancillary to, or in support of, any of our upstream activities.)

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ANCILLARY AGREEMENTS. The master separation agreement sets forth the related agreements that we will enter into with Plains Resources, including:

- employee matters agreement;

- tax allocation agreement;

- intellectual property agreement;

- Plains Exploration & Production transition services agreement;

- Plains Resources transition services agreement; and

- technical services agreement.

EMPLOYEE MATTERS AGREEMENT

The employee matters agreement will be entered into at the same time as the master separation agreement. The employee matters agreement does not address the treatment of Messrs. Flores, Raymond, Overdyke and Stephens, whom we call the executives.

OTHER EMPLOYEES. The employee matters agreement provides that those employees who will work for us after the spin-off will be transferred to us immediately before the spin-off. Neither their transfer nor the spin-off will be treated as a termination of their employment for purposes of any benefits under any plans.

STOCK OPTIONS. Under the employee matters agreement, employees other than the executives would (1) receive options for our common stock at the time of the spin-off to replace their unvested options in Plains Resources common stock, and the terms of the original options would be preserved, and (2) retain their vested options in Plains Resources common stock, with an adjustment to reflect the spin-off.

OTHER PLANS. The employee matters agreement provides that (1) before the spin-off, we will establish a nonqualified deferred compensation plan for certain executive officers and, to the extent that any of the executives are participants in the Plains Resources deferred compensation plan, the related assets and liabilities under the Plains Resources plan would be transferred to our plan, (2) on or before the spin-off, Plains Resources would transfer its 401(k) plan and welfare benefit plans to us and would form a duplicate 401(k) plan and duplicate welfare benefit plans, and (3) at the time of the spin-off, we will establish plans that mirror the fringe benefits and company policies of Plains Resources.

OTHER. Under the employee matters agreement, Plains Resources would retain liability for all incurred but not reported claims occurring before the spin-off, and we will be liable for all claims incurred on or after the spin-off related to our employees.

TAX ALLOCATION AGREEMENT

The tax allocation agreement will be entered into at the same time as the master separation agreement. This agreement provides that, until the spin-off, we will continue to be included in Plains Resources' consolidated federal income tax group, and our federal income tax liability will be included in the consolidated federal income tax liability of Plains Resources. The amount of taxes that we will pay or receive with respect to consolidated or combined returns of Plains Resources in which we are included generally will be determined by multiplying our net taxable income included in the Plains Resources consolidated tax return by the highest marginal tax rate applicable to the income. Plains Resources would not be required to pay us for the use of our tax attributes that come into existence before the spin-off until such time as we would otherwise be able to utilize such attributes.

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Under the agreement, until the spin-off, Plains Resources would:

- continue to have all the rights of a parent of a consolidated group;

- have sole and exclusive responsibility for the preparation and filing of consolidated federal and consolidated or combined state, local and foreign income tax returns (or amended returns) although we may be required to assist in certain circumstances; and

- have the power, in its sole discretion, to contest or compromise any asserted tax adjustment or deficiency and to file, litigate or compromise any claim for refund relating to these returns; provided, that (1) with the consent of Plains Resources, we may participate in any proceedings contesting any proposed adjustment related to our activities and (2) Plains Resources will not accept or offer any settlement of issues related to our tax liabilities without our consent, which will not be unreasonably withheld.

If Plains Resources decides not to contest a proposed adjustment relating to our activities, we may at our expense contest the adjustment, but we may not settle or compromise any issues related to the tax liabilities of Plains Resources.

In general, the agreement provides that we will be included in Plains Resources' consolidated group for federal income tax purposes until the time of the spin-off. Each member of a consolidated group is jointly and severally liable for the federal income tax liability of each other member of the consolidated group. Accordingly, although this agreement allocates tax liabilities between us and Plains Resources during the period in which we are included in Plains Resources' consolidated group, we could be liable if any federal tax liability is incurred, but not discharged, by any other member of Plains Resources' consolidated group.

Under the terms of this agreement, we agree to indemnify Plains Resources if the spin-off is not tax-free to Plains Resources as a result of various actions taken by or with respect to our failure to take various actions.

In addition, we will agree that, during the three-year period following the spin-off, without the prior written consent of Plains Resources, we will not engage in transactions that could adversely affect the tax treatment of the spin-off unless we obtain a supplemental tax ruling from the IRS or a tax opinion acceptable to Plains Resources of nationally recognized tax counsel to the effect that the proposed transaction would not adversely affect the tax treatment of the spin-off or provide adequate economic security to Plains Resources to ensure we would be able to comply with our obligation under this agreement. We may not be able to control some of these events that could trigger this indemnification obligation.

We also agree to be liable for transfer taxes associated with the transfer of assets and liabilities in connection with the separation and the spinoff.

INTELLECTUAL PROPERTY AGREEMENT

The intellectual property agreement will be entered into at the same time as the master separation agreement and provides that Plains Resources will transfer to us ownership and all rights associated with certain trade names, trademarks, service marks and associated goodwill, including Arguello, Plains, Plains Energy, Plains E&P, Plains Exploration & Production, Plains Illinois, Plains Petroleum, Plains Resources, Plains Resources International, PLX, PMCT, Stocker Resources and the Plains logo. In addition, we will grant to Plains Resources a full license to use certain trade names including Plains Energy and Plains Resources, referred to as the Plains Marks, subject to certain limitations. These licenses are not transferable or assignable without our written consent, except that Plains Resources may grant its subsidiaries sublicenses to use the Plains Marks.

Plains Resources will not attempt to register a trade name or trademark that incorporates or is confusingly similar to the Plains Marks. Also, if Plains Resources develops new trademarks

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using the name "Plains," it must first obtain our written approval. We will own such new trademarks and they will be considered subject to the terms of this agreement.

The intellectual property agreement provides that Plains Resources will conform the nature and quality of its products and services offered in connection with the Plains Marks to our reasonable design and quality standards. Further, Plains Resources will use the Plains Marks only in connection with its business.

PLAINS EXPLORATION & PRODUCTION TRANSITION SERVICES AGREEMENT

The Plains Exploration & Production transition services agreement will be entered into at the same time as the master separation agreement and provides that Plains Resources will provide us the following services, on an interim basis:

- management services, including managing our operations, evaluating investment opportunities for us, overseeing our upstream activities, and staffing;

- tax services, including preparing tax returns and preparing financial statement disclosures;

- accounting services, including maintaining general ledgers, preparing financial statements and working with our auditors;

- payroll services, including payment processing and complying with regulations relating to payroll services;

- insurance services, including maintaining for the interim period the existing insurance that Plains Resources provides for us;

- employee benefits services, including administering and maintaining the employee benefit plans that cover our employees;

- legal services, including typical and customary legal services; and

- financial services, including helping us raise capital, preparing budgets and executing hedges.

Monthly, Plains Resources will charge us its costs of providing such services but that charge may not exceed $30.0 million in the aggregate during the term of the agreement.

In addition, we and Plains Resources may identify additional services that Plains Resources will provide to us under this agreement in the future. The terms and costs of these additional services will be mutually agreed upon by us and Plains Resources. Plains Resources may allow one of its subsidiaries or a qualified third party to provide the services under this agreement, but Plains Resources will be responsible for the performance of the services. To the extent that Plains Resources personnel who traditionally have provided services contemplated by the transition services agreement have been or are transferred to a similar position with us, Plains Resources will be relieved of its obligations to provide such services to us.

Plains Resources will be obligated to provide the services with substantially the same degree of care as it employs for its own operations. Plains Resources may change the manner in which it provides the services so long as it deems such change to be necessary or desirable for its own operations.

This transition services agreement provides that Plains Resources will not be liable to us with respect to the performance of the services, except in the case of gross negligence or willful misconduct in providing the services. Plains Resources will indemnify us for any liabilities arising from such gross negligence or misconduct. We will indemnify Plains Resources for any liabilities arising directly from the performance of the services by Plains Resources, except for liabilities caused by gross negligence or willful misconduct of Plains Resources. Plains Resources will disclaim all warranties and makes no representations as to the quality, suitability or adequacy of the services provided.

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Plains Resources will provide the services until the spin-off, unless we and Plains Resources decide to terminate the agreement earlier. We and Plains Resources may agree to extend this agreement to up to 180 days following the spin-off and thereafter for a period as mutually agreed.

PLAINS RESOURCES TRANSITION SERVICES AGREEMENT

The Plains Resources transition services agreement will be entered into at the same time as the master separation agreement and provides that we will provide Plains Resources the following services on an interim basis beginning on a date to be determined by both us and Plains Resources upon the transfer by Plains Resources of substantially all of its employees to us:

- tax services, including preparing tax returns and preparing financial statement disclosures;

- accounting services, including maintaining general ledgers, preparing financial statements and working with Plains Resources auditors;

- payroll services, including payment processing and complying with regulations relating to payroll services;

- employee benefits services, including administering and maintaining the employee benefit plans that cover Plains Resources' employees;

- legal services, including typical and customary legal services; and

- financial services, including helping Plains Resources raise capital, preparing budgets and executing hedges.

We will charge Plains Resources on a monthly basis our costs of providing such services.

In addition, we and Plains Resources may identify additional services that we will provide to Plains Resources under this agreement in the future. The terms and costs of these additional services will be mutually agreed upon by us and Plains Resources. We may allow one of our subsidiaries or a qualified third party to provide the services under this agreement, but we will be responsible for the performance of the services.

We will be obligated to provide the services with substantially the same degree of care as we employ for our own operations. We may change the manner in which we provide the services so long as we deem such change to be necessary or desirable for our own operations.

This transition services agreement provides that we will not be liable to Plains Resources with respect to the performance of the services, except in the case of gross negligence or willful misconduct in providing the services. We will indemnify Plains Resources for any liabilities arising from such gross negligence or misconduct. Plains Resources will indemnify us for any liabilities arising directly from our performance of the services, except for liabilities caused by our gross negligence or willful misconduct. We will disclaim all warranties and make no representations as to the quality, suitability or adequacy of the services provided.

We will provide the services for 180 days, unless we and Plains Resources decide to terminate the agreement earlier. We and Plains Resources may agree to extend this agreement beyond the 180 day period if necessary or desirable.

TECHNICAL SERVICES AGREEMENT

The technical services agreement will be entered into at the same time as the master separation agreement and provides that, beginning on a date to be determined by us and Plains Resources, we will provide Calumet Florida certain engineering and technical support services required to support operation and maintenance of the oil and gas properties owned by Calumet, including geological, geophysical, surveying, drilling and operations services, environmental and

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other governmental or regulatory compliance related to oil and gas activities and other oil and gas engineering services as requested, and accounting services.

Plains Resources will reimburse us for our costs to produce these services.

In addition, we and Plains Resources may identify additional services that we will provide to Plains Resources under this agreement in the future. The terms and costs of these additional services will be mutually agreed upon by us and Plains Resources. We may allow one of our subsidiaries or a qualified third party to provide the services under this agreement, but we will be responsible for the performance of the services.

We and Plains Resources may agree to specific performance metrics that we must meet. Where no metrics are provided, we will (1) perform the services in accordance with the policies and procedures in effect before this agreement, (2) exercise the same care and skill as we exercise in performing similar services for our subsidiaries, and (3) in cases where there is common personnel, equipment or facilities for services provided to our subsidiaries and Plains Resources, not favor Plains Resources or our subsidiaries over the other. We may change the manner in which we provide the services so long as we are making similar changes to the services we are providing to our subsidiaries. We are not obligated to provide any service to the extent it is impracticable as a result of causes outside of our control.

The technical services agreement provides that we will not be liable to Plains Resources or Calumet with respect to the performance of the services, except in the case of gross negligence or willful misconduct in providing the services. We will indemnify Plains Resources and Calumet for any liabilities arising from such gross negligence or misconduct. Plains Resources will indemnify us for any liabilities arising directly from the performance of the services, except for liabilities caused by our gross negligence or willful misconduct. We disclaim all warranties and make no representations as to the quality, suitability or adequacy of the services provided.

We will provide the services until (1) Calumet is no longer a subsidiary of Plains Resources, (2) Calumet transfers substantially all of its assets to a person that is not a subsidiary of Plains Resources, (3) the third anniversary of the date of this agreement or (4) when all the services are terminated as provided in the agreement. Plains Resources may terminate the agreement as to some or all of the services at any time by giving us at least 90 days' written notice.

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DESCRIPTION OF CAPITAL STOCK

Pursuant to our certificate of incorporation, we have the authority to issue an aggregate of shares of capital stock, consisting of shares of common stock, par value $0.01 per share, and shares of preferred stock, par value $0.01 per share. As of , 2002 we had shares of common stock. Plains Resources was the only holder of record of our outstanding shares of common stock as of , 2002.

Selected provisions of our organizational documents are summarized below. This summary is not complete. You should read the organizational documents, which are filed as exhibits to the registration statement, for other provisions that may be important to you. In addition, you should be aware that the summary below does not give full effect to the terms of the provisions of statutory or common law which may affect your rights as a stockholder.

COMMON STOCK

VOTING RIGHTS. Each share of common stock is entitled to one vote in the election of directors and on all other matters submitted to a vote of our stockholders. Our stockholders do not have the right to cumulate their votes in the election of directors.

DIVIDENDS, DISTRIBUTIONS AND STOCK SPLITS. Holders of our common stock are entitled to receive dividends if, as and when such dividends are declared by our board out of assets legally available therefor after payment of dividends required to be paid on shares of preferred stock, if any. We expect that our new credit facility will prohibit us from paying cash dividends.

LIQUIDATION. In the event of any dissolution, liquidation, or winding up of our affairs, whether voluntary or involuntary, after payment of our debts and other liabilities and making provision for any holders of our preferred stock who have a liquidation preference, our remaining assets will be distributed ratably among the holders of common stock.

FULLY PAID. All shares of common stock outstanding are fully paid and nonassessable, and all the shares of common stock to be outstanding upon completion of this offering will be fully paid and nonassessable.

OTHER RIGHTS. Holders of our common stock have no redemption or conversion rights and no preemptive or other rights to subscribe for our securities.

PREFERRED STOCK

The board of directors has the authority to issue up to shares of preferred stock in one or more series and to fix the rights, preferences, privileges and restrictions thereof, including dividend rights, dividend rates, conversion rates, voting rights, terms of redemption, redemption prices, liquidation preferences and the number of shares constituting any series or the designation of that series, which may be superior to those of the common stock, without further vote or action by the stockholders. There will be no shares of preferred stock outstanding upon the closing of the offering and we have no present plans to issue any preferred stock.

One of the effects of undesignated preferred stock may be to enable the board of directors to render more difficult or to discourage an attempt to obtain control of us by means of a tender offer, proxy contest, merger or otherwise, and as a result to protect the continuity of our management. The issuance of shares of the preferred stock by the board of directors as described above may adversely affect the rights of the holders of common stock. For example, preferred stock issued by us may rank prior to the common stock as to dividend rights, liquidation preference or both, may have full or limited voting rights and may be convertible into shares of common stock. Accordingly, the issuance of shares of preferred stock may discourage bids for the common stock or may otherwise adversely affect the market price of the common stock.

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DELAWARE ANTI-TAKEOVER LAW AND CERTAIN CHARTER AND BYLAW PROVISIONS

Our certificate of incorporation, bylaws and the Delaware General Corporation Law contain certain provisions that could discourage potential takeover attempts and make it more difficult for our stockholders to change management or receive a premium for their shares.

DELAWARE LAW. We are subject to Section 203 of the Delaware General Corporation Law, an anti-takeover law. In general, the statute prohibits a publicly-held Delaware corporation from engaging in a business combination with an "interested stockholder" for a period of three years after the date of the transaction in which the person became an interested stockholder. A "business combination" includes a merger, sale of 10% or more of our assets and certain other transactions resulting in a financial benefit to the stockholder. For purposes of Section 203, an "interested stockholder" is defined to include any person that is:

- the owner of 15% or more of the outstanding voting stock of the corporation;

- an affiliate or associate of the corporation and was the owner of 15% or more of the voting stock outstanding of the corporation, at any time within three years immediately prior to the relevant date; and

- an affiliate or associate of the persons described in the foregoing bullet points.

However, the above provisions of Section 203 do not apply if:

- our board approves the transaction that made the stockholder an interested stockholder prior to the date of that transaction;

- after the completion of the transaction that resulted in the stockholder becoming an interested stockholder, that stockholder owned at least 85% of our voting stock outstanding at the time the transaction commenced, excluding shares owned by our officers and directors; or

- on or subsequent to the date of the transaction, the business combination is approved by our board and authorized at a meeting of our stockholders by an affirmative vote of at least two-thirds of the outstanding voting stock not owned by the interested stockholder.

Stockholders may, by adopting an amendment to the corporation's certificate of incorporation or bylaws, elect for the corporation not to be governed by
Section 203, effective 12 months after adoption. Neither our certificate of incorporation nor our bylaws exempt us from the restrictions imposed under
Section 203. It is anticipated that the provisions of Section 203 may encourage companies interested in acquiring us to negotiate in advance with our board.

CHARTER AND BYLAW PROVISIONS. Our certificate of incorporation and bylaws provide that any action required or permitted to be taken by our stockholders may only be effected at a duly called annual or special meeting of the stockholders, and may not be taken by written consent of the stockholders. Special meetings of stockholders may be called by the chairman or the chief executive officer or by a majority of the board.

Directors may be removed with the approval of the holders of a majority of the shares then entitled to vote at an election of directors. Directors may only be removed by stockholders for cause only. Vacancies and newly-created directorships resulting from any increase in the number of directors may be filled by a majority of the directors then in office, a sole remaining director. Stockholders are not permitted to fill vacancies.

Our bylaws provide that nominations for directors may not be made by stockholders at any annual or special meeting unless the stockholder intending to make a nomination notifies us of its intention a specified number of days in advance of the meeting and furnishes to us certain information regarding itself and the intended nominee. Our bylaws also require a stockholder to provide to our secretary advance notice of business to be brought by the stockholder before any

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annual or special meeting of our stockholders, as well as certain information regarding the stockholder and any material interest the stockholder may have in the proposed business.

LIMITATION OF LIABILITY; INDEMNIFICATION

Our certificate of incorporation contains certain provisions permitted under the Delaware General Corporation Law relating to the liability of directors. These provisions eliminate a director's personal liability for monetary damages resulting from a breach of fiduciary duty, except that a director will be personally liable:

- for any breach of the director's duty of loyalty to us or our stockholders;

- for acts or omissions not in good faith or which involve intentional misconduct or a knowing violation of law;

- under Section 174 of the Delaware General Corporation Law relating to unlawful stock repurchases or dividends; or

- for any transaction from which the director derives an improper personal benefit.

These provisions do not limit or eliminate our rights or those of any stockholder to seek non-monetary relief, such as an injunction or rescission, in the event of a breach of a director's fiduciary duty. These provisions will not alter a director's liability under federal securities laws.

Our certificate of incorporation and bylaws also provide that we must indemnify our directors, officers, employees and agents to the fullest extent permitted by Delaware law and also provide that we must advance expenses, as incurred, to our directors and executive officers in connection with a legal proceeding to the fullest extent permitted by Delaware law, subject to very limited exceptions.

We plan to enter into separate indemnification agreements with our directors and officers that may, in some cases, be broader than the specific indemnification provisions contained in our certificate of incorporation, bylaws or the Delaware General Corporation Law. The indemnification agreements may require us, among other things, to indemnify the officers and directors against certain liabilities, other than liabilities arising from willful misconduct, that may arise by reason of their status or service as directors or officers. We believe that these indemnification arrangements are necessary to attract and retain qualified individuals to serve as directors and officers.

TRANSFER AGENT AND REGISTRAR

The Transfer Agent and Registrar for the common stock will be .

SHARES ELIGIBLE FOR FUTURE SALE

Upon the completion of this offering, shares of common stock will be outstanding, or shares if the underwriters exercise their option to purchase additional shares of common stock in full. Of these shares, the shares of common stock, assuming the underwriters exercise their option to purchase additional shares of common stock in full, sold in this offering will be freely tradable without restriction or further registration under the Securities Act, unless held by an "affiliate" of our company as that term is defined in Rule 144 under the Securities Act. All of the shares of common stock outstanding prior to this offering are "restricted securities," as defined under Rule 144. These shares are restricted securities because they were issued in private transactions not involving a public offering and may not be sold in the absence of registration other than in accordance with Rule 144 or Rule 701 promulgated under the Securities Act or another exemption from registration. This prospectus may not be used in connection with any resale of shares of common stock acquired in this offering by our affiliates.

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The shares of our common stock that will continue to be held by Plains Resources after the offering constitute "restricted securities" within the meaning of Rule 144, and will be eligible for sale by Plains Resources in the open market after the offering, subject to contractual lockup provisions and the applicable requirements of Rule 144. In connection with this offering, we, Plains Resources and our collective officers and directors have agreed that, subject to specified exceptions, for a period of 180 days after the date of this prospectus, we and they will not, without the prior written consent of Goldman, Sachs & Co., dispose of or hedge any shares of our common stock or any securities convertible into or exchangeable for our common stock, except that Plains Resources can distribute shares of our common stock in the spin-off after 120 days of the date of this prospectus without the consent of Goldman, Sachs & Co.

In general, under Rule 144 as currently in effect, if a minimum of one year has elapsed since the later of the date of acquisition of the restricted securities from the issuer or from an affiliate of the issuer, a person or persons whose shares of common stock are aggregated, including persons who may be deemed our affiliates, would be entitled to sell within any three-month period a number of shares of common stock that does not exceed the greater of:

- one percent of the then-outstanding shares of common stock, which equals approximately shares immediately after this offering; and

- the average weekly trading volume during the four calendar weeks preceding the date on which notice of the sale is filed with the SEC.

Sales under Rule 144 are also subject to certain restrictions as to the manner of sale, notice requirements and the availability of current public information about us. In addition, under Rule 144(k), if a period of at least two years has elapsed since the later of the date restricted securities were acquired from us or the date they were acquired from one of our affiliates, a stockholder who is not our affiliate at the time of sale and who has not been our affiliate for at least three months prior to the sale would be entitled to sell shares of common stock in the public market immediately without compliance with the foregoing requirements under Rule 144. Rule 144 does not require the same person to have held the securities for the applicable periods. The foregoing summary of Rule 144 is not intended to be a complete description.

Any shares distributed by Plains Resources will be eligible for immediate resale in the public market without restrictions by persons other than our affiliates. Our affiliates would be subject to the restrictions of Rule 144 described above other than the one-year holding period requirement.

Immediately following this offering, none of the "restricted securities" will be available for immediate sale in the public market pursuant to Rule 144(k).

Prior to this offering, there has been no public market for the common stock. No information is currently available and we cannot predict the timing or amount of future sales of shares, or the effect, if any, that future sales of shares, or the availability of shares for future sale, will have on the market price of the common stock prevailing from time to time. Sales of substantial amounts of the common stock (including shares issuable upon the exercise of stock options) in the public market after the lapse of the restrictions described above, or the perception that such sales may occur, could materially adversely affect the prevailing market prices for the common stock and our ability to raise equity capital in the future. See "Risk Factors -- Risks Related to This Offering -- The actual or possible sale of our shares by Plains Resources could depress or reduce the market price of our common stock or cause our shares to trade below the prices at which they would otherwise trade".

63

UNDERWRITING

We and the underwriters for the offering named below have entered into an underwriting agreement with respect to the shares being offered. Subject to certain conditions in the underwriting agreement, each underwriter has severally agreed to purchase the number of shares indicated in the following table. Goldman, Sachs & Co. is the representative of the underwriters.

                                                              Number of
Underwriters                                                   Shares
------------                                                  ---------
Goldman, Sachs & Co. .......................................

     Total..................................................
                                                              ========

The underwriters are committed to take and pay for all of the shares being offered, if any are taken, other than the shares covered by the option described below unless and until this option is exercised.

If the underwriters sell more shares than the total number set forth in the table above, the underwriters have an option to buy up to an additional shares from us to cover such sales. They may exercise that option for 30 days. If any shares are purchased pursuant to this option, the underwriters will severally purchase shares in approximately the same proportion as set forth in the table above.

The following table shows the per share and total underwriting discounts and commissions to be paid to the underwriters by us. Such amounts are shown assuming both no exercise and full exercise of the underwriters' option to purchase additional shares.

Paid by Plains Exploration & Production Company          No Exercise   Full Exercise
-----------------------------------------------          -----------   -------------
Per Share..............................................   $              $
Total..................................................   $              $

Shares sold by the underwriters to the public will initially be offered at the initial public offering price set forth on the cover of this Prospectus. Any shares sold by the underwriters to securities dealers may be sold at a discount of up to $ per share from the initial public offering price. Any such securities dealers may resell any shares purchased from the underwriters to certain other brokers or dealers at a discount of up to $ per share from the initial public offering price. If all the shares are not sold at the initial offering price, the representatives may change the offering price and the other selling terms.

We, Plains Resources and our collective officers and directors have agreed with the underwriters not to dispose of or hedge any of their common stock or securities convertible into or exchangeable for shares of common stock during the period from the date of this Prospectus continuing through the date 180 days after the date of this Prospectus, except with the prior written consent of Goldman, Sachs & Co., except that Plains Resources can distribute shares of our common stock in the spin-off after 120 days of the date of this prospectus without the consent of Goldman, Sachs & Co.

Prior to the offering, there has been no public market for the shares. The initial public offering price will be negotiated between the representatives and us. Among the factors to be considered in determining the initial public offering price of the shares, in addition to prevailing market conditions, will be our historical performance, estimates of our business potential and earnings prospects, an assessment of our and Plains Resources Inc.'s management and the consideration of the above factors in relation to market valuation of companies in related businesses.

64

We intend to list our common stock on the New York Stock Exchange under the symbol "PXP". In order to meet one of the requirements for listing the common stock on the NYSE, the underwriters have undertaken to sell lots of 100 or more shares to a minimum of 2,000 beneficial holders.

In connection with the offering, the underwriters may purchase and sell shares of common stock in the open market. These transactions may include short sales, stabilizing transactions and purchases to cover positions created by short sales. Shorts sales involve the sale by the underwriters of a greater number of shares than they are required to purchase in the offering. "Covered" short sales are sales made in an amount not greater than the underwriters' option to purchase additional shares from us in the offering. The underwriters may close out any covered short position by either exercising their option to purchase additional shares or purchasing shares in the open market. In determining the source of shares to close out the covered short position, the underwriters will consider, among other things, the price of shares available for purchase in the open market as compared to the price at which they may purchase shares through their option to purchase additional shares of common stock. "Naked" short sales are any sales in excess of such option. The underwriters must close out any naked short position by purchasing shares in the open market. A naked short position is more likely to be created if the underwriters are concerned that there may be downward pressure on the price of the common stock in the open market after pricing that could adversely affect investors who purchase in the offering. Stabilizing transactions consist of various bids for or purchases of common stock made by the underwriters in the open market prior to the completion of the offering.

The underwriters may also impose a penalty bid. This occurs when a particular underwriter repays to the underwriters a portion of the underwriting discount received by it because the representatives have repurchased shares sold by or for the account of such underwriter in stabilizing or short covering transactions.

Purchases to cover a short position and stabilizing transactions may have the effect of preventing or retarding a decline in the market price of our common stock, and together with the imposition of the penalty bid, may stabilize, maintain or otherwise affect the market price of the common stock. As a result, the price of the common stock may be higher than the price that otherwise might exist in the open market. If these activities are commenced, they may be discontinued at any time. These transactions may be effected on the New York Stock Exchange, in the over-the-counter market or otherwise.

A prospectus in electronic format will be made available on the websites maintained by one or more of the lead managers of this offering and may also be made available on websites maintained by other underwriters. The underwriters may agree to allocate a number of shares to underwriters for sale to their online brokerage account holders. Internet distributions will be allocated by the lead managers to underwriters that may make Internet distributions on the same basis as other allocations.

The underwriters do not expect sales to discretionary accounts to exceed five percent of the total number of shares offered.

We estimate that the total expenses of the offering, excluding underwriting discounts and commissions, will be approximately $ .

We have agreed to indemnify the several underwriters against certain liabilities, including liabilities under the Securities Act of 1933.

Some of the underwriters may provide from time to time financial advisory and investment banking services to us and our affiliates, for which they will receive customary fees and commissions. Goldman, Sachs & Co. and its affiliates have provided from time to time, and expect to provide in the future, investment and commercial banking and financial advisory

65

services to us and our affiliates in the ordinary course of business, for which they have received and may continue to receive customary fees and commissions.

LEGAL MATTERS

Akin, Gump, Strauss, Hauer & Feld, L.L.P. will pass on certain legal matters with respect to the validity of the common stock offered hereby. Certain legal matters in connection with this offering will be passed upon for the underwriters by Simpson Thacher & Bartlett, New York, New York.

EXPERTS

The combined financial statements of the Upstream Subsidiaries of Plains Resources Inc. as of December 31, 2001 and 2000 and for each of the three years in the period ended December 31, 2001 included in this prospectus have been so included on the reports of PricewaterhouseCoopers LLP, independent accountants, given on the authority of said firm as experts in auditing and accounting.

Certain information with respect to the oil and gas reserves associated with our oil and gas properties is derived from the reports of Netherland, Sewell & Associates, Inc., Ryder Scott Company, and H.J. Gruy and Associates, Inc., independent petroleum consulting firms, and has been included in this prospectus upon the authority of said firms as experts with respect to the matters covered by such reports and in giving such reports.

WHERE YOU CAN FIND MORE INFORMATION

We have filed a registration on Form S-1 with the Securities and Exchange Commission in connection with this offering. In addition, upon completion of the offering, we will be required to file annual, quarterly and current reports, proxy statements and other information with the Securities and Exchange Commission. You may read and copy the registration statement and any other documents we have filed at the Securities and Exchange Commission's Public Reference Room at 450 Fifth Street, N.W., Washington, D.C. 20549. Please call the Securities and Exchange Commission at 1-800-SEC-0330 for further information on the Public Reference Room. Our Securities and Exchange Commission filings are also available to the public at the Securities and Exchange Commission's Internet site at "http://www.sec.gov."

This prospectus is part of the registration statement and does not contain all of the information included in the registration statement. Whenever a reference is made in this prospectus to any of our contracts or other documents, the reference may not be complete and, for a copy of the contract or document, you should refer to the exhibits that are a part of the registration statement.

After the offering, we expect to provide annual reports to our stockholders that include financial information examined and reported on by our independent public accountants.

66

GLOSSARY OF OIL AND GAS TERMS

The following are abbreviations and definitions of certain terms commonly used in the oil and gas industry and this prospectus:

API gravity. A system of classifying oil based on its specific gravity, whereby the greater the gravity, the lighter the oil.

Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons.

BOE. One stock tank barrel equivalent of oil, calculated by converting gas volumes to equivalent oil barrels at a ratio of 6 Mcf to 1 Bbl of oil.

Developed acreage. The number of acres which are allocated or assignable to producing wells or wells capable of production.

Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

Differential. An adjustment to the price of oil from an established spot market price to reflect differences in the quality and/or location of oil.

Exploratory well. A well drilled to find and produce oil or gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir, or to extend a known reservoir.

Farm-in. An agreement between a participant who brings a property into the venture and another participant who agrees to spend an agreed amount to explore and develop the property and has no right of reimbursement but may gain a vested interest in the venture. A "farm-in" describes the position of the participant who agrees to spend the agreed-upon sum of money to gain a vested interest in the venture.

Gas. Natural gas.

Gross acres. The total acres in which we have a working interest.

Gross oil and gas wells. The total wells in which we own a working interest.

Infill drilling. A drilling operation in which one or more development wells is drilled within the proven boundaries of a field.

MBbl. One thousand barrels of oil or other liquid hydrocarbons.

MBOE. One thousand BOE.

Mcf. One thousand cubic feet of gas.

Midstream. The portion of the oil and gas industry focused on marketing, gathering, transporting and storing oil.

MMBbl. One million barrels of oil or other liquid hydrocarbons.

MMBOE. One million BOE.

MMcf. One million cubic feet of gas.

Net acres. Gross acres multiplied by the percentage working interest owned by us.

Net oil and gas wells. Gross wells multiplied by the percentage working interest owned by us.

Net production. Production that is owned, less royalties and production due others.

67

Net profits interest. An interest in a property which entitles the owner to receive a stated percentage of the net profit as defined in the instrument creating the interest. It is carved out of the working interest.

Net revenue interest. Our share of petroleum after satisfaction of all royalty and other non-cost-bearing interests.

NYMEX. New York Mercantile Exchange.

Oil. Crude oil, condensate and natural gas liquids.

Operator. The individual or company responsible for the exploration and/or exploitation and/or production of an oil or gas well or lease.

PV-10. The pre-tax present value, discounted at 10% per year, of estimated future net revenues computed by applying current prices of oil and gas reserves (with consideration of price changes only to the extent provided by contractual arrangements) to estimated future production of proved oil and gas reserves as of the date of the latest balance sheet presented, less estimated future expenditures (based on current costs) to be incurred in developing, producing and abandoning the proved reserves computed assuming continuation of existing economic conditions.

Proved developed reserves. Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

Proved reserve additions. The sum of additions to proved reserves from extensions, discoveries, improved recovery, acquisitions and revisions of previous estimates.

Proved reserves. The estimated quantities of oil, gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.

Proved undeveloped reserves. Reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

Reserve life. A measure of the productive life of an oil and gas property or a group of properties, expressed in years. Reserve life is calculated by dividing proved reserve volumes at year-end by production for that year.

Reserve replacement cost. The cost per BOE of reserves added during a period calculated by using a fraction, the numerator of which equals the costs incurred for the relevant property acquisition, exploration, exploitation and development and the denominator of which equals the proved reserve additions.

Reserve replacement ratio. The proved reserve additions for the period divided by the production for the period.

Royalty. An interest in an oil and gas lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner's royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.

Standardized measure. The present value, discounted at 10% per year, of estimated future net revenues from proved reserves of the properties reduced by future operating expenses, development expenditures and abandonment costs (net of salvage values), and estimated future income taxes thereon.

68

Undeveloped acreage. Acreage held under lease, permit, contract or option that is not in a spacing unit for a producing well.

Upstream. The portion of the oil and gas industry focused on acquiring, exploiting, developing, exploring for and producing oil and gas.

Waterflood. A secondary recovery operation in which water is injected into the producing formation to maintain reservoir pressure and force oil toward and into the producing wells.

Working interest. An interest in an oil and gas lease that gives the owner of the interest the right to drill for and produce oil and gas on the leased acreage and requires the owner to pay a share of the costs of drilling and production operations.

69

INDEX TO OUR FINANCIAL STATEMENTS

                                                              PAGE
UPSTREAM SUBSIDIARIES OF PLAINS RESOURCES INC.
  Unaudited Combined Balance Sheets as of March 31, 2002 and
     December 31, 2001......................................   F-2
  Unaudited Combined Statements of Income for the three
     months ended March 31, 2002 and 2001...................   F-3
  Unaudited Combined Statements of Cash Flows for the three
     months ended March 31, 2002 and 2001...................   F-4
  Unaudited Combined Statements of Comprehensive Income for
     the three months ended March 31, 2002 and 2001.........   F-5
  Unaudited Combined Statements of Changes in Combined
     Owners' Equity for the three months ended March 31,
     2002 and 2001..........................................   F-6
  Notes to Unaudited Combined Financial Statements..........   F-7
  Report of Independent Accountants.........................  F-20
  Combined Balance Sheets as of December 31, 2001 and
     2000...................................................  F-21
  Combined Statements of Income for the years ended December
     31, 2001, 2000 and 1999................................  F-22
  Combined Statements of Cash Flows for the years ended
     December 31, 2001, 2000 and 1999.......................  F-23
  Combined Statements of Comprehensive Income for the years
     ended December 31, 2001, 2000 and 1999.................  F-24
  Combined Statements of Combined Owners' Equity for the
     years ended December 31, 2001, 2000 and 1999...........  F-25
  Notes to Combined Financial Statements....................  F-26

F-1

UPSTREAM SUBSIDIARIES OF PLAINS RESOURCES INC.

UNAUDITED COMBINED BALANCE SHEETS

                                                               MARCH 31,    DECEMBER 31,
                                                                 2002           2001
                                                               ---------    ------------
                                                                    (IN THOUSANDS)
                                         ASSETS
CURRENT ASSETS
  Cash and cash equivalents.................................   $       1     $      13
  Accounts receivable and other current assets..............      18,296        16,382
  Commodity hedging contracts...............................         667        21,787
  Inventories...............................................       5,220         4,629
                                                               ---------     ---------
                                                                  24,184        42,811
                                                               ---------     ---------
PROPERTY AND EQUIPMENT, AT COST
  Oil and natural gas properties -- full cost method
     Subject to amortization................................     584,249       561,034
     Not subject to amortization............................      34,097        33,371
  Other property and equipment..............................       1,536         1,516
                                                               ---------     ---------
                                                                 619,882       595,921
  Less allowance for depreciation, depletion and
     amortization...........................................    (147,492)     (140,804)
                                                               ---------     ---------
                                                                 472,390       455,117
                                                               ---------     ---------
OTHER ASSETS................................................      11,780        18,827
                                                               ---------     ---------
                                                               $ 508,354     $ 516,755
                                                               =========     =========

                        LIABILITIES AND COMBINED OWNERS' EQUITY
CURRENT LIABILITIES
  Accounts payable and other current liabilities............   $  37,582     $  41,368
  Commodity hedging contracts...............................      10,139            --
  Current maturities on long-term debt......................         511           511
                                                               ---------     ---------
                                                                  48,232        41,879
                                                               ---------     ---------
PAYABLE TO PLAINS RESOURCES INC.............................     249,572       235,161
                                                               ---------     ---------
LONG-TERM DEBT..............................................       1,022         1,022
                                                               ---------     ---------
OTHER LONG-TERM LIABILITIES.................................       3,226         1,413
                                                               ---------     ---------
DEFERRED INCOME TAXES.......................................      43,529        57,193
                                                               ---------     ---------
COMMITMENTS AND CONTINGENCIES (NOTE 5)
COMBINED OWNERS' EQUITY
  Owners' equity............................................     170,067       164,203
  Accumulated other comprehensive income (loss).............      (7,294)       15,884
                                                               ---------     ---------
                                                                 162,773       180,087
                                                               ---------     ---------
                                                               $ 508,354     $ 516,755
                                                               =========     =========

See notes to combined financial statements.

F-2

UPSTREAM SUBSIDIARIES OF PLAINS RESOURCES INC.

UNAUDITED COMBINED STATEMENTS OF INCOME

                                                                THREE MONTHS
                                                                    ENDED
                                                                  MARCH 31,
                                                              -----------------
                                                               2002      2001
                                                               ----      ----
                                                               (IN THOUSANDS)
REVENUES
  Crude oil and liquids.....................................  $38,685   $42,601
  Natural gas...............................................    1,988    11,172
                                                              -------   -------
                                                               40,673    53,773
                                                              -------   -------
COSTS AND EXPENSES
  Production expenses.......................................   17,229    13,370
  General and administrative................................    2,452     2,786
  Depreciation, depletion and amortization..................    6,691     5,364
                                                              -------   -------
                                                               26,372    21,520
                                                              -------   -------
INCOME FROM OPERATIONS......................................   14,301    32,253
OTHER INCOME (EXPENSE)
  Interest expense..........................................   (4,692)   (4,191)
  Interest and other income.................................       18       558
                                                              -------   -------
INCOME BEFORE INCOME TAXES AND CUMULATIVE EFFECT OF
  ACCOUNTING CHANGE.........................................    9,627    28,620
  Income tax expense
     Current................................................   (2,045)   (1,932)
     Deferred...............................................   (1,718)   (9,115)
                                                              -------   -------
INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE........    5,864    17,573
  Cumulative effect of accounting change, net of tax
     benefit................................................       --    (1,522)
                                                              -------   -------
NET INCOME..................................................  $ 5,864   $16,051
                                                              =======   =======

See notes to combined financial statements.

F-3

UPSTREAM SUBSIDIARIES OF PLAINS RESOURCES INC.

UNAUDITED COMBINED STATEMENTS OF CASH FLOWS

                                                                 THREE MONTHS
                                                                ENDED MARCH 31,
                                                                ---------------
                                                                2002       2001
                                                                ----       ----
                                                                (IN THOUSANDS)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income..................................................  $  5,864   $ 16,051
Items not affecting cash flows from operating activities:
  Depreciation, depletion and amortization..................     6,691      5,364
  Deferred income taxes.....................................     1,718      9,115
  Cumulative effect of adoption of accounting change........        --      1,522
  Change in derivative fair value...........................        --      1,055
  Other noncash items.......................................        --        739
Change in assets and liabilities from operating activities:
  Accounts receivable and other assets......................      (356)    (3,444)
  Inventories...............................................      (591)    (1,607)
  Accounts payable and other liabilities....................    (3,788)     7,163
                                                              --------   --------
Net cash provided by operating activities...................     9,538     35,958
                                                              --------   --------
CASH FLOWS FROM INVESTING ACTIVITIES
Acquisition, exploration and developments costs.............   (23,941)   (26,888)
Additions to other property and assets......................       (20)       (86)
                                                              --------   --------
Net cash used in investing activities.......................   (23,961)   (26,974)
                                                              --------   --------
CASH FLOWS FROM FINANCING ACTIVITIES
Receipts from (payments to) Plains Resources Inc. ..........    14,411     (8,400)
                                                              --------   --------
Net cash provided by (used in) financing activities.........    14,411     (8,400)
                                                              --------   --------
Net increase (decrease) in cash and cash equivalents........       (12)       584
Cash and cash equivalents, beginning of period..............        13        536
                                                              --------   --------
Cash and cash equivalents, end of period....................  $      1   $  1,120
                                                              ========   ========

See notes to combined financial statements.

F-4

UPSTREAM SUBSIDIARIES OF PLAINS RESOURCES INC.

UNAUDITED COMBINED STATEMENTS OF COMPREHENSIVE INCOME

                                                                 THREE MONTHS
                                                               ENDED MARCH 31,
                                                              ------------------
                                                                2002      2001
                                                                ----      ----
                                                                (IN THOUSANDS)
NET INCOME..................................................  $  5,864   $16,051
OTHER COMPREHENSIVE INCOME (LOSS):
  Unrealized gains on derivatives:
     Cumulative effect of accounting change, net of taxes of
      $4,454................................................        --     6,967
     Change in fair value of open hedging positions, net of
      tax benefit of $13,133 in 2002 and $3,439 in 2001.....   (19,700)   (5,413)
     Reclassification adjustment for settled contracts, net
      of tax benefit of $2,248 in 2002 and $528 in 2001.....    (3,478)     (831)
                                                              --------   -------
                                                               (23,178)      723
                                                              --------   -------
COMPREHENSIVE INCOME (LOSS).................................  $(17,314)  $16,774
                                                              ========   =======

See notes to combined financial statements.

F-5

UPSTREAM SUBSIDIARIES OF PLAINS RESOURCES INC.

UNAUDITED COMBINED STATEMENTS OF COMBINED OWNERS' EQUITY

                                                                 THREE MONTHS
                                                                     ENDED
                                                                   MARCH 31,
                                                              -------------------
                                                                2002       2001
                                                                ----       ----
                                                                (IN THOUSANDS)
OWNERS' EQUITY
  Balance, beginning of period..............................  $164,203   $111,032
  Net income................................................     5,864     16,051
                                                              --------   --------
  Balance, end of period....................................   170,067    127,083
                                                              --------   --------
ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
  Balance, beginning of period..............................    15,884         --
  Other comprehensive income (loss).........................   (23,178)       723
                                                              --------   --------
  Balance, end of period....................................    (7,294)       723
                                                              --------   --------
COMBINED OWNERS' EQUITY.....................................  $162,773   $127,806
                                                              ========   ========

See notes to combined financial statements.

F-6

UPSTREAM SUBSIDIARIES OF PLAINS RESOURCES INC.

NOTES TO UNAUDITED COMBINED FINANCIAL STATEMENTS

NOTE 1 -- ORGANIZATION AND SIGNIFICANT ACCOUNTING POLICIES

ORGANIZATION

The combined financial statements of the Upstream Subsidiaries of Plains Resources Inc. (the "Companies", "our", or "we") include the accounts of Stocker Resources, L.P., Arguello Inc., Plains Illinois, Inc. and Plains Resources International Inc. Arguello Inc., Plains Illinois, Inc., PMCT Inc. and Plains Resources International Inc. are wholly-owned subsidiaries of Plains Resources Inc. ("Plains"). Stocker Resources, L.P. is a limited partnership of which Stocker Resources, Inc., a wholly owned subsidiary of Plains, is the general partner (holding a 2.5% interest) and Plains is the limited partner (holding a 97.5% interest). All significant intercompany transactions have been eliminated.

These combined financial statements and related notes present our combined financial position as of March 31, 2002 and December 31, 2001 and the results of our operations, our cash flows, our comprehensive income and the changes in our owners' equity for the three months ended March 31, 2002 and 2001. The results for the three months ended March 31, 2002 and 2001, are not necessarily indicative of the final results to be expected for the full year. All adjustments, consisting only of normal recurring adjustments, that in the opinion of management were necessary for a fair statement of the results for the interim periods, have been reflected. These unaudited combined financial statements should be read in conjunction with the combined financial statements for the year ended December 31, 2001 included herein.

We are independent energy companies that are engaged in the "Upstream" oil and gas business. The Upstream business acquires, exploits, develops, explores for and produces crude oil and natural gas. Our Upstream activities are all located in the United States.

Under the terms of a service agreement (the "Service Agreement"), Plains provides the Companies with financial intermediary, treasury and other services as may be required from time to time. Such services include, but are not limited to: arranging financings and commercial transactions for the procurement of funds and other commercial accommodations from financial institutions and other lenders; disbursement of capital and operating funds in the form of loans or intercompany advances; maintenance of financial records and books of account; and cash management, including the processing of cash receipts and disbursements.

These financial statements include allocations of direct and indirect corporate and administrative costs of Plains. The methods by which such costs are estimated and allocated to the Companies are deemed reasonable by Plains' management; however, such allocations and estimates are not necessarily indicative of the costs and expenses that would have been incurred had we operated as a separate entity. Allocations of such costs are considered to be related party transactions and are discussed in Note 4.

SIGNIFICANT ACCOUNTING POLICIES

Oil and Gas Properties. We follow the full cost method of accounting whereby all costs associated with property acquisition, exploration, exploitation and development activities are capitalized. Such costs include internal general and administrative costs such as payroll and related benefits and costs directly attributable to employees engaged in acquisition, exploration, exploitation and development activities. General and administrative costs associated with production, operations, marketing and general corporate activities are expensed as incurred. These capitalized costs along with our estimate of future development and abandonment costs, net of salvage values and other considerations, are amortized to expense by the unit-of-production method using engineers' estimates of proved oil and natural gas reserves. The costs

F-7

UPSTREAM SUBSIDIARIES OF PLAINS RESOURCES INC.

NOTES TO UNAUDITED COMBINED FINANCIAL STATEMENTS -- (CONTINUED)

of unproved properties are excluded from amortization until the properties are evaluated. Interest is capitalized on oil and natural gas properties not subject to amortization and in the process of development. Proceeds from the sale of oil and natural gas properties are accounted for as reductions to capitalized costs unless such sales involve a significant change in the relationship between costs and the estimated value of proved reserves, in which case a gain or loss is recognized. Unamortized costs of proved properties are subject to a ceiling which limits such costs to the present value of estimated future cash flows from proved oil and natural gas reserves of such properties (including the effect of any related hedging activities) reduced by future operating expenses, development expenditures and abandonment costs (net of salvage values), and estimated future income taxes thereon.

Other Property and Equipment. Other property and equipment is recorded at cost and consists primarily of office furniture and fixtures and computer hardware and software. Acquisitions, renewals, and betterments are capitalized; maintenance and repairs are expensed. Depreciation is provided using the straight-line method over estimated useful lives of three to seven years. Net gains or losses on property and equipment disposed of are included in interest and other income in the period in which the transaction occurs.

Use of Estimates. The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Significant estimates made by management include
(1) crude oil and natural gas reserves, (2) depreciation, depletion and amortization, including future abandonment costs, (3) income taxes and (4) accrued liabilities. Although management believes these estimates are reasonable, actual results could differ from these estimates.

Cash and Cash Equivalents. Cash and cash equivalents consist of all demand deposits and funds invested in highly liquid instruments with original maturities of three months or less. At March 31, 2001, the majority of cash and cash equivalents is concentrated in one institution and at times may exceed federally insured limits. We periodically assess the financial condition of the institution and believe that any possible credit risk is minimal.

Inventory. Crude oil inventories are carried at the lower of cost to produce or market value. Materials and supplies inventory is stated at the lower of cost or market with cost determined on an average cost method. Inventory consists of the following (in thousands):

                                                              MARCH 31,   DECEMBER 31,
                                                                2002          2001
                                                              ---------   ------------
Crude oil...................................................   $4,775        $4,201
Materials and supplies......................................      445           428
                                                               ======        ======
                                                               $5,220        $4,629
                                                               ======        ======

Federal and State Income Taxes. Income taxes are accounted for in accordance with Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes ("SFAS 109"). SFAS 109 requires recognition of deferred tax liabilities and assets for the expected future tax consequences of events that have been included in the financial statements or tax returns. Under this method, deferred tax liabilities and assets are determined based on the difference between the financial statement and tax bases of assets and liabilities using tax rates in effect for the year in which the differences are expected to reverse. A valuation allowance is

F-8

UPSTREAM SUBSIDIARIES OF PLAINS RESOURCES INC.

NOTES TO UNAUDITED COMBINED FINANCIAL STATEMENTS -- (CONTINUED)

established to reduce deferred tax assets if it is more than likely than not that the related tax benefits will not be realized.

The taxable income or loss of the Companies is included in the consolidated income tax returns filed by Plains. Income tax obligations reflected in these financial statements are based on the tax sharing agreement among all the members of the consolidated group. Such agreement provides that taxes are calculated assuming the combined companies filed a separate income tax return. Income taxes payable are included in Payable to Plains Resources, Inc. in the combined balance sheet.

REVENUE RECOGNITION. Oil and gas revenue from our interests in producing wells is recognized when the production is delivered and the title transfers.

DERIVATIVE FINANCIAL INSTRUMENTS (HEDGING). We utilize various derivative instruments to reduce our exposure to fluctuations in the market price of crude oil. The derivative instruments consist primarily of crude oil swap and option contracts entered into with financial institutions.

RECENT ACCOUNTING PRONOUNCEMENTS. In June 2001 Statement of Financial Accounting Standards ("SFAS") No. 143, Accounting for Asset Retirement Obligations was issued. SFAS No. 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. Subsequently, the asset retirement cost should be allocated to expense using a systematic and rational method. SFAS No. 143 is effective for fiscal years beginning after June 15, 2002. We are currently assessing the impact of SFAS No. 143 and at this time cannot reasonably estimate the effect of this statement on our consolidated financial position, results of operations or cash flows.

NOTE 2 -- DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

Plains entered into various derivative instruments on behalf of the Companies to reduce our exposure to fluctuations in the market price of crude oil. The derivative instruments consist primarily of crude oil swap and option contracts entered into with financial institutions. In accordance with the terms of the Services Agreement, the gains and losses with respect to such instruments have been allocated to the Companies' and oil revenues for the three months ended March 31, 2002 have been increased by $3.7 million and oil revenues for the three months ended March 31, 2001 have been decreased by $3.4 million as a result of such transactions.

Accounting for derivative instruments is in accordance with Statement of Financial Accounting Standards ("SFAS") No. 133 "Accounting for Derivative Instruments and Hedging Activities" as amended by SFAS 137 and SFAS 138 ("SFAS 133"). Under SFAS 133, all derivative instruments are recorded on the balance sheet at fair value. If the derivative does not qualify as a hedge or is not designated as a hedge, the gain or loss on the derivative is recognized currently in earnings. If the derivative qualifies for hedge accounting, the gain or loss on the derivative is deferred in Other Comprehensive Income ("OCI"), a component of Combined Owners' Equity. At March 31, 2002 all open positions qualified for hedge accounting.

Gains and losses deferred in OCI related to cash flow hedges that become ineffective remain unchanged until the related product is delivered. Gains and losses on crude oil hedging instruments representing hedge ineffectiveness, which is measured on a quarterly basis, are included in oil and gas revenues in the period in which they occur. There was no ineffectiveness recognized in the three months ended March 31, 2002 or 2001.

F-9

UPSTREAM SUBSIDIARIES OF PLAINS RESOURCES INC.

NOTES TO UNAUDITED COMBINED FINANCIAL STATEMENTS -- (CONTINUED)

On January 1, 2001, in accordance with the transition provisions of SFAS 133, we recorded a gain of $7.0 million in OCI, representing the cumulative effect of an accounting change to recognize at fair value all cash flow derivatives. We recorded cash flow hedge derivative assets and liabilities of $9.7 million and $4.2 million, respectively, and a net-of-tax non-cash charge of $1.5 million was recorded in earnings as a cumulative effect adjustment.

During the first three months of 2002 gains of $3.5 million were relieved from OCI and the fair value of open positions decreased $19.7 million. At March 31, 2002, the unrealized loss on our swaps contracts included in OCI was $7.3 million. The related assets and liabilities were included in current liabilities ($10.1 million), other liabilities ($1.8 million), and deferred income taxes ($4.7) million. As of March 31, 2002, $5.8 million of deferred net losses on derivative instruments recorded in OCI are expected to be reclassified to earnings during the next twelve-month period.

Oil and gas revenues for the three months ended March 31, 2002 include $3.5 million of cash gains on hedging instruments, and a $0.1 million non-cash loss related to the amortization of time value in existence when Derivative Information Group Issue G20 was implemented in the fourth quarter of 2001. Assets related to the time value component of the fair value of options are included in current assets ($0.7 million).

We utilize various derivative instruments to hedge our exposure to price fluctuations on crude oil sales. The derivative instruments consist primarily of cash-settled crude oil option and swap contracts entered into with financial institutions. We do not currently have any natural gas hedges. At March 31, 2002, we had the following open crude oil hedge positions:

                                                               BARRELS PER DAY
                                               ------------------------------------------------
                                                                2002
                                               ---------------------------------------
                                               2ND QUARTER   3RD QUARTER   4TH QUARTER    2003
                                               -----------   -----------   -----------    ----
Calls
  Average price $35.17/bbl...................     9,000         9,000         9,000          --
Swaps
  Average price $24.14/bbl...................    19,000            --            --          --
  Average price $24.10/bbl...................        --        19,000            --
  Average price $24.09/bbl...................        --            --        19,000          --
  Average price $23.12/bbl...................        --            --            --      12,500

NOTE 3 -- LONG-TERM DEBT

Long-term debt and the related current maturities represents a note issued in connection with the purchase of a production payment on certain of our producing properties. The note bears interest at 8%, payable annually, and requires an annual principal payment of $511,000 through 2004.

NOTE 4 -- RELATED PARTY TRANSACTIONS

We use a centralized cash management system under which our cash receipts are remitted to Plains and our cash disbursements are funded by Plains. We are charged interest on any amounts, other than income taxes payable, due to Plains at the average effective interest rate of Plains long-term debt. For the three months ended March 31, 2002 and 2001 we were charged $4.8 million and $4.2 million, respectively, of interest on amounts payable to Plains. Of such amounts, $4.1 million and $3.4 million was included in interest expense in 2002 and 2001, respectively, and the remainder was capitalized in oil and gas properties.

F-10

UPSTREAM SUBSIDIARIES OF PLAINS RESOURCES INC.

NOTES TO UNAUDITED COMBINED FINANCIAL STATEMENTS -- (CONTINUED)

To compensate Plains for services rendered under the Services Agreement, we are allocated direct and indirect corporate and administrative costs of Plains. Such costs for the three months ended March 31, 2002 and 2001 totaled $2.4 million and $1.6 million, respectively. Of such amounts, $1.7 million and $1.3 million was included in general and administrative expense in 2002 and 2001, respectively, and the remainder was capitalized in oil and gas properties.

In addition, as discussed in Note 2, Plains entered into various derivative instruments to reduce our exposure to decreases in the market price of crude oil.

At March 31, 2002 Plains had $267.5 million principal amount of 10.25% Senior Subordinated Notes due 2006 outstanding. Such notes are guaranteed by the Companies on a full, unconditional, joint and several basis.

NOTE 5 -- COMMITMENTS, CONTINGENCIES AND INDUSTRY CONCENTRATION

COMMITMENTS AND CONTINGENCIES

Under the amended terms of an asset purchase agreement with respect to certain of our onshore California properties, commencing with the year beginning January 1, 2000, and each year thereafter, we are required to plug and abandon 20% of the then remaining inactive wells, which currently aggregate approximately 149. To the extent we elect not to plug and abandon the number of required wells, we are required to escrow an amount equal to the greater of $25,000 per well or the actual average plugging cost per well in order to provide for the future plugging and abandonment of such wells. In addition, we are required to expend a minimum of $600,000 per year in each of the ten years beginning January 1, 1996, and $300,000 per year in each of the succeeding five years to remediate oil contaminated soil from existing well sites, provided there are remaining sites to be remediated. In the event we do not expend the required amounts during a calendar year, we are required to contribute an amount equal to 125% of the actual shortfall to an escrow account. We may withdraw amounts from the escrow account to the extent we expend excess amounts in a future year. Through March 31, 2002, we have not been required to make contributions to an escrow account.

In connection with the acquisition of our interest in the Point Arguello field, offshore California, we assumed our 26% share of (1) plugging and abandoning all existing well bores, (2) removing conductors, (3) flushing hydrocarbons from all lines and vessels and (4) removing/abandoning all structures, fixtures and conditions created subsequent to closing. The seller retained the obligation for all other abandonment costs, including but not limited to (1) removing, dismantling and disposing of the existing offshore platforms, (2) removing and disposing of all existing pipelines and (3) removing, dismantling, disposing and remediation of all existing onshore facilities.

Although we obtained environmental studies on our properties in California and Illinois and we believe that such properties have been operated in accordance with standard oil field practices, certain of the fields have been in operation for more than 90 years, and current or future local, state and federal environmental laws and regulations may require substantial expenditures to comply with such rules and regulations. In connection with the purchase of certain of our onshore California properties, we received a limited indemnity for certain conditions if they violate applicable local, state and federal environmental laws and regulations in effect on the date of such agreement. We believe that we do not have any material obligations for operations conducted prior to our acquisition of the properties, other than our obligation to plug existing wells and those normally associated with customary oil field operations of similarly situated properties. There can be no assurance that current or future local, state or federal rules

F-11

UPSTREAM SUBSIDIARIES OF PLAINS RESOURCES INC.

NOTES TO UNAUDITED COMBINED FINANCIAL STATEMENTS -- (CONTINUED)

and regulations will not require us to spend material amounts to comply with such rules and regulations or that any portion of such amounts will be recoverable under the indemnity.

Consistent with normal industry practices, substantially all of our crude oil and natural gas leases require that, upon termination of economic production, the working interest owners plug and abandon non-producing wellbores, remove tanks, production equipment and flow lines and restore the wellsite. We have estimated that at December 31, 2001 the costs to perform these tasks was approximately $12.0 million, net of salvage value and other considerations.

As is common within the industry, we have entered into various commitments and operating agreements related to the exploration and development of and production from proved crude oil and natural gas properties and the marketing, transportation, terminalling and storage of crude oil. It is management's belief that such commitments will be met without a material adverse effect on our financial position, results of operations or cash flows.

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

INDUSTRY CONCENTRATION

Financial instruments which potentially subject us to concentrations of credit risk consist principally of accounts receivable with respect to our oil and gas operations and derivative instruments related to our hedging activities. PAA is the exclusive marketer/purchaser for all of our equity oil production. This concentration has the potential to impact our overall exposure to credit risk, either positively or negatively, in that PAA may be affected by changes in economic, industry or other conditions. We do not believe the loss of PAA as the exclusive purchaser of our equity production would have a material adverse affect on our results of operations. We believe PAA could be replaced by other purchasers under contracts with similar terms and conditions. The contract counterparties for our derivative commodity contracts are all major financial institutions with Standard & Poor's ratings of A or better. Three of the financial institutions are participating lenders in Plains' revolving credit facility, with one such counterparty holding contracts that represent approximately 34% of the fair value of all of Plains' open positions at March 31, 2002.

There are a limited number of alternative methods of transportation for our production. Substantially all of our oil and gas production is transported by pipelines, trucks and barges owned by third parties. The inability or unwillingness of these parties to provide transportation services to us for a reasonable fee could result in our having to find transportation alternatives, increased transportation costs or involuntary curtailment of a significant portion of our oil and gas production which could have a negative impact on future results of operations or cash flows.

F-12

UPSTREAM SUBSIDIARIES OF PLAINS RESOURCES INC.

NOTES TO UNAUDITED COMBINED FINANCIAL STATEMENTS -- (CONTINUED)

NOTE 6 -- CONSOLIDATING FINANCIAL STATEMENTS

In conjunction with the issuance of the senior subordinated notes, all subsidiaries of Plains referred to in Note 1 will become 100% owned subsidiaries of Stocker Resources, L.P. Stocker Resources, L.P. will be co-issuing the senior subordinated notes along with a 100% owned finance company. The senior subordinated notes will be guaranteed on a full and unconditional and joint and several basis by Arguello Inc. and Plains Illinois Inc. (referred to as "Guarantor Subsidiaries").

The following financial information presents consolidating financial statements, which include:

- the parent company only ("Parent")

- the guarantor subsidiaries on a combined basis ("Guarantor Subsidiaries")

- elimination entries necessary to consolidate the Parent and the Guarantor Subsidiaries; and

- the Companies on a consolidated basis.

Financial information for the non-guarantor subsidiaries, all of which are minor, are immaterial and not separately presented in the table below.

F-13

UPSTREAM SUBSIDIARIES OF PLAINS RESOURCES INC.

NOTES TO UNAUDITED COMBINED FINANCIAL STATEMENTS -- (CONTINUED)

UPSTREAM SUBSIDIARIES OF PLAINS RESOURCES INC.

CONSOLIDATING UNAUDITED COMBINED BALANCE SHEET
MARCH 31, 2002

                                                    GUARANTOR     INTERCOMPANY
                                         PARENT    SUBSIDIARIES   ELIMINATIONS   COMBINED
                                         ------    ------------   ------------   --------
                                                          (IN THOUSANDS)
                                          ASSETS
CURRENT ASSETS
  Cash and cash equivalents...........  $      1     $     --       $    --      $       1
  Accounts receivable and other
     current assets...................    13,847        4,449            --         18,296
  Commodity hedging contracts.........       667                         --            667
  Inventories.........................     3,661        1,559            --          5,220
                                        --------     --------       -------      ---------
                                          18,176        6,008            --         24,184
                                        --------     --------       -------      ---------
PROPERTY AND EQUIPMENT, AT COST
  Oil and natural gas
     properties -- full cost method
     Subject to amortization..........   470,319      113,930            --        584,249
     Not subject to amortization......    20,076       14,021            --         34,097
  Other property and equipment........     1,340          196            --          1,536
                                        --------     --------       -------      ---------
                                         491,735      128,147            --        619,882
  Less allowance for depreciation,
     depletion and amortization.......   (60,959)     (86,533)           --       (147,492)
                                        --------     --------       -------      ---------
                                         430,776       41,614            --        472,390
                                        --------     --------       -------      ---------
INVESTMENT IN AND ADVANCES TO
  SUBSIDIARIES........................   (26,617)          --        26,617             --
                                        --------     --------       -------      ---------
OTHER ASSETS..........................    11,073          707            --         11,780
                                        --------     --------       -------      ---------
                                        $433,408     $ 48,329       $26,617      $ 508,354
                                        ========     ========       =======      =========
                         LIABILITIES AND COMBINED OWNERS' EQUITY
CURRENT LIABILITIES
  Accounts payable and other current
     liabilities......................  $ 32,720     $  4,862       $    --      $  37,582
  Commodity hedging contracts.........     7,624        2,515            --         10,139
  Current maturities on long-term
     debt.............................       511           --            --            511
                                        --------     --------       -------      ---------
                                          40,855        7,377            --         48,232
                                        --------     --------       -------      ---------
PAYABLE TO PLAINS RESOURCES INC.......   183,556       66,016            --        249,572
                                        --------     --------       -------      ---------
LONG-TERM DEBT........................     1,022           --            --          1,022
                                        --------     --------       -------      ---------
OTHER LONG-TERM LIABILITIES...........     1,105        2,121            --          3,226
                                        --------     --------       -------      ---------
DEFERRED INCOME TAXES.................    44,097         (568)           --         43,529
                                        --------     --------       -------      ---------
COMBINED OWNERS' EQUITY
  Owners' equity......................   170,067      (24,654)       24,654        170,067
  Accumulated other comprehensive
     income (loss)....................    (7,294)      (1,963)        1,963         (7,294)
                                        --------     --------       -------      ---------
                                         162,773      (26,617)       26,617        162,773
                                        --------     --------       -------      ---------
                                        $433,408     $ 48,329       $26,617      $ 508,354
                                        ========     ========       =======      =========

F-14

UPSTREAM SUBSIDIARIES OF PLAINS RESOURCES INC.

NOTES TO UNAUDITED COMBINED FINANCIAL STATEMENTS -- (CONTINUED)

UPSTREAM SUBSIDIARIES OF PLAINS RESOURCES INC.

CONSOLIDATING UNAUDITED COMBINED BALANCE SHEET
DECEMBER 31, 2001

                                                    GUARANTOR     INTERCOMPANY
                                         PARENT    SUBSIDIARIES   ELIMINATIONS   COMBINED
                                         ------    ------------   ------------   --------
                                                          (IN THOUSANDS)
                                          ASSETS
CURRENT ASSETS
  Cash and cash equivalents...........  $     11     $      2       $     --     $      13
  Accounts receivable and other
     current assets...................    10,703        5,679             --        16,382
  Commodity hedging contracts.........    13,872        7,915             --        21,787
  Inventories.........................     3,252        1,377             --         4,629
                                        --------     --------       --------     ---------
                                          27,838       14,973             --        42,811
                                        --------     --------       --------     ---------
PROPERTY AND EQUIPMENT, AT COST
  Oil and natural gas
     properties -- full cost method
     Subject to amortization..........   450,038      110,996             --       561,034
     Not subject to amortization......    19,676       13,695             --        33,371
  Other property and equipment........     1,322          194             --         1,516
                                        --------     --------       --------     ---------
                                         471,036      124,885             --       595,921
  Less allowance for depreciation,
     depletion and amortization.......   (56,137)     (84,667)            --      (140,804)
                                        --------     --------       --------     ---------
                                         414,899       40,218             --       455,117
                                        --------     --------       --------     ---------
INVESTMENT IN AND ADVANCES TO
  SUBSIDIARIES........................   (21,496)          --         21,496            --
                                        --------     --------       --------     ---------
OTHER ASSETS..........................    16,275        2,552             --        18,827
                                        --------     --------       --------     ---------
                                        $437,516     $ 57,743       $ 21,496     $ 516,755
                                        ========     ========       ========     =========
                         LIABILITIES AND COMBINED OWNERS' EQUITY
CURRENT LIABILITIES
  Accounts payable and other current
     liabilities......................  $ 29,822     $ 11,546       $     --     $  41,368
  Current maturities on long-term
     debt.............................       511           --             --           511
                                        --------     --------       --------     ---------
                                          30,333       11,546             --        41,879
                                        --------     --------       --------     ---------
PAYABLE TO PLAINS RESOURCES INC.......   172,603       62,558             --       235,161
                                        --------     --------       --------     ---------
LONG-TERM DEBT........................     1,022           --             --         1,022
                                        --------     --------       --------     ---------
OTHER LONG-TERM LIABILITIES...........        --        1,413             --         1,413
                                        --------     --------       --------     ---------
DEFERRED INCOME TAXES.................    53,471        3,722             --        57,193
                                        --------     --------       --------     ---------
COMBINED OWNERS' EQUITY
  Owners' equity......................   164,203      (25,889)        25,889       164,203
  Accumulated other comprehensive
     income...........................    15,884        4,393         (4,393)       15,884
                                        --------     --------       --------     ---------
                                         180,087      (21,496)        21,496       180,087
                                        --------     --------       --------     ---------
                                        $437,516     $ 57,743       $ 21,496     $ 516,755
                                        ========     ========       ========     =========

F-15

UPSTREAM SUBSIDIARIES OF PLAINS RESOURCES INC.

NOTES TO UNAUDITED COMBINED FINANCIAL STATEMENTS -- (CONTINUED)

UPSTREAM SUBSIDIARIES OF PLAINS RESOURCES INC.

CONSOLIDATING UNAUDITED COMBINED STATEMENT OF INCOME
THREE MONTHS ENDED MARCH 31, 2002

                                                    GUARANTOR     INTERCOMPANY
                                         PARENT    SUBSIDIARIES   ELIMINATIONS   COMBINED
                                         ------    ------------   ------------   --------
                                                          (IN THOUSANDS)
REVENUES
  Crude oil and liquids................  $27,747     $10,938        $    --      $38,685
  Natural gas..........................    1,988          --             --        1,988
                                         -------     -------        -------      -------
                                          29,735      10,938             --       40,673
                                         -------     -------        -------      -------
COSTS AND EXPENSES
  Production expenses..................   11,981       5,248             --       17,229
  General and administrative...........    2,111         341             --        2,452
  Depreciation, depletion and
     amortization......................    4,824       1,867             --        6,691
                                         -------     -------        -------      -------
                                          18,916       7,456             --       26,372
                                         -------     -------        -------      -------
INCOME FROM OPERATIONS.................   10,819       3,482             --       14,301
OTHER INCOME (EXPENSE)
  Equity in earnings of subsidiaries...    1,235          --         (1,235)          --
  Interest expense.....................   (3,045)     (1,647)            --       (4,692)
  Interest and other income............        9           9             --           18
                                         -------     -------        -------      -------
INCOME BEFORE INCOME TAXES.............    9,018       1,844         (1,235)       9,627
  Income tax (expense) benefit
     Current...........................   (1,365)       (680)            --       (2,045)
     Deferred..........................   (1,789)         71             --       (1,718)
                                         -------     -------        -------      -------
NET INCOME.............................  $ 5,864     $ 1,235        $(1,235)     $ 5,864
                                         =======     =======        =======      =======

F-16

UPSTREAM SUBSIDIARIES OF PLAINS RESOURCES INC.

NOTES TO UNAUDITED COMBINED FINANCIAL STATEMENTS -- (CONTINUED)

UPSTREAM SUBSIDIARIES OF PLAINS RESOURCES INC.

CONSOLIDATING UNAUDITED COMBINED STATEMENT OF INCOME
THREE MONTHS ENDED MARCH 31, 2001

                                                    GUARANTOR     INTERCOMPANY
                                         PARENT    SUBSIDIARIES   ELIMINATIONS   COMBINED
                                         ------    ------------   ------------   --------
                                                          (IN THOUSANDS)
REVENUES
  Crude oil and liquids................  $29,762     $12,839        $    --      $42,601
  Natural gas..........................   11,172          --             --       11,172
                                         -------     -------        -------      -------
                                          40,934      12,839             --       53,773
                                         -------     -------        -------      -------
COSTS AND EXPENSES
  Production expenses..................    8,019       5,351             --       13,370
  General and administrative...........    2,374         412             --        2,786
  Depreciation, depletion and
     amortization......................    4,189       1,175             --        5,364
                                         -------     -------        -------      -------
                                          14,582       6,938             --       21,520
                                         -------     -------        -------      -------
INCOME FROM OPERATIONS.................   26,352       5,901             --       32,253
OTHER INCOME (EXPENSE)
  Equity in earnings of subsidiaries...    3,970          --         (3,970)          --
  Interest expense.....................   (2,631)     (1,560)            --       (4,191)
  Interest and other income............      189         369             --          558
                                         -------     -------        -------      -------
INCOME BEFORE INCOME TAXES AND
  CUMULATIVE EFFECT OF ACCOUNTING
  CHANGE...............................   27,880       4,710         (3,970)      28,620
  Income tax expense
     Current...........................   (1,043)       (889)            --       (1,932)
     Deferred..........................   (9,024)        (91)            --       (9,115)
                                         -------     -------        -------      -------
INCOME BEFORE CUMULATIVE EFFECT OF
  ACCOUNTING CHANGE....................   17,813       3,730         (3,970)      17,573
  Cumulative effect of accounting
     change, net of tax benefit........   (1,762)        240             --       (1,522)
                                         -------     -------        -------      -------
NET INCOME.............................  $16,051     $ 3,970        $(3,970)     $16,051
                                         =======     =======        =======      =======

F-17

UPSTREAM SUBSIDIARIES OF PLAINS RESOURCES INC.

NOTES TO UNAUDITED COMBINED FINANCIAL STATEMENTS -- (CONTINUED)

UPSTREAM SUBSIDIARIES OF PLAINS RESOURCES INC.

CONSOLIDATING UNAUDITED COMBINED STATEMENT OF CASH FLOWS
THREE MONTHS ENDED MARCH 31, 2002

                                                    GUARANTOR     INTERCOMPANY
                                         PARENT    SUBSIDIARIES   ELIMINATIONS   COMBINED
                                         ------    ------------   ------------   --------
                                                         (IN THOUSANDS)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income............................  $  5,864     $ 1,235        $(1,235)     $  5,864
Items not affecting cash flows from
  operating activities:
  Depreciation, depletion and
     amortization.....................     4,824       1,867             --         6,691
  Equity in earnings of
     subsidiaries.....................    (1,235)         --          1,235            --
  Deferred income taxes...............     1,789         (71)            --         1,718
Change in assets and liabilities from
  operating activities:
  Accounts receivable and other
     assets...........................    (3,430)      3,074             --          (356)
  Inventories.........................      (409)       (182)            --          (591)
  Accounts payable and other
     liabilities......................     2,188      (5,976)            --        (3,788)
                                        --------     -------        -------      --------
Net cash provided by operating
  activities..........................     9,591         (53)            --         9,538
                                        --------     -------        -------      --------
CASH FLOWS FROM INVESTING ACTIVITIES
Acquisition, exploration and
  developments costs..................   (20,681)     (3,260)            --       (23,941)
Additions to other property and
  equipment...........................       (18)         (2)            --           (20)
                                        --------     -------        -------      --------
Net cash used in investing
  activities..........................   (20,699)     (3,262)            --       (23,961)
                                        --------     -------        -------      --------
CASH FLOWS FROM FINANCING ACTIVITIES
Receipts from (payments to) Plains
  Resources Inc. .....................    11,098       3,313             --        14,411
                                        --------     -------        -------      --------
Net cash provided by (used in)
  financing activities................    11,098       3,313             --        14,411
                                        --------     -------        -------      --------
Net increase (decrease) in cash and
  cash equivalents....................       (10)         (2)            --           (12)
Cash and cash equivalents, beginning
  of year.............................        11           2             --            13
                                        --------     -------        -------      --------
Cash and cash equivalents, end of
  year................................  $      1     $    --        $    --      $      1
                                        ========     =======        =======      ========

F-18

UPSTREAM SUBSIDIARIES OF PLAINS RESOURCES INC.

NOTES TO UNAUDITED COMBINED FINANCIAL STATEMENTS -- (CONTINUED)

UPSTREAM SUBSIDIARIES OF PLAINS RESOURCES INC.

CONSOLIDATING UNAUDITED COMBINED STATEMENT OF CASH FLOWS
THREE MONTHS ENDED MARCH 31, 2001

                                                    GUARANTOR     INTERCOMPANY
                                         PARENT    SUBSIDIARIES   ELIMINATIONS   COMBINED
                                         ------    ------------   ------------   --------
                                                         (IN THOUSANDS)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income............................  $ 16,051     $ 3,970        $(3,970)     $ 16,051
Items not affecting cash flows from
  operating activities:
  Depreciation, depletion and
     amortization.....................     4,189       1,175             --         5,364
  Equity in earnings of
     subsidiaries.....................    (3,970)         --          3,970            --
  Deferred income taxes...............     9,024          91             --         9,115
  Cumulative effect of adoption of
     accounting change................     1,762        (240)            --         1,522
  Change in derivative fair value.....        (7)      1,062             --         1,055
  Other noncash items.................        12         727             --           739
Change in assets and liabilities from
  operating activities:
  Accounts receivable and other
     assets...........................    (2,708)       (736)            --        (3,444)
  Inventories.........................      (844)       (763)            --        (1,607)
  Accounts payable and other
     liabilities......................     7,689        (526)            --         7,163
                                        --------     -------        -------      --------
Net cash provided by operating
  activities..........................    31,198       4,760             --        35,958
                                        --------     -------        -------      --------
CASH FLOWS FROM INVESTING ACTIVITIES
Acquisition, exploration and
  developments costs..................   (23,173)     (3,715)            --       (26,888)
Additions to other property and
  equipment...........................       (83)         (3)            --           (86)
                                        --------     -------        -------      --------
Net cash used in investing
  activities..........................   (23,256)     (3,718)            --       (26,974)
                                        --------     -------        -------      --------
CASH FLOWS FROM FINANCING ACTIVITIES
Receipts from (payments to) Plains
  Resources Inc. .....................    (7,938)       (462)            --        (8,400)
                                        --------     -------        -------      --------
Net cash provided by (used in)
  financing activities................    (7,938)       (462)            --        (8,400)
                                        --------     -------        -------      --------
Net increase (decrease) in cash and
  cash equivalents....................         4         580             --           584
Cash and cash equivalents, beginning
  of year.............................       240         296             --           536
                                        --------     -------        -------      --------
Cash and cash equivalents, end of
  year................................  $    244     $   876        $    --      $  1,120
                                        ========     =======        =======      ========

F-19

REPORT OF INDEPENDENT ACCOUNTANTS

To the Board of Directors
of Plains Resources Inc.

In our opinion, the combined financial statements listed in the accompanying index present fairly, in all material respects, the financial position of the Upstream Subsidiaries of Plains Resources Inc. (collectively, the "Company") at December 31, 2001 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2001, in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note 2 to the combined financial statements, the Company changed its method of accounting for derivative instruments and hedging activities, effective January 1, 2001.

PricewaterhouseCoopers LLP

Houston, Texas
April 17, 2002

F-20

UPSTREAM SUBSIDIARIES OF PLAINS RESOURCES INC.

COMBINED BALANCE SHEETS

                                                                  DECEMBER 31,
                                                              ---------------------
                                                                2001        2000
                                                                ----        ----
                                                                 (IN THOUSANDS)
                                      ASSETS
CURRENT ASSETS
  Cash and cash equivalents.................................  $      13   $     536
  Accounts receivable and other current assets..............     16,382      32,878
  Commodity hedging contracts...............................     21,787          --
  Inventories...............................................      4,629       4,038
                                                              ---------   ---------
                                                                 42,811      37,452
                                                              ---------   ---------
PROPERTY AND EQUIPMENT, AT COST
  Oil and natural gas properties -- full cost method
     Subject to amortization................................    561,034     433,915
     Not subject to amortization............................     33,371      34,737
  Other property and equipment..............................      1,516       1,389
                                                              ---------   ---------
                                                                595,921     470,041
  Less allowance for depreciation, depletion and
     amortization...........................................   (140,804)   (116,697)
                                                              ---------   ---------
                                                                455,117     353,344
                                                              ---------   ---------
OTHER ASSETS................................................     18,827      10,239
                                                              ---------   ---------
                                                              $ 516,755   $ 401,035
                                                              =========   =========

                      LIABILITIES AND COMBINED OWNERS' EQUITY
CURRENT LIABILITIES
  Accounts payable and other current liabilities............  $  41,368   $  43,802
  Current maturities on long-term debt......................        511         511
                                                              ---------   ---------
                                                                 41,879      44,313
                                                              ---------   ---------
PAYABLE TO PLAINS RESOURCES INC.............................    235,161     224,996
                                                              ---------   ---------
LONG-TERM DEBT..............................................      1,022       1,533
                                                              ---------   ---------
OTHER LONG-TERM LIABILITIES.................................      1,413          --
                                                              ---------   ---------
DEFERRED INCOME TAXES.......................................     57,193      19,161
                                                              ---------   ---------
COMMITMENTS AND CONTINGENCIES (NOTE 6)
COMBINED OWNERS' EQUITY
  Owners' equity............................................    164,203     111,032
  Accumulated other comprehensive income....................     15,884          --
                                                              ---------   ---------
                                                                180,087     111,032
                                                              ---------   ---------
                                                              $ 516,755   $ 401,035
                                                              =========   =========

See notes to combined financial statements.

F-21

UPSTREAM SUBSIDIARIES OF PLAINS RESOURCES INC.

COMBINED STATEMENTS OF INCOME

                                                               YEAR ENDED DECEMBER 31,
                                                            ------------------------------
                                                              2001       2000       1999
                                                              ----       ----       ----
                                                                    (IN THOUSANDS)
REVENUES
  Crude oil and liquids...................................  $174,895   $126,434   $102,390
  Natural gas.............................................    28,771     16,017      5,095
  Other operating revenues................................       473         --         --
                                                            --------   --------   --------
                                                             204,139    142,451    107,485
                                                            --------   --------   --------
COSTS AND EXPENSES
  Production expenses.....................................    63,795     56,228     50,527
  General and administrative..............................    10,210      6,308      4,367
  Depreciation, depletion and amortization................    24,105     18,859     13,329
                                                            --------   --------   --------
                                                              98,110     81,395     68,223
                                                            --------   --------   --------
INCOME FROM OPERATIONS....................................   106,029     61,056     39,262
OTHER INCOME (EXPENSE)
  Interest expense........................................   (17,411)   (15,885)   (14,912)
  Interest and other income...............................       463        343         87
                                                            --------   --------   --------
INCOME BEFORE INCOME TAXES AND CUMULATIVE EFFECT OF
  ACCOUNTING CHANGE.......................................    89,081     45,514     24,437
  Income tax expense
     Current..............................................    (6,014)    (2,431)      (505)
     Deferred.............................................   (28,374)   (14,334)    (4,827)
                                                            --------   --------   --------
INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE......    54,693     28,749     19,105
  Cumulative effect of accounting change, net of tax
     benefit..............................................    (1,522)        --         --
                                                            --------   --------   --------
NET INCOME................................................  $ 53,171   $ 28,749   $ 19,105
                                                            ========   ========   ========

See notes to combined financial statements.

F-22

UPSTREAM SUBSIDIARIES OF PLAINS RESOURCES INC.

COMBINED STATEMENTS OF CASH FLOWS

                                                               YEAR ENDED DECEMBER 31,
                                                               -----------------------
                                                             2001        2000       1999
                                                             ----        ----       ----
                                                                   (IN THOUSANDS)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income...............................................  $  53,171   $ 28,749   $ 19,105
Items not affecting cash flows from operating activities:
  Depreciation, depletion and amortization...............     24,105     18,859     13,329
  Deferred income taxes..................................     28,374     14,334      4,827
  Cumulative effect of adoption of accounting change.....      1,522         --         --
  Change in derivative fair value........................      1,055         --         --
  Other noncash items....................................      3,206         --         --
Change in assets and liabilities from operating
  activities:
  Accounts receivable and other assets...................      9,197      7,597    (31,616)
  Inventories............................................       (591)      (195)      (586)
  Accounts payable and other liabilities.................     (1,021)    10,120       (450)
                                                           ---------   --------   --------
Net cash provided by operating activities................    119,018     79,464      4,609
                                                           ---------   --------   --------
CASH FLOWS FROM INVESTING ACTIVITIES
Acquisition, exploration and developments costs..........   (125,753)   (70,505)   (59,167)
Additions to other property and assets...................       (127)      (366)      (195)
                                                           ---------   --------   --------
Net cash used in investing activities....................   (125,880)   (70,871)   (59,362)
                                                           ---------   --------   --------
CASH FLOWS FROM FINANCING ACTIVITIES
Principal payments of long-term debt.....................       (511)      (511)      (511)
Receipts from (payments to) Plains Resources Inc. .......      6,850    (12,621)    60,201
                                                           ---------   --------   --------
Net cash provided by (used in) financing activities......      6,339    (13,132)    59,690
                                                           ---------   --------   --------
Net increase (decrease) in cash and cash equivalents.....       (523)    (4,539)     4,937
Cash and cash equivalents, beginning of year.............        536      5,075        138
                                                           ---------   --------   --------
Cash and cash equivalents, end of year...................  $      13   $    536   $  5,075
                                                           =========   ========   ========

See notes to combined financial statements.

F-23

UPSTREAM SUBSIDIARIES OF PLAINS RESOURCES INC.

COMBINED STATEMENTS OF COMPREHENSIVE INCOME

                                                                YEAR ENDED DECEMBER 31,
                                                                -----------------------
                                                               2001      2000      1999
                                                               ----      ----      ----
                                                                    (IN THOUSANDS)
NET INCOME..................................................  $53,171   $28,749   $19,105
OTHER COMPREHENSIVE INCOME:
  Unrealized gains on derivatives:
     Cumulative effect of accounting change, net of taxes of
       $4,454...............................................    6,967        --        --
     Unrealized gains arising during the year, net of taxes
       of $8,566............................................   12,518        --        --
     Reclassification adjustment for gains realized in net
       income, net of tax benefit of $2,320.................   (3,601)       --        --
                                                              -------   -------   -------
Other Comprehensive Income..................................   15,884        --        --
                                                              -------   -------   -------
COMPREHENSIVE INCOME........................................  $69,055   $28,749   $19,105
                                                              =======   =======   =======

See notes to combined financial statements.

F-24

UPSTREAM SUBSIDIARIES OF PLAINS RESOURCES INC.

COMBINED STATEMENTS OF COMBINED OWNERS' EQUITY

                                                                 YEAR ENDED DECEMBER 31,
                                                                 -----------------------
                                                                2001       2000      1999
                                                                ----       ----      ----
                                                                     (IN THOUSANDS)
OWNERS' EQUITY
  Balance, beginning of year................................  $111,032   $ 82,283   $63,177
  Net income................................................    53,171     28,749    19,105
  Issuance of common stock..................................        --         --         1
                                                              --------   --------   -------
  Balance, end of year......................................   164,203    111,032    82,283
                                                              --------   --------   -------
ACCUMULATED OTHER COMPREHENSIVE INCOME
  Balance, beginning of year................................        --         --        --
  Other comprehensive income................................    15,884         --        --
                                                              --------   --------   -------
  Balance, end of year......................................    15,884         --        --
                                                              --------   --------   -------
COMBINED OWNERS' EQUITY.....................................  $180,087   $111,032   $82,283
                                                              ========   ========   =======

See notes to combined financial statements.

F-25

UPSTREAM SUBSIDIARIES OF PLAINS RESOURCES INC.

NOTES TO COMBINED FINANCIAL STATEMENTS

NOTE 1 -- ORGANIZATION AND SIGNIFICANT ACCOUNTING POLICIES

ORGANIZATION

The combined financial statements of the Upstream Subsidiaries of Plains Resources Inc. (the "Companies", "our", or "we") include the accounts of Stocker Resources, L.P., Arguello Inc., Plains Illinois, Inc. and Plains Resources International Inc., Arguello Inc., Plains Illinois, Inc., PMCT Inc. and Plains Resources International Inc. are wholly-owned subsidiaries of Plains Resources Inc. ("Plains"). Stocker Resources, L.P. is a limited partnership of which Stocker Resources, Inc., a wholly owned subsidiary of Plains, is the general partner (holding a 2.5% interest) and Plains is the limited partner (holding a 97.5% interest). All significant intercompany transactions have been eliminated.

We are independent energy companies that are engaged in the "Upstream" oil and gas business. The Upstream business acquires, exploits, develops, explores for and produces crude oil and natural gas. Our Upstream activities are all located in the United States.

Under the terms of a service agreement (the "Service Agreement"), Plains provides the Companies with financial intermediary, treasury and other services as may be required from time to time. Such services include, but are not limited to: arranging financings and commercial transactions for the procurement of funds and other commercial accommodations from financial institutions and other lenders; disbursement of capital and operating funds in the form of loans or intercompany advances; maintenance of financial records and books of account; and cash management, including the processing of cash receipts and disbursements.

These financial statements include allocations of direct and indirect corporate and administrative costs of Plains. The methods by which such costs are estimated and allocated to the Companies are deemed reasonable by Plains' management; however, such allocations and estimates are not necessarily indicative of the costs and expenses that would have been incurred had we operated as a separate entity. Allocations of such costs are considered to be related party transactions and are discussed in Note 4.

SIGNIFICANT ACCOUNTING POLICIES

Oil and Gas Properties. We follow the full cost method of accounting whereby all costs associated with property acquisition, exploration, exploitation and development activities are capitalized. Such costs include internal general and administrative costs such as payroll and related benefits and costs directly attributable to employees engaged in acquisition, exploration, exploitation and development activities. General and administrative costs associated with production, operations, marketing and general corporate activities are expensed as incurred. These capitalized costs along with our estimate of future development and abandonment costs, net of salvage values and other considerations, are amortized to expense by the unit-of-production method using engineers' estimates of proved oil and natural gas reserves. The costs of unproved properties are excluded from amortization until the properties are evaluated. Interest is capitalized on oil and natural gas properties not subject to amortization and in the process of development. Proceeds from the sale of oil and natural gas properties are accounted for as reductions to capitalized costs unless such sales involve a significant change in the relationship between costs and the estimated value of proved reserves, in which case a gain or loss is recognized. Unamortized costs of proved properties are subject to a ceiling which limits such costs to the present value of estimated future cash flows from proved oil and natural gas reserves of such properties (including the effect of any related hedging activities) reduced by future operating expenses, development expenditures and abandonment costs (net of salvage values), and estimated future income taxes thereon.

F-26

UPSTREAM SUBSIDIARIES OF PLAINS RESOURCES INC.

NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)

Other Property and Equipment. Other property and equipment is recorded at cost and consists primarily of office furniture and fixtures and computer hardware and software. Acquisitions, renewals, and betterments are capitalized; maintenance and repairs are expensed. Depreciation is provided using the straight-line method over estimated useful lives of three to seven years. Net gains or losses on property and equipment disposed of are included in interest and other income in the period in which the transaction occurs.

Use of Estimates. The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Significant estimates made by management include
(1) crude oil and natural gas reserves, (2) depreciation, depletion and amortization, including future abandonment costs, (3) income taxes and (4) accrued liabilities. Although management believes these estimates are reasonable, actual results could differ from these estimates.

Cash and Cash Equivalents. Cash and cash equivalents consist of all demand deposits and funds invested in highly liquid instruments with original maturities of three months or less. At December 31, 2001 and 2000, the majority of cash and cash equivalents is concentrated in one institution and at times may exceed federally insured limits. We periodically assess the financial condition of the institution and believe that any possible credit risk is minimal.

Inventory. Crude oil inventories are carried at the lower of cost to produce or market value. Materials and supplies inventory is stated at the lower of cost or market with cost determined on an average cost method. Inventory consists of the following (in thousands):

                                                               DECEMBER 31,
                                                              ---------------
                                                               2001     2000
                                                               ----     ----
Crude oil...................................................  $4,201   $3,487
Materials and supplies......................................     428      551
                                                              ------   ------
                                                              $4,629   $4,038
                                                              ======   ======

Other Assets. Other assets consists of the following (in thousands):

                                                                DECEMBER 31,
                                                              -----------------
                                                               2001      2000
                                                               ----      ----
Land........................................................  $ 8,103   $ 8,103
Commodity hedging contracts.................................    5,627        --
Other.......................................................    5,097     2,136
                                                              -------   -------
                                                              $18,827   $10,239
                                                              =======   =======

Federal and State Income Taxes. Income taxes are accounted for in accordance with Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes ("SFAS 109"). SFAS 109 requires recognition of deferred tax liabilities and assets for the expected future tax consequences of events that have been included in the financial statements or tax returns. Under this method, deferred tax liabilities and assets are determined based on the difference between the financial statement and tax bases of assets and liabilities using tax rates in effect for the year in which the differences are expected to reverse. A valuation allowance is established to reduce deferred tax assets if it is more than likely than not that the related tax benefits will not be realized.

F-27

UPSTREAM SUBSIDIARIES OF PLAINS RESOURCES INC.

NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)

The taxable income or loss of the Companies is included in the consolidated income tax returns filed by Plains. Income tax obligations reflected in these financial statements are based on the tax sharing agreement among all the members of the consolidated group. Such agreement provides that income taxes are calculated assuming the combined companies filed a separate income tax return. Income taxes payable are included in Payable to Plains Resources, Inc. in the combined balance sheet.

Revenue Recognition. Oil and gas revenue from our interests in producing wells is recognized when the production is delivered and the title transfers.

Derivative Financial Instruments (Hedging). We utilize various derivative instruments to reduce our exposure to fluctuations in the market price of crude oil. The derivative instruments consist primarily of crude oil swap and option contracts entered into with financial institutions.

Recent Accounting Pronouncements. The following Statements of Financial Accounting Standards ("SFAS") were issued in June 2001: SFAS No. 141, Business Combinations, SFAS No. 142, Goodwill and Other Intangible Assets, and SFAS No. 143, Accounting for Asset Retirement Obligations. In August 2001, SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets was also issued. SFAS No. 141 requires the use of the purchase method of accounting for all business combinations. It applies to all business combinations initiated after June 30, 2001 and to all business combinations accounted for by the purchase method that are completed after June 30, 2001. SFAS No. 142 requires that goodwill as well as other intangible assets with indefinite lives not be amortized but be tested annually for impairment and is effective for fiscal years beginning after December 15, 2001. SFAS No. 144 addresses financial accounting and reporting for the impairment of long-lived assets and long-lived assets to be disposed of. It supersedes, with exceptions, SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of and is effective for fiscal years beginning after December 15, 2001. SFAS No. 141, No. 142 and No. 144 had no effect on our financial statements. We will account for all future business combinations and any related goodwill in accordance with the provisions of SFAS No. 141 and SFAS No. 142.

SFAS No. 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. Subsequently, the asset retirement cost should be allocated to expense using a systematic and rational method. SFAS No. 143 is effective for fiscal years beginning after June 15, 2002. The Company is currently assessing the impact of SFAS No. 143 and at this time cannot reasonably estimate the effect of this statement on its consolidated financial position, results of operations or cash flows.

NOTE 2 -- DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

Plains entered into various derivative instruments on behalf of the Companies to reduce our exposure to fluctuations in the market price of crude oil. The derivative instruments consist primarily of crude oil swap and option contracts entered into with financial institutions. In accordance with the terms of the Services Agreement, the gains and losses with respect to such instruments have been allocated to the Companies. Oil revenues for the year ended December 31, 2001 have been increased by $0.3 million and oil revenues for the years ended December 31, 2000 and 1999 have been reduced by $72.8 million and $7.5 million, respectively, as a result of such transactions.

F-28

UPSTREAM SUBSIDIARIES OF PLAINS RESOURCES INC.

NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)

On January 1, 2001, we adopted Statement of Financial Accounting Standards ("SFAS") No. 133 "Accounting for Derivative Instruments and Hedging Activities" as amended by SFAS 137 and SFAS 138 ("SFAS 133"). Under SFAS 133, all derivative instruments are recorded on the balance sheet at fair value. If the derivative does not qualify as a hedge or is not designated as a hedge, the gain or loss on the derivative is recognized currently in earnings. To qualify for hedge accounting, the derivative must qualify either as a fair value hedge, cash flow hedge or foreign currency hedge. Currently, we use only cash flow hedges and the remaining discussion will relate exclusively to this type of derivative instrument. If the derivative qualifies for hedge accounting, the gain or loss on the derivative is deferred in Other Comprehensive Income ("OCI"), a component of Combined Owners' Equity to the extent the hedge is effective.

The relationship between the hedging instrument and the hedged item must be highly effective in achieving the offset of changes in cash flows attributable to the hedged risk both at the inception of the contract and on an ongoing basis. Hedge accounting is discontinued prospectively when a hedge instrument becomes ineffective. Gains and losses deferred in OCI related to cash flow hedges that become ineffective remain unchanged until the related product is delivered. If it is determined that it is probable that a hedged forecasted transaction will not occur, deferred gains or losses on the hedging instrument are recognized in earnings immediately.

We formally document all relationships between hedging instruments and hedged items, as well as our risk management objectives and strategy for undertaking the hedge. Hedge effectiveness is measured on a quarterly basis. This process includes specific identification of the hedging instrument and the hedge transaction, the nature of the risk being hedged and how the hedging instrument's effectiveness will be assessed. Both at the inception of the hedge and on an ongoing basis, we assess whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in cash flows of hedged items. No amounts were excluded from the computation of hedge effectiveness. At December 31, 2001, all open positions qualified for hedge accounting.

Unrealized gains and losses on hedging instruments reflected in OCI and adjustments to carrying amounts on hedged volumes are included in oil and gas revenues in the period that the related volumes are delivered. Gains and losses from hedging instruments, which represent hedge ineffectiveness as well as any amounts excluded from the assessment of hedge effectiveness, are recognized currently in oil and gas revenues. Effective October 2001, we implemented Derivatives Implementation Group ("DIG") Issue G20, "Cash Flow Hedges: Assessing and Measuring the Effectiveness of a Purchased Option Used in a Cash Flow Hedge", which provides guidance for assessing the effectiveness on total changes in an option's cash flows rather than only on changes in the option's intrinsic value. Implementation of this DIG issue will reduce earnings volatility since it allows us to include changes in the time value of purchased options and collars in the assessment of hedge effectiveness. Time value changes were previously recognized in current earnings since we excluded time value changes from the assessment of hedge effectiveness. Oil and gas revenues for the year ended December 31, 2001 include a $3.1 million non-cash loss related to the ineffective portion of the cash flow hedges representing the fair value change in the time value of options for the nine months prior to the implementation of DIG Issue G20.

We utilize various derivative instruments to hedge our exposure to price fluctuations on crude oil sales. The derivative instruments consist primarily of cash-settled crude oil option and

F-29

UPSTREAM SUBSIDIARIES OF PLAINS RESOURCES INC.

NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)

swap contracts entered into with financial institutions. We do not currently have any natural gas hedges. At December 31, 2001, we had the following open crude oil hedge positions:

                                                               BARRELS PER
                                                                   DAY
                                                               -----------
                                                               2002    2003
                                                               ----    ----
Calls
  Average price $35.17/bbl..................................   9,000      --
Swaps
  Average price $24.00/bbl..................................  17,000      --
  Average price $23.16/bbl..................................      --   7,500

On January 1, 2001, in accordance with the transition provisions of SFAS 133, we recorded a gain of $7.0 million in OCI, representing the cumulative effect of an accounting change to recognize at fair value all cash flow derivatives. We recorded cash flow hedge derivative assets and liabilities of $9.7 million and $4.2 million, respectively, and a net-of-tax non-cash charge of $1.5 million was recorded in earnings as a cumulative effect adjustment.

For the year ended December 31, 2001, net unrealized gains of $8.9 million were added to OCI, and the fair value of open positions increased $15.2 million.

At December 31, 2001, net unrealized gains on our option and swap contracts included in OCI was $15.9 million. The related assets and liabilities were included in commodity hedging contracts and other derivatives ($21.8 million), other assets ($5.6 million), and deferred income taxes ($10.7 million). As of December 31, 2001, $12.5 million of deferred net gains on derivative instruments recorded in OCI are expected to be reclassified to earnings during the next twelve-month period.

NOTE 3 -- LONG-TERM DEBT

Long-term debt and the related current maturities represents a note issued in connection with the purchase of a production payment on certain of our producing properties. The note bears interest at 8%, payable annually, and requires an annual principal payment of $511,000 through 2004.

NOTE 4 -- RELATED PARTY TRANSACTIONS

We use a centralized cash management system under which our cash receipts are remitted to Plains and our cash disbursements are funded by Plains. We are charged interest on any amounts, other than income taxes payable, due to Plains at the average effective interest rate of Plains long-term debt. For the years 2001, 2000 and 1999 we were charged $20.4 million, $19.5 million and $18.3 million, respectively, of interest on amounts payable to Plains. Of such amounts, $17.3 million, $15.7 million and $14.7 million was included in interest expense in 2001, 2000 and 1999, respectively, and the remainder was capitalized in oil and gas properties

To compensate Plains for services rendered under the Services Agreement, we are allocated direct and indirect corporate and administrative costs of Plains. Such costs totaled $8.2 million, $3.9 million and $3.1 million in 2001, 2000 and 1999, respectively. Of such amounts, $6.1 million, $2.8 million and $2.2 million was included in general and administrative expense in 2001, 2000 and 1999, respectively, and the remainder was capitalized in oil and gas properties.

In addition, as discussed in Note 2, Plains entered into various derivative instruments to reduce our exposure to decreases in the market price of crude oil.

F-30

UPSTREAM SUBSIDIARIES OF PLAINS RESOURCES INC.

NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)

At December 31, 2001 Plains had $267.5 million principal amount of 10.25% Senior Subordinated Notes due 2006 outstanding. Such notes are guaranteed by the Companies on a full, unconditional, joint and several basis.

Plains All American Pipeline, L.P. ("PAA"), an affiliate of Plains, is the exclusive marketer/ purchaser for all of our equity crude oil production. The marketing agreement provides that PAA will purchase for resale at market prices all of our equity crude oil production, for which PAA charges a fee of $0.20 per barrel. In 2001, 2000 and 1999, we were paid $202.1 million, $222.7 million and $114.6 million, respectively, for the purchase of crude oil under the agreement, including the royalty share of production. Accounts receivable and other current assets at December 31, 2001 and 2000 include $12.3 million and $17.6 million, respectively, of amounts receivable from PAA with respect to oil sales.

NOTE 5 -- INCOME TAXES

Our taxable income or loss is included in the consolidated income tax returns filed by Plains. Income tax obligations reflected in these financial statements are based on the tax sharing agreement which provides that income taxes are calculated assuming we filed a separate combined income tax return. Currently payable income taxes are included in Payable to Plains Resources, Inc. in the combined balance sheet.

Our deferred income tax assets and liabilities at December 31, 2001 and 2000 consist of the tax effect of income tax carryforwards and differences related to the timing of recognition of certain types of costs as follows (in thousands):

                                                                 DECEMBER 31,
                                                              -------------------
                                                                2001       2000
                                                                ----       ----
U.S. FEDERAL
Deferred tax assets:
  Tax credit carryforwards..................................  $     --   $  1,181
  Other.....................................................       658        646
                                                              --------   --------
                                                                   658      1,827
Deferred tax liabilities:
  Net oil and gas acquisition, exploration and development
     costs..................................................   (36,520)   (15,807)
  Commodity hedging contracts and other.....................   (10,700)        --
                                                              --------   --------
  Net deferred tax liability................................   (46,562)   (13,980)
STATES
Deferred tax liability......................................   (10,631)    (5,181)
                                                              --------   --------
Net deferred tax liability..................................  $(57,193)  $(19,161)
                                                              ========   ========

At December 31, 2001, for federal income tax purposes, we have no carryforwards of regular tax net operating losses, alternative minimum tax credits or enhanced oil recovery credits.

F-31

UPSTREAM SUBSIDIARIES OF PLAINS RESOURCES INC.

NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)

Set forth below is a reconciliation between the income tax provision computed at the United States statutory rate on income before income taxes and the income tax provision in the accompanying consolidated statements of income (in thousands):

                                                                      YEAR ENDED
                                                                     DECEMBER 31,
                                                              ---------------------------
                                                               2001      2000      1999
                                                               ----      ----      ----
U.S. federal income tax provision at statutory rate.........  $31,101   $15,935   $ 8,553
State income taxes, net of federal benefit..................    4,758     2,232     1,211
Full cost ceiling test limitation...........................       --        --    (3,772)
Other.......................................................   (1,471)   (1,402)     (660)
                                                              -------   -------   -------
Income tax expense on income before effect of accounting
  change....................................................   34,388    16,765     5,332
Income tax benefit allocated to cumulative effect of
  accounting change.........................................   (1,042)       --        --
                                                              -------   -------   -------
Income tax provision........................................  $33,346   $16,765   $ 5,332
                                                              =======   =======   =======

NOTE 6 -- COMMITMENTS, CONTINGENCIES AND INDUSTRY CONCENTRATION

COMMITMENTS AND CONTINGENCIES

We lease certain real property, equipment and operating facilities under various operating leases. Future non-cancelable commitments related to these items at December 31, 2001 total $53,100, all of which relates to 2002. Total expenses related to such commitments for the years ended December 31, 2001, 2000 and 1999 were $41,000, $45,000 and $61,000, respectively.

Under the amended terms of an asset purchase agreement with respect to certain of our onshore California properties, commencing with the year beginning January 1, 2000, and each year thereafter, we are required to plug and abandon 20% of the then remaining inactive wells, which currently aggregate approximately 149. To the extent we elect not to plug and abandon the number of required wells, we are required to escrow an amount equal to the greater of $25,000 per well or the actual average plugging cost per well in order to provide for the future plugging and abandonment of such wells. In addition, we are required to expend a minimum of $600,000 per year in each of the ten years beginning January 1, 1996, and $300,000 per year in each of the succeeding five years to remediate oil contaminated soil from existing well sites, provided there are remaining sites to be remediated. In the event we do not expend the required amounts during a calendar year, we are required to contribute an amount equal to 125% of the actual shortfall to an escrow account. We may withdraw amounts from the escrow account to the extent we expend excess amounts in a future year. Through December 31, 2001, we have not been required to make contributions to an escrow account.

In connection with the acquisition of our interest in the Point Arguello field, offshore California, we assumed our 26% share of (1) plugging and abandoning all existing well bores, (2) removing conductors, (3) flushing hydrocarbons from all lines and vessels and (4) removing/abandoning all structures, fixtures and conditions created subsequent to closing. The seller retained the obligation for all other abandonment costs, including but not limited to (1) removing, dismantling and disposing of the existing offshore platforms, (2) removing and disposing of all existing pipelines and (3) removing, dismantling, disposing and remediation of all existing onshore facilities.

Although we obtained environmental studies on our properties in California and Illinois and we believe that such properties have been operated in accordance with standard oil field

F-32

UPSTREAM SUBSIDIARIES OF PLAINS RESOURCES INC.

NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)

practices, certain of the fields have been in operation for more than 90 years, and current or future local, state and federal environmental laws and regulations may require substantial expenditures to comply with such rules and regulations. In connection with the purchase of certain of our onshore California properties, we received a limited indemnity for certain conditions if they violate applicable local, state and federal environmental laws and regulations in effect on the date of such agreement. We believe that we do not have any material obligations for operations conducted prior to our acquisition of the properties, other than our obligation to plug existing wells and those normally associated with customary oil field operations of similarly situated properties. There can be no assurance that current or future local, state or federal rules and regulations will not require us to spend material amounts to comply with such rules and regulations or that any portion of such amounts will be recoverable under the indemnity.

Consistent with normal industry practices, substantially all of our crude oil and natural gas leases require that, upon termination of economic production, the working interest owners plug and abandon non-producing wellbores, remove tanks, production equipment and flow lines and restore the wellsite. We have estimated that the costs to perform these tasks is approximately $12.0 million, net of salvage value and other considerations. Such estimated costs are amortized to expense through the unit-of-production method as a component of accumulated depreciation, depletion and amortization. Results from operations for 2001, 2000 and 1999 include $0.5 million, $0.2 million and $0.2 million, respectively, of expense associated with these estimated future costs. For valuation and realization purposes of the affected crude oil and natural gas properties, these estimated future costs are also deducted from estimated future gross revenues to arrive at the estimated future net revenues and the Standardized Measure disclosed in Note 8.

As is common within the industry, we have entered into various commitments and operating agreements related to the exploration and development of and production from proved crude oil and natural gas properties and the marketing, transportation, terminalling and storage of crude oil. It is management's belief that such commitments will be met without a material adverse effect on our financial position, results of operations or cash flows.

INDUSTRY CONCENTRATION

Financial instruments which potentially subject us to concentrations of credit risk consist principally of accounts receivable with respect to our oil and gas operations and derivative instruments related to our hedging activities. PAA is the exclusive marketer/purchaser for all of our equity oil production. This concentration has the potential to impact our overall exposure to credit risk, either positively or negatively, in that PAA may be affected by changes in economic, industry or other conditions. We do not believe the loss of PAA as the exclusive purchaser of our equity production would have a material adverse affect on our results of operations. We believe PAA could be replaced by other purchasers under contracts with similar terms and conditions. The contract counterparties for our derivative commodity contracts are all major financial institutions with Standard & Poor's ratings of A or better. Three of the financial institutions are participating lenders in Plains' revolving credit facility, with one such counterparty holding contracts that represent approximately 37% of the fair value of all of Plains' open positions at December 31, 2001.

There are a limited number of alternative methods of transportation for our production. Substantially all of our oil and gas production is transported by pipelines, trucks and barges owned by third parties. The inability or unwillingness of these parties to provide transportation services to us for a reasonable fee could result in our having to find transportation alternatives,

F-33

UPSTREAM SUBSIDIARIES OF PLAINS RESOURCES INC.

NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)

increased transportation costs or involuntary curtailment of a significant portion of our oil and gas production which could have a negative impact on future results of operations or cash flows.

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

NOTE 7 -- FINANCIAL INSTRUMENTS

The disclosure of the estimated fair value of financial instruments is made in accordance with the requirements of Statement of Financial Accounting Standards No. 107, Disclosures About Fair Value of Financial Instruments. Considerable judgment is required to develop estimates of fair value. The use of different assumptions or valuation methodologies may have a material effect on estimated fair value amounts.

The carrying values of items comprising current assets and current liabilities approximate fair values due to the short-term maturities of these instruments. Derivative financial instruments included other assets are stated at fair value. The carrying value of our payable to Plains approximates its fair value, as interest rates are variable, based on prevailing market rates. The fair value of our long-term debt is estimated to equal its carrying value.

NOTE 8 -- CRUDE OIL AND NATURAL GAS ACTIVITIES

COSTS INCURRED

Our oil and natural gas acquisition, exploration, exploitation and development activities are conducted in the United States. The following table summarizes the costs incurred during the last three years (in thousands).

                                                                YEAR ENDED DECEMBER 31,
                                                              ----------------------------
                                                                2001      2000      1999
                                                                ----      ----      ----
Property acquisitions costs:
  Unproved properties.......................................  $     44   $    73   $   879
  Proved properties.........................................     1,645     1,953     2,496
Exploration costs...........................................       286       293       796
Exploitation and development costs..........................   123,778    68,186    54,996
                                                              --------   -------   -------
                                                              $125,753   $70,505   $59,167
                                                              ========   =======   =======

CAPITALIZED COSTS

The following table presents the aggregate capitalized costs subject to amortization relating to our crude oil and natural gas acquisition, exploration, exploitation and development activities, and the aggregate related accumulated DD&A (in thousands).

                                                                  DECEMBER 31,
                                                              ---------------------
                                                                2001        2000
                                                                ----        ----
Proved properties...........................................  $ 561,034   $ 433,915
Accumulated DD&A............................................   (139,797)   (116,066)
                                                              ---------   ---------
                                                              $ 421,237   $ 317,849
                                                              =========   =========

F-34

UPSTREAM SUBSIDIARIES OF PLAINS RESOURCES INC.

NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)

The DD&A rate per equivalent unit of production was $2.70, $2.25 and $1.72 in 2001, 2000 and 1999, respectively.

COSTS NOT SUBJECT TO AMORTIZATION

The following table summarizes the categories of costs comprising the amount of unproved properties not subject to amortization (in thousands).

                                                                     DECEMBER 31,
                                                              ---------------------------
                                                               2001      2000      1999
                                                               ----      ----      ----
Acquisition costs...........................................  $27,523   $31,090   $38,252
Exploration costs...........................................       --       425       504
Capitalized interest........................................    5,848     3,222     4,443
                                                              -------   -------   -------
                                                              $33,371   $34,737   $43,199
                                                              =======   =======   =======

Unproved property costs not subject to amortization consist mainly of acquisition and lease costs and seismic data related to unproved areas. We will continue to evaluate these properties over the lease terms; however, the timing of the ultimate evaluation and disposition of a significant portion of the properties has not been determined. Costs associated with seismic data and all other costs will become subject to amortization as the prospects to which they relate are evaluated. Approximately 9%, 11% and 10% of the balance in unproved properties at December 31, 2001, related to additions made in 2001, 2000 and 1999, respectively.

During 2001, 2000 and 1999, we capitalized $3.1 million, $3.8 million and $3.6 million, respectively, of interest related to the costs of unproved properties in the process of development.

SUPPLEMENTAL RESERVE INFORMATION (UNAUDITED)

The following information summarizes our net proved reserves of crude oil (including condensate and natural gas liquids) and natural gas and the present values thereof for the three years ended December 31, 2001. The following reserve information is based upon reports of the independent petroleum consulting firms of Netherland, Sewell & Associates, Inc., and Ryder Scott Company in 2001, and H.J. Gruy and Associates, Inc., Netherland, Sewell & Associates, Inc., and Ryder Scott Company in 2000 and 1999. The estimates are in accordance with regulations prescribed by the SEC.

In management's opinion, the reserve estimates presented herein, in accordance with generally accepted engineering and evaluation principles consistently applied, are believed to be reasonable. However, there are numerous uncertainties inherent in estimating quantities and values of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond our control. Reserve engineering is a subjective process of estimating the recovery from underground accumulations of crude oil and natural gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Because all reserve estimates are to some degree speculative, the quantities of crude oil and natural gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future crude oil and natural gas sales prices may all differ from those assumed in these estimates. In addition, different reserve engineers may make different estimates of reserve quantities and cash flows based upon the same available data. Therefore, the Standardized Measure shown below represents estimates only and should

F-35

UPSTREAM SUBSIDIARIES OF PLAINS RESOURCES INC.

NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)

not be construed as the current market value of the estimated crude oil and natural gas reserves attributable to our properties. In this regard, the information set forth in the following tables includes revisions of reserve estimates attributable to proved properties included in the preceding year's estimates. Such revisions reflect additional information from subsequent exploitation and development activities, production history of the properties involved and any adjustments in the projected economic life of such properties resulting from changes in product prices.

Decreases in the prices of crude oil and natural gas have had, and could have in the future, an adverse effect on the carrying value of our proved reserves and our revenues, profitability and cash flow. Almost all of our reserve base (approximately 93% of year-end 2001 reserve volumes) is comprised of crude oil properties that are sensitive to crude oil price volatility.

ESTIMATED QUANTITIES OF CRUDE OIL AND NATURAL GAS RESERVES (UNAUDITED)

The following table sets forth certain data pertaining to our proved and proved developed reserves for the three years ended December 31, 2001 (in thousands).

                                        AS OF OR FOR THE YEAR ENDED DECEMBER 31,
                                 ------------------------------------------------------
                                       2001               2000               1999
                                 ----------------   ----------------   ----------------
                                   OIL      GAS       OIL      GAS       OIL      GAS
                                 (MBBL)    (MMCF)   (MBBL)    (MMCF)   (MBBL)    (MMCF)
                                 ------    ------   ------    ------   ------    ------
PROVED RESERVES
  Beginning balance............  204,387   93,486   195,213   90,873   110,950   86,781
  Revision of previous
     estimates.................  (13,093)  (5,485)   (5,601)  (3,597)   47,510   (8,234)
  Extensions, discoveries,
     improved recovery and
     other additions...........   40,218   11,571    22,429   9,252     37,393   15,488
  Purchase of reserves
     in-place..................       --      --         --      --      6,442       --
  Production...................   (8,219)  (3,355)   (7,654)  (3,042)   (7,082)  (3,162)
                                 -------   ------   -------   ------   -------   ------
  Ending balance...............  223,293   96,217   204,387   93,486   195,213   90,873
                                 =======   ======   =======   ======   =======   ======
PROVED DEVELOPED RESERVES
  Beginning balance............  105,679   52,184   100,758   49,255    68,167   58,445
                                 =======   ======   =======   ======   =======   ======
  Ending balance...............  119,248   59,101   105,679   52,184   100,758   49,255
                                 =======   ======   =======   ======   =======   ======

STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS (UNAUDITED)

The Standardized Measure of discounted future net cash flows relating to proved crude oil and natural gas reserves is presented below (in thousands):

                                                                 DECEMBER 31,
                                                    ---------------------------------------
                                                       2001          2000          1999
                                                       ----          ----          ----
Future cash inflows...............................  $ 3,662,137   $ 5,850,215   $ 4,389,337
Future development costs..........................     (305,261)     (249,319)     (193,409)
Future production expense.........................   (1,714,132)   (2,748,492)   (1,558,492)
Future income tax expense.........................     (537,252)   (1,030,400)     (881,167)
                                                    -----------   -----------   -----------
Future net cash flows.............................    1,105,492     1,822,004     1,756,269
Discounted at 10% per year........................     (721,025)   (1,032,566)   (1,028,983)
                                                    -----------   -----------   -----------
Standardized measure of discounted future net cash
  flows...........................................  $   384,467   $   789,438   $   727,286
                                                    ===========   ===========   ===========

F-36

UPSTREAM SUBSIDIARIES OF PLAINS RESOURCES INC.

NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)

The Standardized Measure of discounted future net cash flows (discounted at 10%) from production of proved reserves was developed as follows:

1. An estimate was made of the quantity of proved reserves and the future periods in which they are expected to be produced based on year-end economic conditions.

2. In accordance with SEC guidelines, the engineers' estimates of future net revenues from our proved properties and the present value thereof are made using crude oil and natural gas sales prices in effect as of the dates of such estimates and are held constant throughout the life of the properties, except where such guidelines permit alternate treatment, including the use of fixed and determinable contractual price escalations. We have entered into various arrangements to fix or limit the NYMEX crude oil price for a significant portion of our crude oil production. Arrangements in effect at December 31, 2001 are discussed in Note 2. Such arrangements are not reflected in the reserve reports. The overall average year-end prices used in the reserve reports as of December 31, 2001, were $15.31 per barrel of crude oil and $2.56 per Mcf of natural gas. Such prices as of December 31, 2000 were $21.93 per barrel of crude oil and $14.63 per Mcf of natural gas.

3. The future gross revenue streams were reduced by estimated future operating costs (including production and ad valorem taxes) and future development and abandonment costs, all of which were based on current costs.

4. The reports reflect the pre-tax Present Value of Proved Reserves to be $0.6 billion, $1.3 billion and $1.1 billion at December 31, 2001, 2000 and 1999, respectively. SFAS No. 69 requires us to further reduce these estimates by an amount equal to the present value of estimated income taxes which might be payable by us in future years to arrive at the Standardized Measure. Future income taxes were calculated by applying the statutory federal and state income tax rate to pre-tax future net cash flows, net of the tax basis of the properties involved and utilization of available tax carryforwards related to oil and gas operations.

The principal sources of changes in the Standardized Measure of the future net cash flows for the three years ended December 31, 2001, are as follows (in thousands):

                                                              YEAR ENDED DECEMBER 31,
                                                         ---------------------------------
                                                           2001        2000        1999
                                                           ----        ----        ----
Balance, beginning of year.............................  $ 789,438   $ 727,286   $ 183,630
Sales, net of production expenses......................   (139,827)    (86,237)    (56,958)
Net change in sales and transfer prices, net of
  production expenses..................................   (664,684)     94,159     623,369
Changes in estimated future development costs..........    (17,535)    (16,097)    (46,542)
Extensions, discoveries and improved recovery, net of
  costs................................................     89,010     141,641     112,573
Previously estimated development costs incurred during
  the year.............................................     86,881      27,855      19,676
Purchase of reserves in-place..........................         --          --      53,724
Revision of quantity estimates.........................   (156,402)    (68,163)    159,499
Accretion of discount..................................    141,598     101,667      18,683
Net change in income taxes.............................    255,988    (132,673)   (340,368)
                                                         ---------   ---------   ---------
Balance, end of year...................................  $ 384,467   $ 789,438   $ 727,286
                                                         =========   =========   =========

F-37

UPSTREAM SUBSIDIARIES OF PLAINS RESOURCES INC.

NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)

RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES

The results of operations from oil and gas producing activities below exclude non-oil and gas revenues, general and administrative expenses, interest charges, interest income and interest capitalized. Income tax (expense) or benefit was determined by applying the statutory rates to pretax operating results (in thousands).

                                                               YEAR ENDED DECEMBER 31,
                                                            ------------------------------
                                                              2001       2000       1999
                                                              ----       ----       ----
Revenues from oil and gas producing activities............  $204,139   $142,451   $107,485
Production costs..........................................   (63,795)   (56,228)   (50,527)
Depreciation, depletion and amortization..................   (23,707)   (18,395)   (13,101)
Income tax expense........................................   (45,022)   (24,981)   (16,337)
                                                            ========   ========   ========
Results of operations from producing activities (excluding
  corporate overhead and interest costs)..................  $ 71,615   $ 42,847   $ 27,520
                                                            ========   ========   ========

F-38

UPSTREAM SUBSIDIARIES OF PLAINS RESOURCES INC.

NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)

NOTE 9 -- CONSOLIDATING FINANCIAL STATEMENTS

In conjunction with the anticipated issuance of debt securities, all subsidiaries of Plains referred to in Note 1 will become 100% owned subsidiaries of Stocker Resources, L.P. Stocker Resources, L.P. will be co-issuing the debt securities along with a 100% owned finance company. The debt securities will be guaranteed on a full and unconditional and joint and several basis by Arguello Inc. and Plains Illinois Inc. (referred to as "Guarantor Subsidiaries").

The following financial information presents consolidating financial statements, which include:

- the parent company only ("Parent")

- the guarantor subsidiaries on a combined basis ("Guarantor Subsidiaries")

- elimination entries necessary to consolidate the Parent and the Guarantor Subsidiaries; and

- the Companies on a consolidated basis.

Financial information for the non-guarantor subsidiaries, all of which are minor, are immaterial and not separately presented in the table below.

F-39

UPSTREAM SUBSIDIARIES OF PLAINS RESOURCES INC.

NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)

UPSTREAM SUBSIDIARIES OF PLAINS RESOURCES INC.

CONSOLIDATING COMBINED BALANCE SHEET
DECEMBER 31, 2001

                                                    GUARANTOR     INTERCOMPANY
                                         PARENT    SUBSIDIARIES   ELIMINATIONS   COMBINED
                                         ------    ------------   ------------   --------
                                                          (IN THOUSANDS)
                                          ASSETS
CURRENT ASSETS
  Cash and cash equivalents...........  $     11     $      2       $    --      $      13
  Accounts receivable and other
     current assets...................    10,703        5,679            --         16,382
  Commodity hedging contracts.........    13,872        7,915            --         21,787
  Inventories.........................     3,252        1,377            --          4,629
                                        --------     --------       -------      ---------
                                          27,838       14,973            --         42,811
                                        --------     --------       -------      ---------
PROPERTY AND EQUIPMENT, AT COST
  Oil and natural gas
     properties -- full cost method
     Subject to amortization..........   450,038      110,996            --        561,034
     Not subject to amortization......    19,676       13,695            --         33,371
  Other property and equipment........     1,322          194            --          1,516
                                        --------     --------       -------      ---------
                                         471,036      124,885            --        595,921
  Less allowance for depreciation,
     depletion and amortization.......   (56,137)     (84,667)           --       (140,804)
                                        --------     --------       -------      ---------
                                         414,899       40,218            --        455,117
                                        --------     --------       -------      ---------
INVESTMENT IN AND ADVANCES TO
  SUBSIDIARIES........................   (21,496)          --        21,496             --
                                        --------     --------       -------      ---------
OTHER ASSETS..........................    16,275        2,552            --         18,827
                                        --------     --------       -------      ---------
                                        $437,516     $ 57,743       $21,496      $ 516,755
                                        ========     ========       =======      =========
                         LIABILITIES AND COMBINED OWNERS' EQUITY
CURRENT LIABILITIES
  Accounts payable and other current
     liabilities......................  $ 29,822     $ 11,546       $    --      $  41,368
  Current maturities on long-term
     debt.............................       511           --            --            511
                                        --------     --------       -------      ---------
                                          30,333       11,546            --         41,879
                                        --------     --------       -------      ---------
PAYABLE TO PLAINS RESOURCES INC.......   172,603       62,558            --        235,161
                                        --------     --------       -------      ---------
LONG-TERM DEBT........................     1,022           --            --          1,022
                                        --------     --------       -------      ---------
OTHER LONG-TERM LIABILITIES...........        --        1,413            --          1,413
                                        --------     --------       -------      ---------
DEFERRED INCOME TAXES.................    53,471        3,722            --         57,193
                                        --------     --------       -------      ---------
COMBINED OWNERS' EQUITY
  Owners' equity......................   164,203      (25,889)       25,889        164,203
  Accumulated other comprehensive
     income...........................    15,884        4,393        (4,393)        15,884
                                        --------     --------       -------      ---------
                                         180,087      (21,496)       21,496        180,087
                                        --------     --------       -------      ---------
                                        $437,516     $ 57,743       $21,496      $ 516,755
                                        ========     ========       =======      =========

F-40

UPSTREAM SUBSIDIARIES OF PLAINS RESOURCES INC.

NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)

UPSTREAM SUBSIDIARIES OF PLAINS RESOURCES INC.

CONSOLIDATING COMBINED BALANCE SHEET
DECEMBER 31, 2000

                                                    GUARANTOR     INTERCOMPANY
                                         PARENT    SUBSIDIARIES   ELIMINATIONS   COMBINED
                                         ------    ------------   ------------   --------
                                                          (IN THOUSANDS)
                                          ASSETS
CURRENT ASSETS
  Cash and cash equivalents...........  $    240     $    296       $    --      $     536
  Accounts receivable and other
     current assets...................    24,144        8,734            --         32,878
  Inventories.........................     2,666        1,372            --          4,038
                                        --------     --------       -------      ---------
                                          27,050       10,402            --         37,452
                                        --------     --------       -------      ---------
PROPERTY AND EQUIPMENT, AT COST
  Oil and natural gas
     properties -- full cost method
     Subject to amortization..........   338,859       95,056            --        433,915
     Not subject to amortization......    22,278       12,459            --         34,737
  Other property and equipment........     1,189          200            --          1,389
                                        --------     --------       -------      ---------
                                         362,326      107,715            --        470,041
  Less allowance for depreciation,
     depletion and amortization.......   (37,721)     (78,976)           --       (116,697)
                                        --------     --------       -------      ---------
                                         324,605       28,739            --        353,344
                                        --------     --------       -------      ---------
INVESTMENT IN AND ADVANCES TO
  SUBSIDIARIES........................   (37,417)          --        37,417             --
                                        --------     --------       -------      ---------
OTHER ASSETS..........................     9,608          631            --         10,239
                                        --------     --------       -------      ---------
                                        $323,846     $ 39,772       $37,417      $ 401,035
                                        ========     ========       =======      =========
                         LIABILITIES AND COMBINED OWNERS' EQUITY
CURRENT LIABILITIES
  Accounts payable and other current
     liabilities......................  $ 29,665     $ 14,137       $    --      $  43,802
  Current maturities on long-term
     debt.............................       511           --            --            511
                                        --------     --------       -------      ---------
                                          30,176       14,137            --         44,313
PAYABLE TO PLAINS RESOURCES INC.......   161,789       63,207            --        224,996
LONG-TERM DEBT........................     1,533           --            --          1,533
OTHER LONG-TERM LIABILITIES...........        --           --            --             --
DEFERRED INCOME TAXES.................    19,316         (155)           --         19,161
COMBINED OWNERS' EQUITY...............   111,032      (37,417)       37,417        111,032
                                        --------     --------       -------      ---------
                                        $323,846     $ 39,772       $37,417      $ 401,035
                                        ========     ========       =======      =========

F-41

UPSTREAM SUBSIDIARIES OF PLAINS RESOURCES INC.

NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)

UPSTREAM SUBSIDIARIES OF PLAINS RESOURCES INC.

CONSOLIDATING COMBINED STATEMENT OF INCOME
YEAR ENDED DECEMBER 31, 2001

                                                    GUARANTOR     INTERCOMPANY
                                         PARENT    SUBSIDIARIES   ELIMINATIONS   COMBINED
                                         ------    ------------   ------------   --------
                                                         (IN THOUSANDS)
REVENUES
  Crude oil and liquids...............  $124,250     $50,645        $     --     $174,895
  Natural gas.........................    28,771          --              --       28,771
  Other operating revenues............        --         473              --          473
                                        --------     -------        --------     --------
                                         153,021      51,118              --      204,139
                                        --------     -------        --------     --------
COSTS AND EXPENSES
  Production expenses.................    41,458      22,337              --       63,795
  General and administrative..........     8,708       1,502              --       10,210
  Depreciation, depletion and
     amortization.....................    18,413       5,692              --       24,105
                                        --------     -------        --------     --------
                                          68,579      29,531              --       98,110
                                        --------     -------        --------     --------
INCOME FROM OPERATIONS................    84,442      21,587              --      106,029
OTHER INCOME (EXPENSE)
  Equity in earnings of
     subsidiaries.....................    11,528          --         (11,528)          --
  Interest expense....................   (10,679)     (6,732)             --      (17,411)
  Interest and other income...........        94         369              --          463
                                        --------     -------        --------     --------
INCOME BEFORE INCOME TAXES AND
  CUMULATIVE EFFECT OF ACCOUNTING
  CHANGE..............................    85,385      15,224         (11,528)      89,081
  Income tax expense
     Current..........................    (2,832)     (3,182)             --       (6,014)
     Deferred.........................   (27,620)       (754)             --      (28,374)
                                        --------     -------        --------     --------
INCOME BEFORE CUMULATIVE EFFECT OF
  ACCOUNTING CHANGE...................    54,933      11,288         (11,528)      54,693
  Cumulative effect of accounting
     change, net of tax benefit.......    (1,762)        240              --       (1,522)
                                        --------     -------        --------     --------
NET INCOME............................  $ 53,171     $11,528        $(11,528)    $ 53,171
                                        ========     =======        ========     ========

F-42

UPSTREAM SUBSIDIARIES OF PLAINS RESOURCES INC.

NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)

UPSTREAM SUBSIDIARIES OF PLAINS RESOURCES INC.

CONSOLIDATING COMBINED STATEMENT OF INCOME
YEAR ENDED DECEMBER 31, 2000

                                                    GUARANTOR     INTERCOMPANY
                                         PARENT    SUBSIDIARIES   ELIMINATIONS   COMBINED
                                         ------    ------------   ------------   --------
                                                         (IN THOUSANDS)
REVENUES
  Crude oil and liquids...............  $ 85,921     $40,513        $    --      $126,434
  Natural gas.........................    16,017          --             --        16,017
                                        --------     -------        -------      --------
                                         101,938      40,513             --       142,451
                                        --------     -------        -------      --------
COSTS AND EXPENSES
  Production expenses.................    35,278      20,950             --        56,228
  General and administrative..........     5,168       1,140             --         6,308
  Depreciation, depletion and
     amortization.....................    15,450       3,409             --        18,859
                                        --------     -------        -------      --------
                                          55,896      25,499             --        81,395
                                        --------     -------        -------      --------
INCOME FROM OPERATIONS................    46,042      15,014             --        61,056
OTHER INCOME (EXPENSE)
  Equity in earnings of
     subsidiaries.....................     6,859          --         (6,859)           --
  Interest expense....................   (10,212)     (5,673)            --       (15,885)
  Interest and other income...........       213         130             --           343
                                        --------     -------        -------      --------
INCOME BEFORE INCOME TAXES............    42,902       9,471         (6,859)       45,514
  Income tax expense
     Current..........................      (168)     (2,263)            --        (2,431)
     Deferred.........................   (13,985)       (349)            --       (14,334)
                                        --------     -------        -------      --------
NET INCOME............................  $ 28,749     $ 6,859        $(6,859)     $ 28,749
                                        ========     =======        =======      ========

F-43

UPSTREAM SUBSIDIARIES OF PLAINS RESOURCES INC.

NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)

UPSTREAM SUBSIDIARIES OF PLAINS RESOURCES INC.

CONSOLIDATING COMBINED STATEMENT OF INCOME
YEAR ENDED DECEMBER 31, 1999

                                                    GUARANTOR     INTERCOMPANY
                                         PARENT    SUBSIDIARIES   ELIMINATIONS   COMBINED
                                         ------    ------------   ------------   --------
                                                          (IN THOUSANDS)
REVENUES
  Crude oil and liquids................  $73,073     $29,317        $    --      $102,390
  Natural gas..........................    5,095          --             --         5,095
                                         -------     -------        -------      --------
                                          78,168      29,317             --       107,485
                                         -------     -------        -------      --------
COSTS AND EXPENSES
  Production expenses..................   35,526      15,001             --        50,527
  General and administrative...........    3,469         898             --         4,367
  Depreciation, depletion and
     amortization......................   11,154       2,175             --        13,329
                                         -------     -------        -------      --------
                                          50,149      18,074             --        68,223
                                         -------     -------        -------      --------
INCOME FROM OPERATIONS.................   28,019      11,243             --        39,262
OTHER INCOME (EXPENSE)
  Equity in earnings of subsidiaries...    4,782          --         (4,782)           --
  Interest expense.....................   (9,447)     (5,465)            --       (14,912)
  Interest and other income............       44          43             --            87
                                         -------     -------        -------      --------
INCOME BEFORE INCOME TAXES.............   23,398       5,821         (4,782)       24,437
  Income tax (expense) benefit
     Current...........................    1,038      (1,543)            --          (505)
     Deferred..........................   (5,331)        504             --        (4,827)
                                         -------     -------        -------      --------
NET INCOME.............................  $19,105     $ 4,782        $(4,782)     $ 19,105
                                         =======     =======        =======      ========

F-44

UPSTREAM SUBSIDIARIES OF PLAINS RESOURCES INC.

NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)

UPSTREAM SUBSIDIARIES OF PLAINS RESOURCES INC.

CONSOLIDATING COMBINED STATEMENT OF CASH FLOWS
YEAR ENDED DECEMBER 31, 2001

                                                    GUARANTOR     INTERCOMPANY
                                        PARENT     SUBSIDIARIES   ELIMINATIONS   COMBINED
                                        ------     ------------   ------------   --------
                                                         (IN THOUSANDS)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income...........................  $  53,171     $ 11,528       $(11,528)    $  53,171
Items not affecting cash flows from
  operating activities:
  Depreciation, depletion and
     amortization....................     18,413        5,692             --        24,105
  Equity in earnings of
     subsidiaries....................    (11,528)                     11,528
  Deferred income taxes..............     27,620          754             --        28,374
  Cumulative effect of adoption of
     accounting change...............      1,762         (240)            --         1,522
  Change in derivative fair value....         (7)       1,062             --         1,055
  Other noncash items................      2,473          733             --         3,206
Change in assets and liabilities from
  operating activities:
  Accounts receivable and other
     assets..........................      9,449         (252)            --         9,197
  Inventories........................       (586)          (5)            --          (591)
  Accounts payable and other
     liabilities.....................        157       (1,178)            --        (1,021)
                                       ---------     --------       --------     ---------
Net cash provided by operating
  activities.........................    100,924       18,094             --       119,018
                                       ---------     --------       --------     ---------
CASH FLOWS FROM INVESTING ACTIVITIES
Acquisition, exploration and
  developments costs.................   (108,577)     (17,176)            --      (125,753)
Additions to other property and
  equipment..........................       (127)          --             --          (127)
                                       ---------     --------       --------     ---------
Net cash used in investing
  activities.........................   (108,704)     (17,176)            --      (125,880)
                                       ---------     --------       --------     ---------
CASH FLOWS FROM FINANCING ACTIVITIES
Principal payments of long-term
  debt...............................       (511)          --             --          (511)
Receipts from (payments to) Plains
  Resources Inc. ....................      8,062       (1,212)            --         6,850
                                       ---------     --------       --------     ---------
Net cash provided by (used in)
  financing activities...............      7,551       (1,212)            --         6,339
                                       ---------     --------       --------     ---------
Net increase (decrease) in cash and
  cash equivalents...................       (229)        (294)            --          (523)
Cash and cash equivalents, beginning
  of year............................        240          296             --           536
                                       ---------     --------       --------     ---------
Cash and cash equivalents, end of
  year...............................  $      11     $      2       $     --     $      13
                                       =========     ========       ========     =========

F-45

UPSTREAM SUBSIDIARIES OF PLAINS RESOURCES INC.

NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)

UPSTREAM SUBSIDIARIES OF PLAINS RESOURCES INC.

CONSOLIDATING COMBINED STATEMENT OF CASH FLOWS
YEAR ENDED DECEMBER 31, 2000

                                                    GUARANTOR     INTERCOMPANY
                                         PARENT    SUBSIDIARIES   ELIMINATIONS   COMBINED
                                         ------    ------------   ------------   --------
                                                         (IN THOUSANDS)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income............................  $ 28,749     $  6,859       $(6,859)     $ 28,749
Items not affecting cash flows from
  operating activities:
  Depreciation, depletion and
     amortization.....................    15,450        3,409            --        18,859
  Equity in earnings of
     subsidiaries.....................    (6,859)                     6,859            --
  Deferred income taxes...............    13,985          349            --        14,334
  Other noncash items.................        --                                       --
Change in assets and liabilities from
  operating activities:
  Accounts receivable and other
     assets...........................     7,192          405            --         7,597
  Inventories.........................       228         (423)           --          (195)
  Accounts payable and other
     liabilities......................     9,745          375            --        10,120
                                        --------     --------       -------      --------
Net cash provided by operating
  activities..........................    68,490       10,974            --        79,464
                                        --------     --------       -------      --------
CASH FLOWS FROM INVESTING ACTIVITIES
Acquisition, exploration and
  developments costs..................   (54,782)     (15,723)           --       (70,505)
Additions to other property and
  equipment...........................      (359)          (7)           --          (366)
                                        --------     --------       -------      --------
Net cash used in investing
  activities..........................   (55,141)     (15,730)           --       (70,871)
                                        --------     --------       -------      --------
CASH FLOWS FROM FINANCING ACTIVITIES
Principal payments of long-term
  debt................................      (511)          --            --          (511)
Receipts from (payments to) Plains
  Resources Inc. .....................   (12,803)         182            --       (12,621)
                                        --------     --------       -------      --------
Net cash provided by (used in)
  financing activities................   (13,314)         182            --       (13,132)
                                        --------     --------       -------      --------
Net increase (decrease) in cash and
  cash equivalents....................        35       (4,574)           --        (4,539)
Cash and cash equivalents, beginning
  of year.............................       205        4,870            --         5,075
                                        --------     --------       -------      --------
Cash and cash equivalents, end of
  year................................  $    240     $    296       $    --      $    536
                                        ========     ========       =======      ========

F-46

UPSTREAM SUBSIDIARIES OF PLAINS RESOURCES INC.

NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)

UPSTREAM SUBSIDIARIES OF PLAINS RESOURCES INC.

CONSOLIDATING COMBINED STATEMENT OF CASH FLOWS
YEAR ENDED DECEMBER 31, 1999

                                                    GUARANTOR     INTERCOMPANY
                                         PARENT    SUBSIDIARIES   ELIMINATIONS   COMBINED
                                         ------    ------------   ------------   --------
                                                         (IN THOUSANDS)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income............................  $ 19,105     $ 4,782        $(4,782)     $ 19,105
Items not affecting cash flows from
  operating activities:
  Depreciation, depletion and
     amortization.....................    11,154       2,175             --        13,329
  Equity in earnings of
     subsidiaries.....................    (4,782)                     4,782            --
  Deferred income taxes...............     5,331        (504)            --         4,827
  Other noncash items.................
Change in assets and liabilities from
  operating activities:
  Accounts receivable and other
     assets...........................   (24,329)     (7,287)            --       (31,616)
  Inventories.........................        38        (624)            --          (586)
  Accounts payable and other
     liabilities......................   (13,669)     13,219             --          (450)
                                        --------     -------        -------      --------
Net cash provided by operating
  activities..........................    (7,152)     11,761             --         4,609
                                        --------     -------        -------      --------
CASH FLOWS FROM INVESTING ACTIVITIES
Acquisition, exploration and
  developments costs..................   (51,348)     (7,819)            --       (59,167)
Additions to other property and
  equipment...........................      (154)        (41)            --          (195)
                                        --------     -------        -------      --------
Net cash used in investing
  activities..........................   (51,502)     (7,860)            --       (59,362)
                                        --------     -------        -------      --------
CASH FLOWS FROM FINANCING ACTIVITIES
Principal payments of long-term
  debt................................      (511)         --             --          (511)
Receipts from (payments to) Plains
  Resources Inc. .....................    59,232         969             --        60,201
                                        --------     -------        -------      --------
Net cash provided by (used in)
  financing activities................    58,721         969             --        59,690
                                        --------     -------        -------      --------
Net increase (decrease) in cash and
  cash equivalents....................        67       4,870             --         4,937
Cash and cash equivalents, beginning
  of year.............................       138          --             --           138
                                        --------     -------        -------      --------
Cash and cash equivalents, end of
  year................................  $    205     $ 4,870        $    --      $  5,075
                                        ========     =======        =======      ========

F-47



NO DEALER, SALESPERSON OR OTHER PERSON IS AUTHORIZED TO GIVE ANY INFORMATION OR TO REPRESENT ANYTHING NOT CONTAINED IN THIS PROSPECTUS. YOU MUST NOT RELY ON ANY UNAUTHORIZED INFORMATION OR REPRESENTATIONS. THIS PROSPECTUS IS AN OFFER TO SELL ONLY THE SHARES OFFERED HEREBY, BUT ONLY UNDER CIRCUMSTANCES AND IN JURISDICTIONS WHERE IT IS LAWFUL TO DO SO. THE INFORMATION CONTAINED IN THIS PROSPECTUS IS CURRENT ONLY AS OF ITS DATE.


TABLE OF CONTENTS

                                       Page
                                       ----
Prospectus Summary...................    1
Summary Financial Information........    6
Summary Reserve and Production
  Data...............................    8
Risk Factors.........................    9
Forward-Looking Statements...........   19
Use of Proceeds......................   20
Dividend Policy......................   20
Capitalization.......................   21
Dilution.............................   22
Selected Historical Combined
  Financial and Other Data...........   23
Management's Discussion and Analysis
  of Financial Condition and Results
  of Operations......................   25
Business.............................   35
Management...........................   47
Principal Stockholder................   51
Certain Transactions.................   52
Description of Capital Stock.........   60
Shares Eligible for Future Sale......   62
Underwriting.........................   64
Legal Matters........................   66
Experts..............................   66
Where You Can Find More
  Information........................   66
Index to Financial Statements........  F-1

THROUGH AND INCLUDING , 2002 (THE 25TH DAY AFTER THE DATE OF THIS PROSPECTUS), ALL DEALERS EFFECTING TRANSACTIONS IN THESE SECURITIES, WHETHER OR NOT PARTICIPATING IN THIS OFFERING, MAY BE REQUIRED TO DELIVER A PROSPECTUS. THIS IS IN ADDITION TO A DEALER'S OBLIGATION TO DELIVER A PROSPECTUS WHEN ACTING AS AN UNDERWRITER AND WITH RESPECT TO AN UNSOLD ALLOTMENT OR SUBSCRIPTION.





Shares
PLAINS EXPLORATION &
PRODUCTION COMPANY
Common Stock
GOLDMAN, SACHS & CO.


PART II

INFORMATION NOT REQUIRED IN PROSPECTUS

ITEM 13. OTHER EXPENSES OF ISSUANCE AND DISTRIBUTION

The following table sets forth the costs and expenses, other than underwriting discounts and commissions, payable by the Registrant in connection with the sale of common stock being registered. All amounts are estimates except the SEC registration fee, the NASD filing fee and the New York Stock Exchange listing fee.

                                                                 AMOUNT
                                                                 TO BE
                                                                  PAID
                                                               ----------
SEC registration fee........................................    $ 9,200
NASD filing fee.............................................          *
New York Stock Exchange listing fee.........................          *
Printing and engraving expenses.............................          *
Legal fees and expenses.....................................          *
Accounting fees and expenses................................          *
Blue Sky qualification fees and expenses....................          *
Transfer agent and registrar fees...........................          *
Miscellaneous fees..........................................          *
                                                                -------
     Total..................................................    $     *
                                                                =======


* To be supplied by amendment.

ITEM 14. INDEMNIFICATION OF DIRECTORS AND OFFICERS

Our Certificate of Incorporation provides that we must indemnify to the full extent authorized or permitted by law any person made, or threatened to be made, a party to any action, suit or proceeding (whether civil, criminal or otherwise) by reason of fact that he, his testator or intestate, is or was one of our directors or officers or by reason of the fact that such director or officer, at our request, is or was serving any other corporation, partnership, joint venture, trust, employee benefit plan or other enterprise, in any capacity. The rights to indemnification set forth above are not exclusive of any other rights to which such person may be entitled under any statute, provision of our Certificate of Incorporation or bylaws, agreements, vote of stockholders or disinterested directors or otherwise.

Additionally, our Bylaws provide for mandatory indemnification to at least the extent specifically allowed by Section 145 of the Delaware General Corporation Law (the "GCL"). Our Bylaws generally follow the language of Section 145 of the GCL, but in addition specify that any director, officer, employee or agent may apply to any court of competent jurisdiction in the State of Delaware for indemnification to the extent otherwise permissible under the Bylaws, notwithstanding any contrary determination denying indemnification made by the Board, by independent legal counsel, or by the stockholders, and notwithstanding the absence of any determination with respect to indemnification. The Bylaws also specify certain circumstances in which a finding is required that the person seeking indemnification acted in good faith, for purposes of determining whether indemnification is available. Under the Bylaws, a person shall be deemed to have acted in good faith and in a manner he reasonably believed to be in or not opposed to our best interests, or, with respect to any criminal action or proceeding, to have had no reasonable cause to believe his conduct was unlawful, if his action is based on our records or books of account or those of another enterprise, or on information supplied to him by our

II-1


officers or the officers of another enterprise in the course of their duties, or on the advice of our legal counsel or the legal counsel of another enterprise or on information or records given or reports made to us or to another enterprise by an independent certified public accountant or by an appraiser or other expert selected with reasonable care by us or another enterprise.

Pursuant to Section 145 of the GCL, we generally have the power to indemnify our current and former directors, officers, employees and agents against expenses and liabilities that they incur in connection with any suit to which they are, or are threatened to be made, a party by reason of their serving in such positions so long as they acted in good faith and in a manner they reasonably believed to be in, or not opposed to, our best interests, and with respect to any criminal action, they had no reasonable cause to believe their conduct was unlawful. With respect to suits by or in our right, however, indemnification is generally limited to attorneys' fees and other expenses and is not available if such person is adjudged to be liable to us unless the court determines that indemnification is appropriate. The statute expressly provides that the power to indemnify authorized thereby is not exclusive of any rights granted under any bylaw, agreement, vote of stockholders or disinterested directors, or otherwise. We also have the power to purchase and maintain insurance for such persons.

The above discussion of our Certificate of Incorporation and Bylaws and
Section 145 of the GCL is not intended to be exhaustive and is qualified in its entirety by each of those documents and that statute.

Reference is also made to the Underwriting Agreement contained in Exhibit 1.1 hereto, which provides for the indemnification of our officers and directors against certain liabilities.

ITEM 15. RECENT SALES OF UNREGISTERED SECURITIES

Plains Exploration & Production Company has not sold any securities, registered or otherwise, within the past three years.

ITEM 16. EXHIBITS

(a) Exhibits

EXHIBIT
NUMBER                            DESCRIPTION
-------                           -----------
  1.1*    Form of Underwriting Agreement.
  3.1*    Form of Certificate of Incorporation.
  3.4*    Form of Bylaws.
  4.1*    Form of Common Stock Certificate.
  5.1*    Opinion of Akin, Gump, Strauss, Hauer & Feld, L.L.P.
 10.1*    Master Separation Agreement between Plains Exploration &
          Production Company, L.P. and Plains Resources Inc.
 10.2*    Transition Services Agreement between Plains Exploration &
          Production Company, L.P. and Plains Resources Inc.
 10.3*    Tax Allocation Agreement between Plains Exploration &
          Production Company, L.P. and Plains Resources Inc.
 10.4*    Technical Services Agreement between Plains Exploration &
          Production Company, L.P. and Plains Resources Inc.
 10.5*    Intellectual Property Agreement between Plains Exploration &
          Production Company, L.P. and Plains Resources Inc.
 10.6*    Employee Matters Agreement between Plains Exploration &
          Production Company, L.P. and Plains Resources Inc.

II-2


EXHIBIT
NUMBER                            DESCRIPTION
-------                           -----------
 10.7     Purchase and Sale Agreement dated June 4, 1999, by and among
          Plains Resources Inc., Chevron U.S.A., Inc., and Chevron
          Pipe Line Company.
 10.8     Crude Oil Marketing Agreement among Plains Resources Inc.,
          Plains Illinois Inc., Stocker Resources, L.P., Calumet
          Florida, Inc. and Plains Marketing, L.P. dated as of
          November 23, 1998.
 10.9     Letter Agreement dated as of October 23, 2001 by and between
          Plains Marketing, L.P. and Stocker Resources, L.P.
 21.1*    Subsidiaries of Plains Exploration & Production Company.
 23.1     Consent of PricewaterhouseCoopers LLP.
 23.2*    Consent of Akin, Gump, Strauss, Hauer & Feld, L.L.P.
          (included in Exhibit 5.1).
 23.3     Consent of Netherland, Sewell & Associates, Inc.
 23.4     Consent of Ryder Scott Company.
 23.5     Consent of H.J. Gruy and Associates, Inc.
 24.1     Powers of Attorney (included on the signature page).


* To be filed by amendment.

(b) Financial Statements and Schedules

ITEM 17. UNDERTAKINGS

The undersigned Registrant hereby undertakes to provide to the underwriters at the closing specified in the underwriting agreement, certificates in such denominations and registered in such names as required by the underwriters to permit prompt delivery to each purchaser.

Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors, officers and controlling persons of the Registrant pursuant to the foregoing provisions, or otherwise, the Registrant has had been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the Registrant of expenses incurred or paid by a director, officer or controlling person of the Registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the Registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act of 1933 and will be governed by the final adjudication of such issue.

The undersigned Registrant hereby undertakes that:

(1) For purposes of determining any liability under the Securities Act of 1933, the information omitted from the form of prospectus filed as part of this Registration Statement in reliance upon Rule 430A and contained in a form of prospectus filed by the Registrant pursuant to Rule 424(b)(1) or
(4) or 497(h) under the Securities Act of 1933 shall be deemed to be part of this Registration Statement as of the time it was declared effective.

(2) For the purpose of determining any liability under the Securities Act of 1933, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

II-3


SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, the Registrant has duly caused this Registration Statement on Form S-1 to be signed on its behalf by the undersigned, thereunto duly authorized, in Houston, Texas on June 21, 2002.

PLAINS EXPLORATION & PRODUCTION
COMPANY, L.P.

By: Stocker Resources, Inc.,
its general partner

By:     /s/ JOHN T. RAYMOND
  ------------------------------------
            John T. Raymond
               President

POWER OF ATTORNEY

KNOW ALL PERSON BY THESE PRESENTS that each individual whose signature appears below constitute and appoints John T. Raymond, Jere C. Overdyke and Timothy T. Stephens, and each of them, his or her true and lawful attorneys-in-fact and agents with full power of substitution, for him or her and in his or her name, place and stead, in any and all capacities, to sign any and all amendments (including post-effective amendments) to this Registration Statement, and to sign any registration statement for he same offering covered by the Registration Statement that is to be effective upon filing pursuant to Rule 462(b) promulgated under the Securities Act, and all post-effective amendments thereto, and to file the same, with all exhibits thereto and all documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done in and about the premises, as fully to all intents and purposes as he or she might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents or any of them, or his, her or their substitute or substitutes, may lawfully do or cause to be done or by virtue hereof. Pursuant to the requirements of the Securities Act, this Registration Statement has been signed by the following persons in the capacities and on the date indicated.

                      NAME                                       TITLE                      DATE
                      ----                                       -----                      ----

              /s/ JOHN T. RAYMOND                        President and Director         June 21, 2002
------------------------------------------------     (Principal Executive Officer)
                John T. Raymond


           /s/ JERE C. OVERDYKE, JR.                   Vice President & Treasurer       June 21, 2002
------------------------------------------------        (Principal Financial and
             Jere C. Overdyke, Jr.                        Accounting Officer)


            /s/ TIMOTHY T. STEPHENS                    Vice President, Secretary        June 21, 2002
------------------------------------------------              and Director
              Timothy T. Stephens

II-4


EXHIBIT INDEX

EXHIBIT
NUMBER                            DESCRIPTION
-------                           -----------
  1.1*    Form of Underwriting Agreement.
  3.1*    Form of Certificate of Incorporation.
  3.4*    Form of Bylaws.
  4.1*    Form of Common Stock Certificate.
  5.1*    Opinion of Akin, Gump, Strauss, Hauer & Feld, L.L.P.
 10.1*    Master Separation Agreement between Plains Exploration &
          Production Company, L.P. and Plains Resources Inc.
 10.2*    Transition Services Agreement between Plains Exploration &
          Production Company, L.P. and Plains Resources Inc.
 10.3*    Tax Allocation Agreement between Plains Exploration &
          Production Company, L.P. and Plains Resources Inc.
 10.4*    Technical Services Agreement between Plains Exploration &
          Production Company, L.P. and Plains Resources Inc.
 10.5*    Intellectual Property Agreement between Plains Exploration &
          Production Company, L.P. and Plains Resources Inc.
 10.6*    Employee Matters Agreement between Plains Exploration &
          Production Company, L.P. and Plains Resources Inc.
 10.7     Purchase and Sale Agreement dated June 4, 1999, by and among
          Plains Resources Inc., Chevron U.S.A., Inc., and Chevron
          Pipe Line Company.
 10.8     Crude Oil Marketing Agreement among Plains Resources Inc.,
          Plains Illinois Inc., Stocker Resources, L.P., Calumet
          Florida, Inc. and Plains Marketing, L.P. dated as of
          November 23, 1998.
 10.9     Letter Agreement dated as of October 23, 2001 by and between
          Plains Marketing, L.P. and Stocker Resources, L.P.
 21.1*    Subsidiaries of Plains Exploration & Production Company.
 23.1     Consent of PricewaterhouseCoopers LLP.
 23.2*    Consent of Akin, Gump, Strauss, Hauer & Feld, L.L.P.
          (included in Exhibit 5.1).
 23.3     Consent of Netherland, Sewell & Associates, Inc.
 23.4     Consent of Ryder Scott Company.
 23.5     Consent of H.J. Gruy and Associates, Inc.
 24.1     Powers of Attorney (included on the signature page).


* To be filed by amendment.


EXHIBIT 10.7

POINT ARGUELLO PROJECT ASSETS AND RELATED PROPERTIES

PURCHASE AND SALE AGREEMENT

AMONG

CHEVRON U.S.A. INC.,

CHEVRON PIPE LINE COMPANY

AND

PLAINS RESOURCES INC.

JUNE 4, 1999


TABLE OF CONTENTS

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ARTICLE 1  DEFINITIONS . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
     1.1  Defined Terms. . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
     1.2  Rules of Construction. . . . . . . . . . . . . . . . . . . . . . . . 7
ARTICLE 2  PURCHASE AND SALE OF TRANSFERRED PROPERTIES . . . . . . . . . . . . 8
     2.1  CUSA Properties. . . . . . . . . . . . . . . . . . . . . . . . . . . 8
     2.2  CPL Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
     2.3  Hydrocarbon Inventories. . . . . . . . . . . . . . . . . . . . . . .10
     2.4  Partnership Interests and Clean Seas Interests . . . . . . . . . . .11
     2.5  Included and Excluded Items. . . . . . . . . . . . . . . . . . . . .12
     2.6  Conveyancing Instruments . . . . . . . . . . . . . . . . . . . . . .12
ARTICLE 3  ASSUMPTION AND INDEMNIFICATION OF LIABILITIES . . . . . . . . . . .13
     3.1  Liabilities Retained by Sellers. . . . . . . . . . . . . . . . . . .13
     3.2  Liabilities Assumed by Buyer . . . . . . . . . . . . . . . . . . . .15
     3.3  General Liability Provisions . . . . . . . . . . . . . . . . . . . .15
     3.4  Claims Procedures. . . . . . . . . . . . . . . . . . . . . . . . . .16
     3.5  Security for Sellers' Liabilities. . . . . . . . . . . . . . . . . .17
     3.6  Security for Buyer's Liabilities . . . . . . . . . . . . . . . . . .17
ARTICLE 4  DEPOSIT AND PURCHASE PRICE. . . . . . . . . . . . . . . . . . . . .19
     4.1  Deposit. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .19
     4.2  Purchase Price . . . . . . . . . . . . . . . . . . . . . . . . . . .19
     4.3  Purchase Price Adjustments . . . . . . . . . . . . . . . . . . . . .20
     4.4  Settlement Statement . . . . . . . . . . . . . . . . . . . . . . . .20
     4.5  Allocation of Purchase Price . . . . . . . . . . . . . . . . . . . .21
ARTICLE 5  CLOSING . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .21
     5.1  Time and Place of Closing. . . . . . . . . . . . . . . . . . . . . .21
     5.2  Scheduled Closing Date . . . . . . . . . . . . . . . . . . . . . . .21
     5.3  Termination. . . . . . . . . . . . . . . . . . . . . . . . . . . . .21
     5.4  Consequences of Termination. . . . . . . . . . . . . . . . . . . . .21
     5.5  Jointly Used Assets. . . . . . . . . . . . . . . . . . . . . . . . .22
ARTICLE 6  CLOSING CONDITIONS PRECEDENT. . . . . . . . . . . . . . . . . . . .23
     6.1  Sellers' Closing Conditions Precedent. . . . . . . . . . . . . . . .23
     6.2  Buyer's Closing Conditions Precedent . . . . . . . . . . . . . . . .24
ARTICLE 7  REPRESENTATIONS AND WARRANTIES. . . . . . . . . . . . . . . . . . .26
     7.1  CUSA's Representations and Warranties. . . . . . . . . . . . . . . .26
     7.2  CPL's Representations and Warranties . . . . . . . . . . . . . . . .28
     7.3  Buyer's Representations and Warranties . . . . . . . . . . . . . . .30
     7.4  Survival . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .31
     7.5  Exclusivity of Warranties and Specific Disclaimers . . . . . . . . .31
     7.6  Year 2000 Disclaimer, Release and Indemnity. . . . . . . . . . . . .33
ARTICLE 8  PRE-CLOSING COVENANTS . . . . . . . . . . . . . . . . . . . . . . .35
     8.1  Buyer's Due Diligence Review . . . . . . . . . . . . . . . . . . . .35
     8.2  Buyer's Right to Enter . . . . . . . . . . . . . . . . . . . . . . .37
     8.3  Operation of Transferred Properties Prior to Closing . . . . . . . .38
     8.4  Announcements. . . . . . . . . . . . . . . . . . . . . . . . . . . .39
     8.5  Requirements for Transfer of Transferred Properties. . . . . . . . .39
     8.6  Other Government Authority Reviews and Approvals . . . . . . . . . .41

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ARTICLE 9  POST-CLOSING COVENANTS. . . . . . . . . . . . . . . . . . . . . . .42
     9.1  Termination of Rights to Sellers' Insurance. . . . . . . . . . . . .42
     9.2  Buyer's Insurance. . . . . . . . . . . . . . . . . . . . . . . . . .43
     9.3  Removal of Proprietary Technical Information . . . . . . . . . . . .43
     9.4  Replacement of Sellers' Identification . . . . . . . . . . . . . . .44
     9.5  Access by Sellers After Closing. . . . . . . . . . . . . . . . . . .44
     9.6  Abandonment Project Permitting, Planning and Execution Services. . .44
     9.7 Services Agreement. . . . . . . . . . . . . . . . . . . . . . . . . .44
ARTICLE 10  TAXES. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .45
     10.1  Transfer Taxes. . . . . . . . . . . . . . . . . . . . . . . . . . .45
     10.2 Property  and Excise Taxes . . . . . . . . . . . . . . . . . . . . .45
     10.3  Partnerships and Partnership Interests. . . . . . . . . . . . . . .46
     10.4  Refunds . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .46
     10.5  Compliance and Contests . . . . . . . . . . . . . . . . . . . . . .46
ARTICLE 11  [INTENTIONALLY OMITTED]. . . . . . . . . . . . . . . . . . . . . .46
ARTICLE 12  GENERAL TERMS. . . . . . . . . . . . . . . . . . . . . . . . . . .47
     12.1  Costs and Expenses. . . . . . . . . . . . . . . . . . . . . . . . .47
     12.2  Bulk Transfer Law . . . . . . . . . . . . . . . . . . . . . . . . .47
     12.3  Further Assurances. . . . . . . . . . . . . . . . . . . . . . . . .47
     12.4  Notices . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .47
     12.5  Assignment. . . . . . . . . . . . . . . . . . . . . . . . . . . . .48
     12.6  Governing Law and Dispute Resolution. . . . . . . . . . . . . . . .48
     12.7  Entire Agreement and Modifications. . . . . . . . . . . . . . . . .51
     12.8  Parties in Interest . . . . . . . . . . . . . . . . . . . . . . . .51
     12.9  Severability. . . . . . . . . . . . . . . . . . . . . . . . . . . .51
     12.10  Records and Audits . . . . . . . . . . . . . . . . . . . . . . . .51
     12.11  Counterparts . . . . . . . . . . . . . . . . . . . . . . . . . . .52

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SCHEDULES

Schedule 1  Abandonment Obligations
Schedule 2  Point Arguello Assets
Schedule 3  Microwave Communication Assets
Schedule 4  Ventura Office Assets
Schedule 4A Offsite Stored Inventory
Schedule 5  Applicable Contracts
Schedule 6  Applicable Permits
Schedule 7  Contracts and Permits for Transfer to Partnerships
Schedule 8  Measured Inventories
Schedule 9  Valuation Procedure for Measured Inventories

Schedule 10 Allocation of Purchase Price Schedule 11 Rights of First Refusal
Schedule 12 FERC Tariffs
Schedule 13 Project Permitting, Planning and Execution Schedule 14 Excluded Items

EXHIBITS

Exhibit A   Grant Deed for Fee Property
Exhibit B   Assignment and Assumption Agreement for Easements
Exhibit C   Assignment and Assumption Agreement for Leases and Contracts
Exhibit D   Bill of Sale for Personal Property
Exhibit E   Services Agreement
Exhibit F   [INTENTIONALLY OMITTED]
Exhibit G   Opinion of Buyer's Counsel
Exhibit H   Opinion of Sellers' Counsel
Exhibit I   Affidavits of Sellers' Non-Foreign Status
Exhibit J   Chevron Corporation Guaranty in Favor of Buyer
Exhibit K   Supplemental Performance Bond in Favor of MMS
Exhibit L   Performance Bond in Favor of Sellers
Exhibit M   Voting Agreements for Units and Partnership Interests

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PURCHASE AND SALE AGREEMENT

THIS PURCHASE AND SALE AGREEMENT (this "Agreement"), entered into as of June 4, 1999 (the "Execution Date"), by and among CHEVRON U.S.A. INC., a Pennsylvania corporation ("CUSA"), CHEVRON PIPE LINE COMPANY, a Delaware corporation ("CPL"), and PLAINS RESOURCES INC., a Delaware corporation ("Buyer"),

W I T N E S S E T H:

WHEREAS CUSA and CPL (collectively "Sellers") are the owners of interests in crude oil and natural gas production properties located offshore California and wells, platforms, pipelines, processing facilities, terminals, storage facilities, real property interests, equipment, inventories and other property related thereto defined below; and

WHEREAS Sellers desire to sell such interests to Buyer, and Buyer desires to purchase such interests from Sellers, on the terms and subject to the conditions set forth in this Agreement:

NOW, THEREFORE, in consideration of the mutual promises set forth in this Agreement, Sellers and Buyer hereby agree as follows:

ARTICLE 1

DEFINITIONS

1.1 DEFINED TERMS. As used in this Agreement, the following capitalized terms shall have the respective meanings set forth below or in the respective referenced Sections.

ABANDONMENT OBLIGATIONS. The obligations, as and to the extent required by Laws, permits, licenses or other Government Authority approvals, or rights-of-way or easement agreements or other contracts, to perform the activities defined in Schedule 1 with respect to any of the CUSA Properties, the CPL Properties or the Partnerships' Facilities that would become effective as of and result from the permanent cessation of operation of any given facility; and the obligations to pay the actual costs of performance of the foregoing activities. In the case of Abandonment Obligations with respect to the Partnerships' Facilities or to property subject to a lease, operating agreement or unit agreement, the Abandonment Obligations consist of the Sellers' share of such obligations transferred by this Agreement as allocated to Sellers or Buyer as a member of the applicable unit or holder of an interest in the applicable lease, operating agreement or partnership. Abandonment Obligations do not include any Environmental Losses or other Losses relating to other aspects of the condition of

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a facility that are discovered in the course of conducting the abandonment activities; such Losses shall be allocated between Sellers and Buyer in accordance with Article 3 below.

AFFILIATE. With respect to a given Person, any other Person directly or indirectly controlling, controlled by or under common control with the given Person. For purposes of this definition "control" means ownership of fifty percent (50%) or more of the voting securities or equivalent voting rights of a Person.

AGREEMENT. See Recitals.

APPLICABLE CONTRACTS. The CUSA Applicable Contracts and the CPL Applicable Contracts defined in Article 2, collectively.

APPLICABLE PERMITS. The CUSA Applicable Permits and the CPL Applicable Permits defined in Article 2, collectively.

APPROVAL DATE. See Section 8.1(b).

BUSINESS DAY. Any day other than a Saturday, a Sunday or any other day on which federal banking institutions in the United States of America conducting business in the State of California are required or authorized by Law to suspend such business.

BUYER. See Recitals.

CLAIM. See Section 3.4.

CLEAN SEAS. Clean Seas L.L.C., a California limited liability company formed under a LLC Membership Agreement amended to be effective January 12, 1998 among CUSA, CPL and other parties.

CLOSING. The closing of the transactions contemplated by this Agreement, to be effective at 12:01 a.m. California time on the Closing Date.

CLOSING DATE. See Section 5.2.

COLD STANDBY PERIOD. As to any given platform in the Transferred Properties, the Cold Standby Period shall begin at 12:01 a.m. on the latter of (i) 12 months following notice from Buyer to Sellers that Cold Standby is to begin, or (ii) the date on which all wells drilled from a given platform have been abandoned to MMS standards, all well conductors have been removed, and all platform facilities have been purged and cleared of hydrocarbons to a safe level as required by applicable regulatory standards. As to any given onshore facility or offshore or onshore pipeline in the Transferred Properties, the Cold Standby Period shall begin at 12:01 am on the date on which all facility or pipeline components have been purged and cleared of hydrocarbons to a safe level as required by applicable regulatory standards. The Cold Standby Period for any platform, facility or pipeline ends on the date on which the Abandonment Obligations allocated to Sellers in Schedule 1 with respect to such platform, facility or pipeline have been completed.

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For purposes of having Cold Standby apply to a portion of an onshore facility in circumstances whereby any equipment owned and maintained by the partnership which owns the facility remains in service for the purpose of processing, handling, or storing crude oil or natural gas, Buyer must establish that such portion of the facility to be placed in Cold Standby (i) has ceased operation and has been purged and cleaned of hydrocarbons and other process materials, (ii) has been completely isolated from any equipment that remains in service both mechanically and electrically, (iii) can be abandoned using usual, economic means of removal, demolition, etc. according to applicable regulations and reasonably permitted conditions without undue risk and hazard from the ongoing operations, and (iv) can be abandoned without increasing costs over the full removal of such facility once operations have completely ceased.

COLD STANDBY COSTS. The costs incurred during the Cold Standby Period for maintenance of any given platform, processing plant or other facility, or pipeline, including operating costs, insurance, taxes, bonds (other than those bonds required of Buyer hereunder), and management fees and general and administrative overhead charges chargeable under applicable agreements.

CONFIDENTIALITY AGREEMENT. The Confidentiality Agreement dated April 22, 1999 between CUSA and Buyer.

CPL PROPERTIES. See Section 2.2.

CUSA PROPERTIES. See Section 2.1.

DEPOSIT. See Section 4.1.

DISCLOSURE LETTER. The letter from Sellers to Buyer dated May 5, 1999 and referencing Article 7 of this Agreement, including all attachments to such letter.

DOLLARS OR $. United States of America dollars.

ENVIRONMENTAL CONDITION. Any condition resulting from a violation of Laws and permits, licenses and other Government Authority approvals relating to environmental, health and safety matters to the extent that prosecution, if instituted, or removal and remediation, if required, would be reasonably likely to result in Environmental Losses.

ENVIRONMENTAL LOSSES. Losses relating to the presence, release, discharge or threatened discharge of Subject Materials in or into the air, surface water, ground water, soil, land surface, subsurface strata or soil vapor in excess of levels permitted by Laws, permits, licenses or other Government Authority approvals; Losses incurred in investigating and remediating such presence, release, discharge or threatened discharge; and Losses relating to noncompliance with Laws, permits, licenses or other Government Authority approvals pertaining to Subject Materials or otherwise relating to environment, health and safety, including Laws related to "endangered species" or "threatened species" (e.g., 16 U.S.C. Section 1531 et seq. and California Fish and Game Code Section 2000 et seq.). Notwithstanding the

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foregoing, Abandonment Obligations do not constitute Environmental Losses for purposes of this Agreement.

EXECUTION DATE. See Recitals.

FERC. Federal Energy Regulatory Commission.

GOVERNMENT AUTHORITY. Any national, state or local government or any subdivision, agency, court, commission, board, bureau or other authority thereof.

GGP. Gaviota Gas Plant Company, a California general partnership formed under a Partnership Agreement dated October 1, 1984.

HYDROCARBON INVENTORIES. See Section 2.3.

INTEREST RATE. The lesser of (i) the interest rate announced as of the Closing Date by the principal San Francisco, California office of Bank of America, N.T.&S.A. as its prime rate or reference rate or (ii) the highest rate permitted by applicable Laws.

LAWS. All applicable statutes, laws, rules, regulations, orders, ordinances, judgments, decrees, directives, instructions, and interpretations of any Government Authority, including common law, equity and other legal principles.

LIENS. All pledges, mortgages, charges, security interests, options, rights of first refusal or first offer, preemptive rights or any other encumbrances or liens of any kind in respect of any of the Transferred Properties.

LOSSES. All liabilities, losses, damages, costs, penalties (civil or criminal), expenses, fines, settlements, interest, reasonable attorneys' fees, suits, causes of action, legal or administrative proceedings, arbitration awards, demands or claims, including claims for personal injury or damage to business property. Losses may include claims of consequential or punitive damages sought by third parties against any of Sellers, Buyer or their Affiliates, but exclude (i) any claims of consequential damages suffered by any of Sellers, Buyer or their Affiliates, including claims of lost profits, lost revenue or loss of use of facilities or assets, and (ii) any claims of punitive damages by any of Sellers, Buyer or their Affiliates. Losses include Environmental Losses defined above.

MATERIAL DISCOVERY. See Section 8.1(b).

MEASURED INVENTORIES. See Section 4.3(a).

MMS. The Minerals Management Service of the United States Department of the Interior (or successor Government Authority).

MMS PERFORMANCE BOND. See Section 3.6(a).

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PANGL. Point Arguello Natural Gas Line Company, a California general partnership formed under a Partnership Agreement dated September 1, 1984.

PAPCO. Point Arguello Pipeline Company, a California general partnership formed under a Partnership Agreement dated August 1, 1984.

PARTNERSHIP INTERESTS. The partnership interests of Sellers in GGP, PANGL, PAPCO and PATC collectively.

PARTNERSHIPS' FACILITIES. The real property, including fixtures and improvements thereon, owned or operated as of the Closing Date by any of GGP, PANGL, PAPCO or PATC.

PATC. Point Arguello Terminal Company, a California general partnership formed under a Partnership Agreement dated January 1, 1998.

PERMITTED ENCUMBRANCES. Any of the following:

(i) lessor's royalties, non-participating royalties, overriding royalties, division orders and sales contracts containing customary terms and provisions covering oil, gas or associated liquefied or gaseous hydrocarbons, reversionary interests, and similar burdens if the net cumulative effect of such burdens does not operate to reduce the net revenue interest claimed by Sellers;

(ii) Liens for taxes or assessments not yet due or delinquent or, if delinquent, that are being contested in good faith in the normal course of business;

(iii) all rights to consent by, required notices to, filings with, or other actions by governmental entities in connection with the sale or conveyance of oil and gas leases or interests therein, if the same are customarily obtained subsequent to such sale or conveyance and Buyer has no reason to believe they cannot be obtained;

(iv) easements, road-use agreements, rights-of-way, servitudes, permits, surface leases and other rights in respect of surface operations, or defects or deficiencies in title thereto, that do not materially interfere with Buyer's operation or use of the Transferred Properties;

(v) zoning, planning and environmental Laws to the extent valid and applicable to the Transferred Properties; and

(vi) Liens of carriers, warehousemen, mechanics, workers, material suppliers or other providers of materials or services arising by operation of Law in the ordinary course of business or incident to the construction or improvement of any property in respect of obligations which are not yet due.

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PERSON. Any individual, partnership, corporation, limited liability company, business trust, joint stock company, trust, unincorporated association, joint venture, firm, Government Authority or other entity or person.

PURCHASE PRICE. See Section 4.2.

SELLERS. See Recitals.

SELLERS' BANK ACCOUNT. Account number 55-58727 in the name of Chevron Corporation at the Chicago, Illinois principal office of First National Bank of Chicago, American Banking Association ("ABA") number 0710-0001-3, or such other account as Sellers may designate by written notice to Buyer more than three Business Days prior to the payment date of any payment obligation of Buyer under this Agreement.

SELLERS' PERFORMANCE BOND. See Section 3.6(b).

SETTLEMENT ESTIMATE. See Section 4.4.

SETTLEMENT STATEMENT. See Section 4.4.

STRUCTURAL CONDITION. Any rupture, fracture, corrosion or similar physical defect in any structural component of the platforms included in the Transferred Properties not constituting ordinary wear and tear and not covered by any applicable warranty, insurance policy or maintenance service contract provided at Sellers' expense.

SUBJECT MATERIAL. Any substance, product, waste or other material which is, or becomes identified, listed, published or defined as a hazardous substance, hazardous waste, hazardous material, toxic substance, solid waste or pollutant, or which is otherwise regulated or restricted under any Laws or permits, licenses or other Government Authority approvals, including the Comprehensive Environmental Response Compensation and Liability Act (CERCLA), the Superfund Amendments and Reauthorization Act (SARA), the Hazardous Materials Transportation Act, the Resource Conservation and Recovery Act (RCRA), the Toxic Substances Control Act (TSCA), the Clean Water Act and the Oil Pollution Liability and Compensation Act of 1990 (OPA 90). Without limitation, Subject Material includes hydrocarbons, asbestos and polychlorinated biphenyls.

TITLE DEFECT. Any defect or deficiency in title, except for Permitted Encumbrances, that (i) creates a Lien affecting the interests of Sellers in the Transferred Properties, (ii) diminishes Sellers' net revenue interest (defined as Sellers' share of the proceeds from the sale of hydrocarbons produced from and allocable to the Transferred Properties, net of all royalties, overriding royalties, or other burdens on production or non-operating interests applicable thereto) with respect to a particular Transferred Property to an interest less than that set forth on a Schedule hereto, (iii) increases Sellers' working interest (defined as Sellers' share of the costs of operation, development or production borne by the owner of such interest) with respect to a particular Transferred Property to an interest greater than that set forth on a Schedule hereto without a corresponding increase in Sellers' net revenue interest, (iv) creates an obligation to pay costs in an amount greater than Sellers' working interest with respect to a particular Transferred Property as set forth on a

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Schedule hereto, or (v) constitutes a lack of validity or perfection of title such that a reasonably prudent person, engaged in the ownership, development and operation of oil and gas properties or assets with knowledge of all the facts would not be willing to accept title without curing such defect.

TRANSFERRED PROPERTIES. The CUSA Properties, the CPL Properties, the Hydrocarbon Inventories, the Partnership Interests and the transferred interests of CUSA and CPL in Clean Seas collectively. Transferred Properties specifically excludes the Partnerships' Facilities, which continue to be owned by the relevant partnerships, but includes CUSA's and CPL's interests in such partnerships.

YEAR 2000 COMPLIANT AND YEAR 2000 COMPLIANCE. See Section 7.6.

1.2 RULES OF CONSTRUCTION. For the purposes of this Agreement, unless the context otherwise requires:

(a) GENERAL. In any provision, (i) "or" is not exclusive; (ii) "including" and "include" are not exclusive; (iii) an accounting term not otherwise defined has the meaning assigned to it in accordance with accounting principles that are generally accepted in the United States of America; (iv) words in the singular include the plural and words in the plural include the singular; (v) words in the masculine include the feminine and words in the feminine include the masculine; (vi) any date specified for any action that is not a Business Day shall be deemed to mean the first Business Day after such date; and (vii) a reference to a corporation, limited liability company or a partnership includes its successors and permitted assigns.

(b) ARTICLES AND SECTIONS. References to Articles and Sections without identifying a specific agreement shall be deemed references to Articles and Sections of this Agreement. The captions of Articles and Sections are for convenience of reference only and shall not be used in the interpretation of this Agreement.

(c) AGREEMENTS AND INSTRUMENTS. References to this Agreement or any other agreement or instrument shall be deemed references to such agreement or instrument as it may from time to time be amended, and shall be deemed to refer to any schedules, exhibits or other materials incorporated into such agreement or instrument.

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ARTICLE 2

PURCHASE AND SALE OF TRANSFERRED PROPERTIES

2.1 CUSA PROPERTIES. At the Closing, CUSA shall sell, convey, transfer and assign to Buyer and Buyer shall purchase and receive from CUSA all right, title and interest of CUSA in and to assets associated with Sellers' crude oil and natural gas production associated with the Point Arguello Project, as such assets are described as follows (collectively the "CUSA Properties"). Notwithstanding the foregoing, certain CUSA Properties are jointly used in the ownership, use, operation, maintenance, improvement or abandonment of the properties related to the Santa Barbara Channel and Dos Cuadras Projects (the "SBC/DC Properties") transferred to Venoco, Inc. ("Venoco") under the Purchase and Sale Agreement among CUSA, CPL, Venoco and Ellwood Pipeline, Inc. dated as of November 4, 1998. Such jointly used properties are designated in the referenced Schedules by a "J," and shall be transferred in accordance with the provisions of Section 5.5 of this Agreement:

(a) OIL AND GAS LEASES. All of CUSA's oil and gas leases and lease operating agreements described in Part A of Schedule 2 attached to this Agreement, which includes all of CUSA's interests in the Point Arguello Unit, the Rocky Point Unit, the overriding royalty interest in State of California leases, and the Cojo lease defined in Schedule 2 (collectively the "Oil and Gas Leases");

(b) UNIT AGREEMENTS. The unit agreements, unit operating agreements, joint operating agreements and facility operating agreements described in Part B of Schedule 2 attached to this Agreement (the "Unit Agreements");

(c) WELLS. The oil and gas wells, disposal wells, injection wells and other wells located on the real property described in (a) above or (d) below or on real property subject to the Unit Agreements, as such wells are described in Part C of Schedule 2 attached to this Agreement (the "Wells");

(d) CUSA REAL PROPERTY. The fee properties, surface leases, easements and other real property interests described in Part D-1 of Schedule 2 attached to this Agreement (the "CUSA Real Property");

(e) CUSA FIXED ASSETS. The production platforms, equipment, machinery, furnishings, vehicles, fixtures, flowlines, roads, pipelines, pole lines, appurtenances, materials, improvements, spare parts, and other property (excluding Hydrocarbon Inventories separately defined below) related to the foregoing assets, as described more particularly in Part E-1 of Schedule 2 attached to this Agreement (the "CUSA Fixed Assets");

(f) MICROWAVE COMMUNICATION ASSETS. The site leases and other property and contract rights, the Federal Communications Commission licenses, and transmitter, receiver, repeater and other equipment and furnishings utilized for microwave communication related

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to the foregoing assets, as described more particularly in Schedule 3 attached to this Agreement (the "Microwave Communication Assets");

(g) VENTURA OFFICE ASSETS. The equipment, furnishings and vehicles located at CUSA's Ventura Business Unit office at 646 County Square Drive, Ventura, California, described more particularly in Schedule 4 attached to this Agreement (the "Ventura Office Assets");

(h) OFFSITE STORED INVENTORY. The inventory of parts and equipment associated with the foregoing properties and stored at locations other than at the foregoing property, as described in Schedule 4A attached to this Agreement (the "Offsite Stored Inventory");

(i) CUSA APPLICABLE CONTRACTS. The contracts of CUSA relating to the foregoing assets or the ownership, use, operation, maintenance, improvement or abandonment thereof, or to the production, treatment, sale, storage or disposal of hydrocarbons, water or other substances associated therewith, described in Schedule 5 attached to this Agreement (the "CUSA Applicable Contracts");

(j) CUSA APPLICABLE PERMITS. The licenses, permits and other approvals issued by Government Authorities to CUSA relating to the foregoing assets or the ownership, use, operation, maintenance, improvement or abandonment thereof, or to the production, treatment, sale, storage or disposal of hydrocarbons, water or other substances associated therewith, described in Schedule 6 attached to this Agreement (the "CUSA Applicable Permits"); and

(k) CUSA RECORDS. Subject to the provisions of Section 12.10 below, the files, records and other information relating to the Point Arguello Project owned by CUSA available through CUSA's best efforts to locate such information and which CUSA is not prohibited from transferring to Buyer by Laws, Applicable Permits or existing contractual relationship (collectively the "CUSA Records"), including (i) lease, land and title records (including abstracts of title, title opinions, certificates of title, title curative documents, division orders, and division order files), (ii) the CUSA Applicable Contracts and CUSA Applicable Permits documents, (iii) well logs, well test data, well production reports, maps, environmental, and production files, (iv) core samples from wells, (v) input and output data with respect to engineering simulation models (excluding modeling software), (vi) Sellers' geological or geophysical data (including magnetic tapes, field notes, seismic lines, structure maps and isopach maps) relating to properties within the Point Arguello Project, the Rocky Point Unit, the overriding royalty interests in State of California leases and the Cojo lease included in the CUSA Properties and not held by Sellers subject to any obligation of confidentiality in favor of any third party, and (vii) any of the foregoing data contained in electronic production databases.

2.2 CPL PROPERTIES. At the Closing, CPL shall sell, transfer and assign to Buyer and Buyer shall purchase and receive from CPL all right, title and interest of CPL in and to assets described as follows (collectively the "CPL Properties"). Notwithstanding the foregoing, certain CPL Properties are jointly used in the ownership, use, operation, maintenance, improvement or abandonment of the properties related to the Santa Barbara

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Channel and Dos Cuadras Projects (the "SBC/DC Properties") transferred to Ellwood Pipeline, Inc. ("Ellwood") under the Purchase and Sale Agreement dated as of November 4, 1998. Such jointly used properties are designated in the referenced Schedules by a "J," and shall be transferred in accordance with the provisions of Section 5.5 of this Agreement:

(a) CPL REAL PROPERTY. The fee properties, surface leases, easements and other real property interests described in Part D-2 of Schedule 2 attached to this Agreement (the "CPL Real Property");

(b) CPL FIXED ASSETS. The pipelines, pump stations, equipment, machinery, furnishings, vehicles, fixtures, roads, pole lines, appurtenances, materials, improvements, spare parts, and other property (excluding Hydrocarbon Inventories defined below) related to the foregoing assets, as described more particularly in Part E-2 of Schedule 2 attached to this Agreement (the "CPL Fixed Assets");

(c) CPL APPLICABLE CONTRACTS. The contracts of CPL relating to the foregoing assets or the ownership, use, operation, maintenance, improvement or abandonment thereof described in Schedule 5 attached to this Agreement (the "CPL Applicable Contracts");

(d) CPL APPLICABLE PERMITS. The licenses, permits and other approvals issued by Government Authorities to CPL relating to the foregoing assets or the ownership, use, operation, maintenance, improvement or abandonment thereof described in Schedule 6 attached to this Agreement (the "CPL Applicable Permits"); and

(e) CPL RECORDS. Subject to the provisions of Section 12.10 below, the files, records and other information relating to the Point Arguello Project owned by CPL available through CPL's best efforts to locate such information and which CPL is not prohibited from transferring to Buyer by Laws, Applicable Permits or existing contractual relationship (collectively the "CPL Records"), including (i) lease, land and title records (including abstracts of title, title opinions, certificates of title, title curative documents, division orders, and division order files), (ii) the CPL Applicable Contracts and Applicable Permits documents and (iii) environmental files.

2.3 HYDROCARBON INVENTORIES. At the Closing, Sellers shall sell, convey, transfer and assign to Buyer and Buyer shall purchase and receive from Sellers all right, title and interest of Sellers in and to the crude oil, natural gas, casinghead gas, drip gasoline, natural gasoline, natural gas liquids, condensate products and other hydrocarbons, whether gaseous or liquid, produced from or allocable to the CUSA Properties, the CPL Properties, or other real property subject to the Unit Agreements that are in the custody of CUSA or CPL, or in the possession of any of the GGP, PANGL, PAPCO or PATC partnerships, as of the Closing Date. The portion of the Hydrocarbon Inventories physically present in the PATC facilities described in Schedule 8 attached hereto (the "Measured Inventories") shall be measured as of the Closing Date and valued separately as provided in Section 4.3(a) below.

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2.4 PARTNERSHIP INTERESTS AND CLEAN SEAS INTERESTS.

(a) GGP INTEREST. At the Closing, CUSA shall sell, transfer and assign to Buyer and Buyer shall purchase and receive from CUSA the partnership interest of CUSA in GGP, including all of CUSA's rights and duties under the applicable partnership agreement referenced in part F of Schedule 2 attached hereto.

(b) PANGL, PAPCO AND PATC INTERESTS. At the Closing, CPL shall sell, transfer and assign to Buyer and Buyer shall purchase and receive from CPL the partnership interests of CPL in each of PANGL, PAPCO and PATC, including all of CPL's rights and duties under the applicable partnership agreements referenced in part F of Schedule 2 attached hereto.

(c) CLEAN SEAS INTERESTS. At the Closing, CUSA shall sell, transfer and assign to Buyer and Buyer shall purchase and receive from CUSA the membership interest of CUSA in Clean Seas. At the Closing, CPL shall sell, transfer and assign to Buyer and Buyer shall purchase and receive from CPL the portion of the membership interest of CPL in Clean Seas associated with the CPL Properties. CPL shall retain the portion of its membership interest in Clean Seas (including the related portion of its capital account in Clean Seas) associated with Sellers' Estero, California terminal and related facilities and vessel and barge movements to and from such terminal. Buyer shall take all actions necessary for Sellers and Sellers' contractors to qualify for Clean Seas spill response coverage in the course of performance of any Abandonment Obligations retained by Sellers hereunder, notwithstanding any subsequent transfer or disposal of interests by Buyer in the Transferred Properties. Any capital contributions or other payments of expenses associated with the requirements for Buyer to receive and maintain a membership interest in Clean Seas shall be for Buyer's account.

(d) ALLOCATION OF POST-CLOSING DATE PARTNERSHIP AND CLEAN SEAS EXPENSES. Buyer shall pay the share of operating and capital expenses associated with the Partnership Interests and the Clean Seas interests transferred to Buyer hereunder from the Closing Date until the commencement of the Cold Standby Period for a given platform or other facility. The operating and capital expenses associated with such interests for a particular platform or other facility from the beginning of its Cold Standby Period until the completion of Sellers' Abandonment Obligations with respect thereto shall be allocated between Sellers and Buyer based on their respective proportions of Abandonment Obligations during such period. The same principles shall apply to the allocation of expenses for CUSA Properties and CPL Properties subject to a unit agreement or operating agreement.

(e) ALLOCATION OF DISTRIBUTIONS, CASH CALLS AND CAPITAL ACCOUNTS. Any distributions of cash by any of GGP, PANGL, PAPCO, PATC or Clean Seas resulting from activities prior to the Closing Date shall be for the account of Sellers. Any distributions of cash by any of GGP, PANGL, PAPCO, PATC or Clean Seas resulting from activities on or after the Closing Date shall be for the account of Buyer. Any cash calls by any of GGP, PANGL, PAPCO, PATC or Clean Seas to fund the payment of accounts payable accruing prior to the Closing Date shall be for the account of Sellers. Any cash calls by any of GGP, PANGL, PAPCO, PATC or Clean Seas to fund the payment of accounts payable accruing on or after the Closing Date shall be for the account of Buyer. Except as stated above in this Section 2.4, the capital account of Sellers in each of GGP, PANGL, PAPCO, PATC and

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Clean Seas shall be transferred to Buyer as of the Closing Date. The same principles shall apply to the allocation of distributions, cash calls and capital accounts (if any) for CUSA Properties and CPL Properties subject to a unit agreement or operating agreement.

2.5 INCLUDED AND EXCLUDED ITEMS.

(a) INCLUDED ITEMS. Any rights of Sellers to unused emission reduction credits associated with the Transferred Properties or capital projects for which Applicable Permits have been obtained or are pending shall be transferred to Buyer on Closing. To the extent that Buyer holds any such unused credits at the time Sellers commence performance of their retained Abandonment Obligations, Buyer shall transfer such credits to Sellers or make such credits available for use by Sellers at no cost to Sellers.

(b) EXCLUDED ITEMS. Notwithstanding the foregoing Sections of this Article 2, the following items shall be excluded from the Transferred Properties: (i) property owned by hydrocarbon buyers or by contractors; (ii) Sellers' geological or geophysical data not related to the Point Arguello Project, the Rocky Point Unit, the overriding royalty interest in State of California leases or the Cojo lease included in the CUSA Properties; (iii) cash located at the Transferred Properties, deposits with Government Authorities, contractors and vendors, and other cash equivalents, to the extent that such cash was generated from transactions occurring prior to the Closing Date or such deposit was made prior to the Closing Date (provided, however, that Sellers' interest in any cash held by Clean Seas shall be for Buyer's account to the extent Sellers' equity interests in Clean Seas are transferred hereunder); (iv) items used, consumed or disposed of in the ordinary course of business prior to the Closing; (v) surety bonds posted at the request of Sellers; (vi) rights under insurance policies held by Sellers or their Affiliates covering any of the Transferred Properties or Sellers' interests in any of GGP, PANGL, PAPCO, PATC or Clean Seas; (vii) any software or other systems used by CPL for monitoring and control of the CPL Properties from remote locations; (viii) rights to technology, software and other intellectual property listed on Schedule 14 attached to this Agreement; (ix) the items of equipment listed on Schedule 14 attached to this Agreement; and
(x) records that are subject to attorney-client privilege, work product immunity or other privileges against disclosure enjoyed by Sellers or their representatives.

2.6 CONVEYANCING INSTRUMENTS. The fee real property to be conveyed at Closing shall be conveyed by means of grant deeds in the form of Exhibit A attached to this Agreement. The rights-of-way and other easements to be transferred at Closing shall be transferred by means of assignment and assumption agreements in the form of Exhibit B attached to this Agreement. The oil and gas leases, surface leases, unit agreement rights and other contract rights to be conveyed or transferred at Closing shall be transferred by means of assignment and assumption agreements in the form of Exhibit C attached to this Agreement, or such assignment forms as may be prescribed by applicable Government Authorities. The personal property to be transferred at Closing shall be transferred by means of bills of sale in the form of Exhibit D attached to this Agreement. The Partnership Interests and Clean Seas interests to be transferred at Closing shall be transferred by means of assignment and assumption agreements conforming in each case to the requirements of the applicable partnership or limited liability company agreement. The transferable Applicable Permits will

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be transferred by means of appropriate forms consistent with the requirements of the applicable Government Authority.

ARTICLE 3

ASSUMPTION AND INDEMNIFICATION OF LIABILITIES

3.1 LIABILITIES RETAINED BY SELLERS.

(a) CUSA shall indemnify, defend and hold harmless Buyer from and after the Closing against any Losses attributable to a breach of CUSA's representations and warranties or a material breach of CUSA's covenants under this Agreement, provided that (i) any claim of Buyer for breach of CUSA's representations and warranties shall be void unless notice of such claim is given to Sellers within one year after the Closing Date and (ii) any claim of Buyer for breach of CUSA's representations and warranties must individually exceed Fifty Thousand Dollars ($50,000).

(b) CPL shall indemnify, defend and hold harmless Buyer from and after the Closing against any Losses attributable to a breach of CPL's representations and warranties or a material breach of CPL's covenants under this Agreement, provided that (i) any claim of Buyer for breach of CPL's representations and warranties shall be void unless notice of such claim is given to Sellers within one year after the Closing Date and (ii) any claim of Buyer for breach of CPL's representations and warranties must individually exceed Fifty Thousand Dollars ($50,000).

(c) From and after the Closing CUSA agrees that it shall perform when due the Abandonment Obligations associated with the CUSA Properties that are allocated to "Chevron" as set forth in Schedule 1 attached hereto, and shall indemnify, defend and hold harmless Buyer against any Losses attributable to non-performance or the manner of performance of such Abandonment Obligations.

(d) From and after the Closing CPL agrees that it shall perform when due the Abandonment Obligations associated with the CPL Properties that are allocated to "Chevron" as set forth in Schedule 1 attached hereto, and shall indemnify, defend and hold harmless Buyer against any Losses attributable to non-performance or the manner of performance of such Abandonment Obligations.

(e) From and after the Closing CUSA agrees that it shall indemnify, defend and hold harmless Buyer against all Losses that are attributable to ownership, use, operation, maintenance, improvement or abandonment of any of the CUSA Properties prior to the Closing, including offsite transportation, storage, treatment and disposal of Subject Materials from such properties prior to the Closing, but excluding Abandonment Obligations and other liabilities and obligations assumed by Buyer under Section 3.2 below.

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(f) From and after the Closing CPL agrees that it shall indemnify, defend and hold harmless Buyer against all Losses that are attributable to ownership, use, operation, maintenance, improvement or abandonment of any of the CPL Properties prior to the Closing, including offsite transportation, storage, treatment and disposal of Subject Materials from such properties prior to the Closing, but excluding Abandonment Obligations and other liabilities and obligations assumed by Buyer under Section 3.2 below.

(g) From and after the Closing CUSA agrees to reimburse Buyer for or directly pay Buyer's share of any cash call or other assessment by the operator of any unit or pursuant to any operating agreement to which the Transferred Properties are subject, or by GGP, with respect to (i) the investigation, funding, remediation, defense or settlement of any Abandonment Obligations allocated to "Chevron" in Schedule 1 with respect to unit property or the GGP Partnerships' Facilities, and (ii) any Losses that are attributable to injuries suffered or casualties occurring on the Transferred Properties, the property of any unit or operating agreement to which the Transferred Properties are subject, or the GGP Partnerships' Facilities prior to the Closing.

(h) From and after the Closing CPL agrees to reimburse Buyer for or directly pay Buyer's share of any cash call or other assessment by any of PAPCO, PANGL or PATC with respect to (i) the investigation, funding, remediation, defense or settlement of any Abandonment Obligations allocated to "Chevron" in Schedule 1 for the applicable Partnerships' Facilities, and
(ii) any Losses that are attributable to injuries suffered or casualties occurring at the applicable Partnerships' Facilities prior to the Closing.

(i) In the event the operator of any unit or operating agreement to which the Transferred Properties are subject or any of GGP, PAPCO, PANGL or PATC makes a cash call on unit owners or partners or provides other communications to unit owners or partners with respect to the payment liabilities retained by Sellers under clauses (h) and (g) above, Buyer shall promptly forward the cash call or other communication to the applicable Seller for review and payment. At the Closing, Buyer shall execute and deliver to Sellers Voting Agreements in the form attached as Exhibit M to this Agreement, by which Sellers shall have the right to receive information, attend meetings and direct the casting of Buyer's vote and the exercise of Buyer's approval or rejection rights in the Point Arguello Unit, the Rocky Point Unit, lease operating agreements, and each of GGP, PANGL, PAPCO, PATC and Clean Seas with respect to such payment liabilities retained by Sellers. If any of the Transferred Properties are subsequently subject to a different or amended unit, partnership or comparable agreement, Buyer shall grant Sellers similar information and voting rights with respect to the new agreement.

(j) Without limitation on liabilities retained by Sellers hereunder,
(i) if applicable Government Authorities require Buyer to take investigatory or remedial action with respect to the shell mound and oil spotting matters disclosed by Sellers in the Disclosure Letter, CUSA shall indemnify, defend and hold harmless Buyer and its Affiliates against the costs of performing such investigations or remedies, and (ii) the responsibility for defending against and settling or paying any judgment or arbitration monetary award issued in any of the litigation or arbitration proceedings filed prior to the Closing Date and disclosed in the Disclosure Letter shall remain with CUSA or CPL rather than with Buyer.

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3.2 LIABILITIES ASSUMED BY BUYER.

(a) Buyer shall indemnify, defend and hold harmless Sellers from and after the Closing against any Losses attributable to a breach of Buyer's representations and warranties or a material breach of Buyer's covenants under this Agreement, provided that (i) any claim of Sellers for breach of Buyer's representations and warranties shall be void unless notice of such claim is given to Buyer within one year after the Closing Date and (ii) any claims for breach of Buyer's representations and warranties must individually exceed Fifty Thousand Dollars ($50,000).

(b) From and after the Closing Buyer agrees that it shall perform when due the Abandonment Obligations associated with the Transferred Properties that are allocated to "Buyer" as set forth in Schedule 1 attached hereto, and shall indemnify, defend and hold harmless Sellers against any Losses attributed to non-performance or the manner of performance of such Abandonment Obligations.

(c) Buyer shall indemnify, defend and hold harmless Sellers and their Affiliates from and after the Closing against all Losses that are attributable to the ownership, use, operation, maintenance, improvement or abandonment of the Transferred Properties and the Partnerships' Facilities on and after the Closing Date, including offsite transportation, storage, treatment and disposal of Subject Materials from such properties on and after the Closing Date.

(d) Buyer shall indemnify, defend and hold Sellers and their Affiliates harmless from and against all Losses attributable to (i) Buyer's employee selection and offer process and actions taken by Buyer and its Affiliates relating to employees or former employees of Sellers or their Affiliates, (ii) Buyer's use of employee records or other records maintained by Sellers or their Affiliates that have been provided to Buyer and (iii) the actions of any employees of Sellers or their Affiliates acting on Buyer's behalf and at Buyer's direction in connection with Buyer's employee selection and offer process.

3.3 GENERAL LIABILITY PROVISIONS.

(a) Notwithstanding the allocation of Abandonment Obligations in Schedule 1, Buyer shall be responsible to Sellers for any additional or increased costs of performing and paying Abandonment Obligations resulting from any material expansions or modifications to the applicable platforms, facilities or other property to be abandoned, or from any material modifications to the underlying permits, rights-of-way or other contract rights or land use rights granted by any Persons, if such modifications were made by Buyer or its representatives after the Closing Date.

(b) For purposes of allocating liability between Sellers and Buyer under the indemnity provisions of this Agreement, Losses shall be deemed to be attributable to ownership, use, operation, maintenance, improvement or abandonment as of the time that an injury or alleged injury is suffered by a Person, and not as of the time that a claim or legal action is filed or as of the time that an allegedly deficient condition was created.

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3.4 CLAIMS PROCEDURES.

(a) Any party entitled to indemnification hereunder (the "Indemnitee") shall notify the party liable for such indemnification (the "Indemnitor") in writing of any Loss which the Indemnitee has determined has given or could give rise to a claim for indemnification under this Agreement. Such notice (a "Notice of Claim") shall specify in reasonable detail, so far as the Indemnitee is able to do so, the nature and any particulars of any such claim giving rise to a right of indemnification (including the amount thereof, so far as the Indemnitee is able to do so). Any Notice of Claim shall be given promptly after Indemnitee has actual knowledge of the Loss, and in no event more than 45 calendar days after such knowledge (or, in the case of a Loss involving filing of a complaint or other pleading, such Notice of Claim shall be given to allow reasonable time for the Indemnitor to answer or otherwise respond to such pleading). Failure or delay of the Indemnitee to give such notice shall relieve the Indemnitor of any liability to the extent actual prejudice results. The Indemnitee shall permit access (or ensure that any relevant Affiliate permits access) by the Indemnitor or its representatives to all personnel, records and other materials reasonably required by them for their use in connection with any Claim, and shall cooperate with the Indemnitor in connection with all such Claims as reasonably required by the Indemnitor.

(b) With respect to any suit, cause of action, legal or administrative proceeding, arbitration, demand or claim by a third party (a "Claim") that could give rise to indemnification under this Agreement, the Indemnitor shall defend (in the name of the Indemnitee, if necessary), at its own expense with attorneys of its own selection (and who shall be reasonably satisfactory to the Indemnitee), any such Claim, and the Indemnitee shall not settle any such Claim without the Indemnitor's written consent; provided, that if any Indemnitor is not defending such Claim within 30 calendar days after having been afforded the opportunity to do so in accordance with this Section, then the Indemnitee shall have the right to reasonably defend the Claim in such manner as it may deem appropriate at the cost and expense of the Indemnitor, and the Indemnitor shall promptly reimburse the Indemnitee therefor in accordance with this Agreement, and the Indemnitor's consent to any proposed settlement shall not be unreasonably withheld. Notwithstanding the assumption by the Indemnitor of the defense of any Claim as provided in this Section 3.4, the Indemnitee shall be permitted to participate in the defense of such Claim and to employ counsel at its own expense (subject to the right of the Indemnitor to control and direct such defense).

(c) If the Indemnitor does not assume the defense of any Claim, then any failure of the Indemnitee to defend shall not relieve the Indemnitor of its obligations hereunder; provided that the Indemnitee shall have given the Indemnitor notice of its intention not to defend and afforded the Indemnitor the opportunity to assume the defense within such period as may be reasonable (taking into consideration when determining whether such period is reasonable, the time when notice was given to the Indemnitee by the Indemnitor that such Indemnitor did not intend to assume the defense thereof). Notwithstanding any other provision of this Section 3.4, no Indemnitor shall settle any Claim without the consent of the Indemnitee if such settlement would involve an admission by the Indemnitee of criminal liability, the consent to any equitable order or injunction or otherwise materially and adversely affect the Indemnitee or its subsidiaries.

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3.5 SECURITY FOR SELLERS' LIABILITIES. On the Closing, Sellers shall deliver to Buyer a Guaranty Agreement executed by Chevron Corporation in the form attached as Exhibit J to this Agreement, by which Chevron Corporation shall guarantee to Buyer the performance and payment when due by each of Sellers of certain obligations arising under this Agreement.

3.6 SECURITY FOR BUYER'S LIABILITIES.

(a) On the Closing, Buyer shall deliver to the MMS a supplemental performance bond in the penal sum required by the MMS executed and acknowledged by Buyer and sureties acceptable to CUSA and the MMS in the form of supplemental bond prescribed by the MMS attached as Exhibit K to this Agreement (the "MMS Performance Bond"), guaranteeing performance and payment when due by Buyer of its Abandonment Obligations with respect to the interests in the offshore MMS oil and gas leases transferred hereunder. A duplicate original of the MMS Performance Bond shall be provided to Sellers on the Closing. Buyer shall not enter into any amendment, waiver, assignment or termination of the MMS Performance Bond without the prior written consent of CUSA. CUSA's consent shall not be unreasonably withheld for amendments of such bond that do not materially impact CUSA's security, or for substitution of a surety that has on the substitution date credit ratings from Standard & Poor's or the equivalent that are as good as or better than the credit ratings for the surety or sureties accepted by CUSA on the Closing. CUSA may otherwise withhold its consent to amendments, waivers, assignments or terminations of the bond in its sole discretion, except as described in clauses (e) and (f) below. Sellers and Buyer shall endeavor to cause the MMS to agree that in the event of any default with respect to Buyer's Abandonment Obligations, the MMS would proceed against the MMS Performance Bond before proceeding against CUSA. CUSA and the sureties providing the MMS Performance Bond shall enter into a similar agreement.

(b) On the Closing, Buyer shall deliver to Sellers a performance bond in favor of Sellers in a penal sum equal to Five Million Dollars ($5,000,000) minus the penal sum required for the MMS Performance Bond in clause (a) above, executed and acknowledged by Buyer and sureties acceptable to Sellers in the form attached as Exhibit L to this Agreement ("Sellers' Performance Bond"), guaranteeing to Sellers the performance and payment when due by Buyer of the Buyer's Abandonment Obligations arising under this Agreement. Seller's Performance Bond shall be maintained by Buyer in full force and effect at all times until the earlier of (i) the date on which all Abandonment Obligations assumed by Buyer have been completely performed and satisfied or (ii) the date Buyer's Abandonment Obligation expenditures are fully credited against the penal sum of such bond, as described in clauses
(c) and (d) below. Sellers' consent shall not be unreasonably withheld for substitution of a surety that has on the substitution date credit ratings from Standard & Poor's or the equivalent that are as good as or better than the credit ratings for the surety or sureties accepted by Sellers on the Closing.

(c) Buyer shall maintain accurate records of their actual expenditures incurred in performing its Abandonment Obligations, and shall deliver to Sellers reports of such expenditures promptly after each calendar year in which Abandonment Obligations are performed. For purposes of this Agreement, any expenditures for an Abandonment Obligation completion of which requires approval from a Governmental Authority or contract

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party shall not be deemed expended until the calendar year in which such approval is obtained. Sellers or their authorized representatives may audit Buyer's records for the purpose of verifying the actual expenditures incurred in performing Buyer's Abandonment Obligations. Any disputes concerning the amount of such expenditures or their attribution to performance of Abandonment Obligations shall be resolved in accordance with Section 12.6 below.

(d) Sellers and Buyer shall jointly maintain an account of Buyer's Abandonment Obligation expenditures determined in accordance with clause (c) above. In such account, Buyer's expenditures for those Abandonment Obligations covered by the MMS Performance Bond shall be credited against the penal sum of the MMS Performance Bond. Buyer's other Abandonment Obligation expenditures shall be credited against the penal sum of Sellers' Performance Bond until an amount equal to such penal sum is attained. At any time after any calendar year in which Abandonment Obligation expenditures are credited against the penal sum under the MMS Supplemental Performance Bond under this clause (d), Buyer may require that CUSA consent to partial reduction of such penal sum in the amount of such credit, conditioned on the consent of MMS to such partial reduction. At any time after any calendar year in which Abandonment Obligation expenditures are credited against the penal sum under the Sellers' Performance Bond under this clause (d), Buyer may require that Sellers consent to partial reduction of such penal sum in the amount of such credit.

(e) Until a consent to reconveyance or surety bond termination is executed by Sellers, the performance bonds described in this Section 3.6 shall remain in full force and effect and Sellers shall have all remedies available under such instruments or applicable Laws to enforce performance of Buyer's obligations and to execute on such security in the event of any default in performance or payment of such obligations when due. Buyer waives the right to require Sellers to proceed against or exhaust any particular security or make any election of remedies.

(f) Buyer shall not sell, assign, pledge, grant a security interest in or otherwise transfer ("transfer") any interest in the real property interests included in the Transferred Properties, and Plains Resources Inc. shall not transfer any interest in any subsidiary designated to hold title to the Transferred Properties or the interests transferred hereunder in GGP, PANGL, PAPCO or PATC, without first obtaining the written consent of Sellers. Sellers shall not withhold their consent to such transfer if the transfer will meet each of the following criteria to Sellers' reasonable satisfaction:

(i) The transfer will not increase the cost or time for performance of Sellers' then remaining retained Abandonment Obligations.

(ii) The transfer will not impair the ability or likelihood of performance of Buyer's then remaining assumed Abandonment Obligations.

(iii) Sellers will continue to hold unimpaired all rights granted by Buyer in accordance with this Agreement applicable to performance of Sellers' then remaining retained Abandonment Obligations, including rights to use of emission reduction credits, rights to Clean Seas spill response commitments,

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rights as an additional insured under Buyer's insurance, and rights under the MMS Performance Bond and Sellers' Performance Bond required hereunder.

Notwithstanding the foregoing, Sellers hereby consent to Buyer's granting of security interests in the Transferred Properties to the lenders providing acquisition funding for the Closing of this Agreement and to the sureties providing the MMS Performance Bond and the Sellers' Performance Bond, and their respective successors or assigns or substitute parties (provided that Sellers' consent based on the above criteria shall be required for any execution, foreclosure, trustee sale or other transfer by or on behalf of such lenders or sureties, which would result in a party other than the lender or sureties acquiring an interest). If Sellers' consent based on the above criteria is obtained with respect to a transfer in which the transferee provides Sellers with bonds in forms and from sureties satisfying the requirements for the MMS Performance Bond and Sellers' Performance Bond hereunder, Sellers shall consent to the release of the respective bond or bonds furnished by Buyer.

ARTICLE 4

DEPOSIT AND PURCHASE PRICE

4.1 DEPOSIT. Within three Business Days after the Execution Date, Buyer shall deliver to Sellers a deposit of One Hundred Thousand Dollars ($100,000) (the "Deposit"). The Deposit shall be made in Dollars by transfer of immediately available funds to Sellers' Bank Account. Sellers need not segregate the Deposit and shall not hold the Deposit in trust. If the Closing occurs, the principal amount of the Deposit shall be credited against the Purchase Price. If the Closing does not occur, the Deposit shall be applied pursuant to Section 5.4 below. Buyer shall not be entitled to any interest on the Deposit, whether the Closing occurs or the Agreement is terminated.

4.2 PURCHASE PRICE. As consideration for the sale of the Transferred Properties and Sellers' other obligations hereunder, Buyer shall transfer the following amounts (collectively the "Purchase Price") subject to adjustment as set forth in Section 4.3 below:

(i) the Deposit shall be paid to Sellers in accordance with
Section 4.1 above;

(ii) an amount equal to One Million Thirty-Seven Thousand Five Hundred Dollars ($1,037,500) shall be paid to Sellers on the Closing Date;

(iii) an amount equal to One Million Twenty-Six Thousand Two Hundred Ninety-Four Dollars ($1,026,294) shall be paid to Sellers on the later of the Closing Date or the date on which the Application for Expenditure defined in Section 9.7 below relating to the Reconfiguration 2 Project is approved by the PAPCO and PATC partnerships; and

(iv) the estimated positive or negative total amount of the adjustments calculated by Sellers in the Settlement Estimate delivered in accordance with Section

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4.3 below, shall be credited to or debited from the amount transferred by Buyer to Sellers on the Closing Date under clause (ii) above.

All transfers to Sellers shall be paid in Dollars by transfer of immediately available funds to Sellers' Bank Account.

4.3 PURCHASE PRICE ADJUSTMENTS.

(a) MEASURED INVENTORIES. Sellers shall calculate, using records and other means of account, the value of the Hydrocarbon Inventories physically present in the PATC facilities described in Schedule 8 as of the Closing Date (the "Measured Inventories"). The estimated value of Measured Inventories shall be calculated in accordance with the Valuation Procedure attached as Schedule 9 to this Agreement. Buyer shall have the right to have their representatives audit the records used by Sellers in calculating such measurement and valuation.

(b) PAYABLES. All credits and payment obligations associated with the Transferred Properties (including accounts payable and prepayments) which have been paid by Sellers and their Affiliates or which have accrued on or before the Closing Date and which relate to liabilities that have been assumed by Buyer or for which Buyer is otherwise responsible shall be prorated to CUSA or CPL, as applicable, for the period prior to the Closing Date and to Buyer, for the period on and after the Closing Date. Sellers shall pay all such items due prior to the Closing Date and Buyer shall pay for all such items due on and after the Closing Date.

(c) RECEIVABLES. Accounts receivable or other rights to revenue associated with the Transferred Properties, to the extent that such accounts receivable and rights to revenue are attributable to transactions prior to the Closing Date, shall not be part of the sale but shall remain the property of Sellers whenever collected.

(d) TAXES. The allocation between Sellers and Buyer of responsibility for and payment of all property and excise taxes shall be made in accordance with the provisions of Article 10 below.

4.4 SETTLEMENT STATEMENT. A preliminary estimate of the value of the Measured Inventories as of the Closing Date under Section 4.3(a) above shall be calculated by Sellers and set forth in a settlement estimate (the "Settlement Estimate") delivered to Buyer not later than five (5) Business Days prior to the scheduled date for Closing. A final determination of the value of the Measured Inventories as of the Closing Date under Section 4.3(a) above shall be calculated by Sellers and set forth in a settlement statement (the "Settlement Statement") delivered to Buyer not later than 180 calendar days after the Closing. The Settlement Statement shall contain information detailing the basis for Sellers' calculations, and Buyer and its representatives shall have access to such records of Sellers as may be reasonably requested

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for verifying the measurements and calculations. If Buyer gives to Sellers written notice of dispute of any element of the Settlement Statement within 60 calendar days after receiving the Settlement Statement, (i) Sellers or Buyer, as the case may be, shall pay all undisputed amounts to the other within 75 calendar days after receiving the Settlement Statement and (ii) the disputed amount shall be negotiated between Sellers and Buyer. If such negotiations do not result in a resolution of the dispute within fifteen calendar days after Buyer's notice of dispute, the disputed amount shall be determined by one partner of an independent accounting firm jointly selected by Sellers and Buyer, whose determination shall be consistent with the provisions of this Agreement and shall be final and conclusive. The disputed amount shall be payable by the parties owing such amount within five Business Days following settlement or resolution of the dispute. Any amounts owing under the Settlement Statement shall bear interest at the Interest Rate from the Closing Date until paid.

4.5 ALLOCATION OF PURCHASE PRICE. The Purchase Price shall be allocated among the Transferred Properties potentially subject to rights of first refusal in accordance with Schedule 10 attached to this Agreement.

ARTICLE 5

CLOSING

5.1 TIME AND PLACE OF CLOSING. The consummation of the sale of the Transferred Properties and other transactions contemplated by this Agreement (the "Closing") shall be deemed to have occurred at 12:01 a.m. California time on the Closing Date. The meeting at which execution or delivery of Closing documents shall take place shall be held at the Ventura, California office of CUSA at 8:00 a.m. on the Closing Date, or such other location or date as Sellers and Buyer may mutually agree in writing.

5.2 SCHEDULED CLOSING DATE. The Closing Date is scheduled for July 1, 1999. If the conditions for Closing have not been satisfied by July 1, 1999, the Closing Date may be extended until August 20, 1999 by written notice by Sellers to Buyer given not later than July 1, 1999. Alternatively, Sellers and Buyer may mutually agree to schedule the Closing Date on a different date.

5.3 TERMINATION. If the Closing has not occurred on or before the later of (i) July 1, 1999 or (ii) the later Closing Date established by extension notice or mutual agreement in accordance with Section 5.2 above, either Sellers or Buyer, by written notice to the other, may elect to terminate their respective obligations to close the transactions contemplated by this Agreement; provided that no party may so terminate its obligations if it is then in default of any of its obligations under this Agreement.

5.4 CONSEQUENCES OF TERMINATION.

(a) No termination of this Agreement shall relieve any party hereto of any liability for any breach hereof occurring prior to such termination.

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(b) If the Closing does not occur because of material breach of Buyer's obligations and this Agreement is terminated as contemplated herein, Sellers shall retain the Deposit as liquidated damages in lieu of all other damages and as Sellers' sole remedy against Buyer for such failure to close.
THE PARTIES AGREE THAT THE AMOUNT OF THE LIQUIDATED DAMAGES IS REASONABLE CONSIDERATION FOR SELLERS' HOLDING THE TRANSFERRED PROPERTIES OFF THE MARKET FOR THE PERIOD GOVERNED BY THIS AGREEMENT, AND THAT THE EXTENT OF DAMAGES TO SELLERS OCCASIONED BY FAILURE TO CLOSE WOULD BE EXTREMELY IMPRACTICABLE TO ASCERTAIN.

(c) If the Closing does not occur because of material breach of Sellers' obligations and this Agreement is terminated as contemplated herein, Sellers shall return to Buyer the Deposit, and in addition shall reimburse to Buyer the verified expenditures incurred by Buyer in conducting due diligence reviews of the Transferred Properties and negotiating the transaction, all as liquidated damages in lieu of all other damages and as Buyer's sole remedy against Sellers for such failure to close. THE PARTIES AGREE THAT THE AMOUNT OF THE LIQUIDATED DAMAGES IS REASONABLE CONSIDERATION FOR BUYER'S COMMITMENT TO PURCHASE THE TRANSFERRED PROPERTIES, AND THAT THE EXTENT OF DAMAGES TO BUYER OCCASIONED BY FAILURE TO CLOSE WOULD BE EXTREMELY IMPRACTICABLE TO ASCERTAIN.

(d) If the Closing does not occur for reasons other than material breach of Buyer's or Sellers' obligations and this Agreement is terminated as contemplated herein, Buyer shall be entitled to the immediate return of the Deposit. In such event, the recovery of such Deposit shall be Buyer's sole remedy against Sellers arising out of this Agreement or the termination hereof.

(e) By initialing where indicated below, the parties specifically agree to this liquidated damages provision.

CUSA     __________           BUYER  __________
         (Initials)                  (Initials)
CPL      __________
         (Initials)

5.5 JOINTLY USED ASSETS. Certain of the assets, contracts and permits (designated with a "J" in the Schedules) are jointly used in ownership, use, operation, maintenance, improvement or abandonment of the Transferred Properties and the SBC/DC Properties previously transferred to Venoco and/or Ellwood ("Jointly Used Assets"). All right, title and interest in the Jointly Used Assets are currently held by Sellers subject to arrangements for shared usage with Venoco and/or Ellwood. During the period between the Execution Date and the Closing Date, Sellers shall facilitate negotiations among Sellers, Venoco, Ellwood and Buyer for mutually acceptable arrangements for shared usage of the Jointly Used Assets and determination of which party or parties will have ownership of the Jointly Used Assets. If such arrangements have not been entered into and executed five (5) calendar days prior to the Closing Date, or waiver in the sole discretion of Buyer, Buyer may terminate this Agreement and obtain a full reimbursement of its Deposit.

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ARTICLE 6

CLOSING CONDITIONS PRECEDENT

6.1 SELLERS' CLOSING CONDITIONS PRECEDENT. The obligations of Sellers to be performed at the Closing shall be subject to the satisfaction of the following conditions precedent, each of which may be waived by Sellers except as otherwise required by Law:

(a) PAYMENTS. Buyer shall make the payments required by Article 4 above to be made on or before the Closing Date.

(b) ACCURACY AND PERFORMANCE OF BUYER'S REPRESENTATIONS AND COVENANTS. The representations and warranties of Buyer contained in this Agreement shall be true and correct in all material respects both as of the Execution Date and as of the Closing Date as if made on and as of the Closing Date, except for changes permitted or contemplated by this Agreement or otherwise consented to by Sellers in writing. Each of the covenants of Buyer required by this Agreement to be performed and complied with at or prior to the Closing shall have been duly performed and validly complied with at or prior to the Closing. Sellers shall have received a certificate executed by an officer of Buyer certifying the substance of this clause (b).

(c) AUTHORIZATION OF BUYER. All corporate action necessary to authorize the execution, delivery and performance of this Agreement and the consummation of the transactions contemplated hereby shall have been duly taken by Buyer.

(d) OPINION OF BUYER'S COUNSEL. Sellers shall have received an opinion of the General Counsel of Buyer, in the form of Exhibit G attached to this Agreement.

(e) DELIVERY OF BUYER'S SECURITY AGREEMENTS. Sellers shall have received the performance bonds as required by Section 3.6 above executed and acknowledged by the sureties (and Buyer, if applicable), and, if any rights and duties under this Agreement have been assigned by Buyer to its subsidiaries as permitted by Section 12.5 below, Sellers shall have received the parent guaranty required by Section 12.5 executed and acknowledged by Plains Resources Inc., guaranteeing to Sellers performance and payment when due of such subsidiaries' obligations.

(f) ABSENCE OF RESTRAINING LITIGATION. No action or proceeding by or before any Government Authority shall have been instituted or threatened (and not subsequently dismissed, settled or otherwise terminated) which might prohibit, invalidate or materially restrain the transactions contemplated by this Agreement, other than an action or proceeding instituted or threatened by Sellers or any of their Affiliates.

(g) ASSIGNMENT AND ASSUMPTION AGREEMENTS. Buyer shall have executed and delivered to Sellers the assignment and assumption agreements with respect to the transfer of

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rights-of-way and other easements and mineral and surface leases and contract rights in the forms described in Section 2.6 above.

(h) REQUIRED CONSENTS. Sellers and Buyer shall have received all consents from the parties to the Point Arguello Unit unit agreement and the partners in each of GGP, PANGL, PAPCO and PATC necessary for Buyer to succeed to Sellers' interests as a unit owner in the Point Arguello Unit, as operator of the Point Arguello Unit, and as a partner or limited liability company member holding Sellers' interest in each of GGP, PANGL, PAPCO, PATC and Clean Seas.

(i) TRANSFER OF PARTNERSHIP INTERESTS AND CLEAN SEAS INTERESTS. Buyer shall have executed and delivered to Sellers the assignment and assumption agreements with respect to the transfer of the Partnership Interests and interests in Clean Seas to be transferred hereunder, conforming in each case to the requirements of the applicable partnership or limited liability company agreement.

(j) SERVICES AGREEMENT. Buyer shall have executed and delivered to Sellers the Services Agreement in the form of Exhibit E attached to this Agreement.

(k) VOTING AGREEMENTS. Buyer shall have executed and delivered to Sellers the Voting Agreements in the forms of Exhibit M to this Agreement.

(m) AUTHORIZATION OF SELLERS. All corporate approvals necessary to authorize the performance of this Agreement and the consummation of the transactions contemplated hereby shall have been duly taken by Sellers. Sellers shall use their commercially reasonable efforts to secure such approvals within thirty (30) calendar days after the Execution Date, and shall promptly notify Buyer in writing after successfully obtaining such approvals.

6.2 BUYER'S CLOSING CONDITIONS PRECEDENT. The obligations of Buyer to be performed at the Closing shall be subject to the satisfaction of the following conditions precedent, each of which may be waived by Buyer except as otherwise required by Law:

(a) DELIVERY OF CONVEYANCING INSTRUMENTS. Sellers shall have executed, acknowledged where applicable, and delivered to Buyer the conveyancing instruments defined in Section 2.6 above.

(b) ACCURACY AND PERFORMANCE OF SELLERS' REPRESENTATIONS AND COVENANTS. The representations and warranties of Sellers contained in this Agreement shall be true and correct in all material respects both as of the Execution Date and as of the Closing Date as if made on and as of the Closing Date, except for changes permitted or contemplated by this Agreement or otherwise consented to by Buyer in writing. Each of the covenants of Sellers required by this Agreement to be performed and complied with at or prior to the Closing shall have been duly performed and validly complied with at or prior to the Closing. Buyer shall have received a certificate executed by an officer of each of CUSA and of CPL certifying the substance of this clause (b).

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(c) AUTHORIZATION OF SELLERS. All corporate approvals necessary to authorize the execution, delivery and performance of this Agreement and the consummation of the transactions contemplated hereby shall have been duly taken by Sellers.

(d) OPINION OF SELLERS' COUNSEL. Buyer shall have received an opinion of Pillsbury Madison & Sutro LLP, legal counsel for Sellers, in the form of Exhibit H attached to this Agreement.

(e) GUARANTY AGREEMENT. Sellers shall have delivered the Guaranty Agreement executed by Chevron Corporation as required by Section 3.5 above.

(f) ABSENCE OF RESTRAINING LITIGATION. No action or proceeding by or before any Government Authority shall have been instituted or threatened (and not subsequently dismissed, settled or otherwise terminated) which might prohibit, invalidate or materially restrain the transactions contemplated by this Agreement, other than an action or proceeding instituted or threatened by Buyer or any of their Affiliates.

(g) APPROVAL DATE. Buyer shall not have given written notice of a Material Discovery to Sellers on or before the Approval Date under Section 8.1 below; provided, however, that if Buyer did timely give any such notice, and if Sellers shall have provided the undertaking in favor of Buyer to cure or indemnify Buyer against the matters identified in such notice as contemplated by Section 8.1, then this condition shall be deemed to have been satisfied.

(h) REQUIRED CONSENTS. Sellers and Buyer shall have received all consents from the parties to the Point Arguello Unit unit agreement and the partners in each of GGP, PANGL, PAPCO, PATC and Clean Seas necessary for Buyer to succeed to Sellers' interests as a unit owner in the Point Arguello Unit, as operator of the Point Arguello Unit, and as a partner or limited liability company member holding Sellers' interests in each of GGP, PANGL, PAPCO, PATC and Clean Seas.

(i) SERVICES AGREEMENT. Sellers shall have executed and delivered to Buyer the Services Agreement in the form of Exhibit E attached to this Agreement.

(j) AFFIDAVITS OF SELLERS' NON-FOREIGN STATUS. Buyer shall have received affidavits of non-foreign status of each of CUSA and CPL in the form of Exhibit I attached to this Agreement.

(k) AUTHORIZATION OF BUYER. All corporate approvals necessary to authorize the performance of this Agreement and the consummation of the transactions contemplated hereby shall have been duly taken by Buyer. Buyer shall use its commercially reasonable efforts to secure such approvals within thirty (30) calendar days after the Execution Date, and shall promptly notify Sellers in writing after successfully obtaining such approvals.

(l) JOINT USE AGREEMENT. Buyer shall have received the executed joint use agreements contemplated in Section 5.5 above.

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(m) PREFERENTIAL RIGHTS. No more than ten percent (10%) of the Purchase Price has been reduced due to the exercise by third parties of preferential rights pursuant to Section 8.5 below.

(n) UNIT OPERATORSHIP. Buyer shall have received the necessary votes or approvals to become the unit operator of the Point Arguello Unit.

(o) PARTNERSHIP SUCCESSION. Buyer shall be entitled to succeed to the general partner, managing general or operator status that CPL and CUSA enjoyed in GGP, PANGL, PAPCO and PATC.

(p) CURRENT INVENTORY LISTS. Buyer shall have received from Sellers the most current inventory lists for equipment, spare parts and similar items located at the Gaviota warehouse, stored offsite, and such other locations in the Transferred Properties and Partnerships' Facilities as Sellers regularly maintain inventory records.

ARTICLE 7

REPRESENTATIONS AND WARRANTIES

7.1 CUSA'S REPRESENTATIONS AND WARRANTIES. CUSA represents and warrants the following to Buyer with respect to the transfer of CUSA Properties and Partnership Interests of CUSA as of the Execution Date. As used herein, "to the knowledge of CUSA's management" means to the best knowledge and belief, after due inquiry within his respective area of responsibility, of George Steinbach, Vega Sankur, Steven Merritt, Gary Gray, David Patterson, Delmar Clement and Ralph Mayo.

(a) DUE INCORPORATION. CUSA is a corporation duly organized, validly existing and in good standing under the Laws of the Commonwealth of Pennsylvania. CUSA has all requisite corporate power and authority to own, lease and operate its properties and to carry on its business as now being conducted. CUSA is in good standing as a foreign corporation authorized to transact intrastate business in the State of California.

(b) DUE AUTHORIZATION. CUSA has full power and authority to enter into this Agreement and the instruments and agreements hereunder and to consummate the transactions contemplated hereby and thereby. Except for the approvals contemplated in Section 6.1(m) above, the execution, delivery and performance of this Agreement and the instruments and agreements hereunder have been duly approved, and no other corporate proceedings on the part of CUSA is necessary to authorize this Agreement, the instruments and agreements hereunder or the transactions contemplated hereby and thereby. This Agreement and the instruments and agreements hereunder have been duly and validly executed and delivered by CUSA and are enforceable in accordance with their respective terms, except as such enforceability may be limited by applicable bankruptcy, insolvency,

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moratorium, reorganization or similar laws from time to time in effect which affect creditors' rights generally and by legal and equitable limitations on the availability of specific remedies.

(c) PARTNERSHIP AUTHORITY. The GGP partnership is a California general partnership duly organized and validly existing under California law and has all requisite power to carry on its business as now being conducted, to own and operate the assets now owned and being operated by it, and has no assets and conducts no business in any state other than California.

(d) DEFAULTS. To the knowledge of CUSA's management and except as disclosed to Buyer in the Disclosure Letter, the Unit Agreements and the CUSA Applicable Contracts are in full force and effect and no royalties or other lease or contractual payments are outstanding and past due; there are no defaults by CUSA, or events that with notice or the lapse of time, or both, would constitute a default by CUSA or any other party thereto; and CUSA has not received any notice that any party to any of the Unit Agreements or the CUSA Applicable Contracts intends to terminate such agreement.

(e) NOTICES OF VIOLATION. Except as disclosed to Buyer in the Disclosure Letter, CUSA has not received between January 1, 1996 and the Execution Date in written form a notice from any Government Authority claiming violation of any Law (including any building, zoning or other ordinance) or CUSA Applicable Permits or requiring any substantial work, construction or expenditure, or asserting any tax penalty, with respect to the CUSA Properties or the Partnerships' Facilities of GGP.

(f) COMPLIANCE WITH LAWS AND PERMITS. Except as disclosed to Buyer in the Disclosure Letter and except for noncompliance matters as to which a fine or other penalty would not be applicable, to the knowledge of CUSA's management the CUSA Properties and the Partnerships' Facilities of GGP are in compliance with Laws and Applicable Permits.

(g) STRUCTURAL CONDITIONS. Except as disclosed to Buyer in the Disclosure Letter, to the knowledge of CUSA's management CUSA has not identified Structural Conditions with respect to the platforms included in the CUSA Properties.

(h) LITIGATION. Except as disclosed to Buyer in the Disclosure Letter, there are no actions, suits or other litigation, proceedings or governmental investigations pending or, to the knowledge of CUSA's management, threatened by, against or affecting CUSA, or any of its officers, directors, employees or the stockholders thereof in their capacity as such, or any of the properties or businesses of CUSA, arising out of CUSA's ownership or operation of the Transferred Properties or the Partnerships' Facilities of GGP, or which in any manner challenge or seek to prevent, enjoin, alter or delay the transactions contemplated hereby, and CUSA's management is not aware of any facts or circumstances which may give rise to any of the foregoing. Except as disclosed to Buyer in the Disclosure Letter and except for the Applicable Permits, CUSA is not subject to any order, judgment, decree, stipulation or consent of or with any court or other governmental authority which has or could have a material adverse effect.

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(i) INCLUSION OF PROPERTIES. Except for the items specifically excluded in Section 2.5(b) and Schedule 14, the Transferred Properties include all the real and personal properties owned by CUSA that are necessary for the production and transportation from the Transferred Properties of crude oil, natural gas, casinghead gas, drip gasoline, natural gasoline, natural gas liquids, condensate products and other hydrocarbons whether gaseous or liquid to the sales connection with third party carriers.

(j) ENCUMBRANCES CREATED BY CUSA. CUSA has not conveyed any right, title or interest in the Transferred Properties to any third party except as described in the Disclosure Letter or the Schedules attached hereto. All of the Transferred Properties and the Partnerships' Facilities of GGP are free and clear of mortgages, mechanics' liens, tax liens and other forms of security interests securing financial obligations of CUSA, except for those disclosed in the Disclosure Letter and Permitted Encumbrances; or, if such liens exist, they have been bonded or otherwise secured against.

(k) NO BROKERS. CUSA has not incurred any liability, contingent or otherwise, for brokers' or finders' fees relating to the transactions contemplated by this Agreement by which Buyer or any of the Transferred Properties would be liable.

7.2 CPL'S REPRESENTATIONS AND WARRANTIES. CPL represents and warrants the following to Buyer with respect to the transfer of CPL Properties and Partnership Interests of CPL as of the Execution Date. As used herein, "to the knowledge of CPL's management" means to the best knowledge and belief, after due inquiry within his respective area of responsibility, of Jerry Bowman, James Foster and Michael Orlind.

(a) DUE INCORPORATION. CPL is a corporation duly organized, validly existing and in good standing under the laws of the State of Delaware. CPL has all requisite corporate power and authority to own, lease and operate its properties and to carry on its business as now being conducted. CPL is in good standing as a foreign corporation authorized to transact intrastate business in the State of California.

(b) DUE AUTHORIZATION. CPL has full power and authority to enter into this Agreement and the instruments and agreements hereunder and to consummate the transactions contemplated hereby and thereby. Except for the approvals contemplated by Section 6.1(m) above, the execution, delivery and performance of this Agreement and the instruments and agreements hereunder have been duly approved, and no other corporate proceedings on the part of CPL are necessary to authorize this Agreement, the instruments and agreements hereunder or the transactions contemplated hereby and thereby. This Agreement and the instruments and agreements hereunder have been duly and validly executed and delivered by CPL and are enforceable in accordance with their respective terms, except as such enforceability may be limited by applicable bankruptcy, insolvency, moratorium, reorganization or similar laws from time to time in effect which affect creditors' rights generally and by legal and equitable limitations on the availability of specific remedies.

(c) PARTNERSHIP AUTHORITY. Each of the PANGL, PAPCO and PATC partnerships is a California general partnership duly organized and validly existing under California law and has all requisite power to carry on its business as now being conducted, to own and operate

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the assets now owned and being operated by it, and has no assets and conducts no business in any state other than California.

(d) DEFAULTS. To the knowledge of CPL's management and except as disclosed to Buyer in the Disclosure Letter, the CPL Applicable Contracts are in full force and effect; there are no defaults by CPL and no royalties or other lease or contractual payments are outstanding and past due, or events that with notice or the lapse of time, or both, would constitute a default by CPL or (to the knowledge of CPL's management) any other party thereto; and CPL has not received any notice that any party to any of the CPL Applicable Contracts intends to terminate such agreement.

(e) NOTICES OF VIOLATION. Except as disclosed to Buyer in the Disclosure Letter, CPL has not received between January 1, 1996 and the Execution Date in written form a notice from any Government Authority claiming any substantial violation of any Law (including any building, zoning or other ordinance) or CPL Applicable Permits, or requiring any substantial work, construction or expenditure, or asserting any tax penalty, with respect to the CPL Transferred Properties or the Partnerships' Facilities of partnerships in which CPL has an interest.

(f) COMPLIANCE WITH LAWS AND PERMITS. Except as disclosed to Buyer in the Disclosure Letter and except for noncompliance matters as to which a fine or other penalty would not be applicable, to the knowledge of CPL's management the CPL Properties and the Partnerships' Facilities of PANGL, PAPCO and PATC are in compliance with applicable Laws and Permits.

(g) LITIGATION. Except as disclosed to Buyer in the Disclosure Letter, there are no actions, suits or other litigation, proceedings or governmental investigations pending or, to the knowledge of CPL's management, threatened by, against or affecting CPL, or any of its officers, directors, employees or the stockholders thereof in their capacity as such, or any of the properties or businesses of CPL, arising out of CPL's ownership or operation of the Transferred Properties, or which in any manner challenge or seek to prevent, enjoin, alter or delay the transactions contemplated hereby, and CPL's management is not aware of any facts or circumstances which may give rise to any of the foregoing. Except as disclosed to Buyer in the Disclosure Letter, CPL is not subject to any order, judgment, decree, stipulation or consent of or with any court or other governmental authority which has or could have a substantially adverse effect.

(h) INCLUSION OF PROPERTIES. Except for the items specifically excluded in Section 2.5(b) and Schedule 14, the Transferred Properties include all the real and personal property owned by CPL that is necessary for the transportation from the oil and gas production interests included in the Transferred Properties of crude oil, natural gas, casinghead gas, drip gasoline, natural gasoline, natural gas liquids, condensate products and other hydrocarbons whether gaseous or liquid to the sales connection with third party carriers.

(i) ENCUMBRANCES CREATED BY CPL. CPL has not conveyed any right, title or interest in the Transferred Properties to any third party except as described in the Disclosure Letter or in the Schedules attached hereto. All of the Transferred Properties and the

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Partnerships' Facilities of partnerships in which CPL has an interest are free and clear of mortgages, mechanics' liens, tax liens and other forms of security interests securing financial obligations of CPL, except for those disclosed to Buyer in the Disclosure Letter and Permitted Encumbrances; or, if such liens exist, they have been bonded or secured against.

(i) NO BROKERS. CPL has not incurred any liability, contingent or otherwise, for brokers' or finders' fees relating to the transactions contemplated by this Agreement by which Buyer or any of the Transferred Properties would be liable.

7.3 BUYER'S REPRESENTATIONS AND WARRANTIES. Buyer represents and warrants the following to Sellers as of the Execution Date:

(a) DUE INCORPORATION. Each of Buyer and any subsidiary designated by it to receive assets in accordance with Section 12.5 below is a corporation duly organized, validly existing and in good standing under the laws of the State of Delaware. Each of Buyer and such subsidiaries has all requisite corporate power and authority to own, lease and operate its properties and to carry on its businesses as now being conducted. Each of Buyer and such subsidiaries is in good standing as a foreign corporation authorized to transact intrastate business in the State of California.

(b) DUE AUTHORIZATION. Each of Buyer and any subsidiary designated by it to receive assets in accordance with Section 12.5 below has full power and authority to enter into this Agreement and the instruments and agreements hereunder and to consummate the transactions contemplated hereby and thereby. Except for the approvals contemplated by Section 6.2(m), the execution, delivery and performance of this Agreement and the instruments and agreements hereunder have been duly and validly approved and no other corporate proceedings on the part of Buyer or such subsidiaries is necessary to authorize this Agreement, the instruments and agreements hereunder or the transactions contemplated hereby and thereby. This Agreement and the instruments and agreements hereunder have been duly and validly executed and delivered by Buyer and are enforceable in accordance with their respective terms, except as such enforceability may be limited by applicable bankruptcy, insolvency, moratorium, reorganization or similar laws from time to time in effect which affect creditors' rights generally and by legal and equitable limitations on the availability of specific remedies.

(c) NO BROKERS. Buyer has not incurred any liability, contingent or otherwise, for brokers' or finders' fees relating to the transactions contemplated by this Agreement by which Sellers or any of their Affiliates would be liable.

(d) FINANCIAL STATEMENTS. The audited financial statements for Buyer and its consolidated subsidiaries as of December 31, 1998 previously delivered to Sellers, including the balance sheets and the related statements of earnings and cash flows, have been prepared in accordance with generally accepted accounting principles. The unaudited financial statements for Buyer as of March 31, 1999 previously delivered to Sellers constitute the financial statements that Buyer has provided to its senior lenders in accordance with the requirements of applicable loan agreements.

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(e) FURTHER DISTRIBUTION. Buyer is acquiring their respective Partnership Interests for their own account for investment and not with a view to or for sale in connection with any distribution thereof within the meaning of the Securities Act of 1933, as amended, and the rules and regulations pertaining to such Act, or in connection with any distribution thereof in violation of any applicable state securities laws.

(f) BUYER'S BUSINESSES. Buyer is and has been during at least the preceding two years engaged primarily in the business of drilling for or producing oil or gas, transporting oil or gas and owning interests in and operating oil or gas pipelines.

(g) EXPERIENCED INVESTOR. Buyer is an experienced and knowledgeable investor in the oil and gas business. Prior to entering into this Agreement, Buyer was advised by its own legal, tax and other professional counsel concerning this Agreement, the Transferred Properties and the value thereof. Buyer is aware of the risks and uncertainties of an investment in oil and gas properties and is able to absorb a loss of its entire investment.

(h) ALLOCATIONS OF PURCHASE PRICE. The portion of the Purchase Price allocated to each property listed in Schedules 10 and 11 as being potentially subject to a right of first refusal constitutes the amount which Buyer would be willing to pay if it were only acquiring such property.

7.4 SURVIVAL. The representations and warranties of Sellers in Section 7.1 and 7.2 and the representations and warranties of Buyer in Section 7.3 shall survive the Closing of the transaction contemplated by this Agreement, but shall expire one year after the Closing except to the extent that a notice of claim under this Article 7, filed in accordance with Article 3, shall have been given to the party obligated thereunder within such one-year period.

7.5 EXCLUSIVITY OF WARRANTIES AND SPECIFIC DISCLAIMERS.

(a) Buyer acknowledges that at Closing that it will acquire the Transferred Properties on the basis of its own investigation of the physical condition of the Transferred Properties and assume the risk that adverse conditions outside the scope of Sellers' representations and warranties set forth in Section 7.1 and 7.2 may not be revealed by Buyer's own investigation. Buyer acknowledges that, EXCEPT AS EXPRESSLY PROVIDED IN THIS AGREEMENT, (i) THE TRANSFERRED PROPERTIES ARE SOLD "AS IS" AND "WITH ALL FAULTS," (ii) NO WARRANTY, EXPRESS OR IMPLIED IN FACT OR BY LAW, WHETHER OF MERCHANTABILITY, FITNESS FOR ANY PARTICULAR PURPOSE, CONDITION OR OTHERWISE, CONCERNING THE TRANSFERRED PROPERTIES HAS BEEN MADE TO BUYER, AND (iii) BUYER'S REMEDIES AGAINST SELLERS AND SELLERS' LIABILITIES TO BUYER FOR CONDITIONS ASSOCIATED WITH THE TRANSFERRED PROPERTIES ARE LIMITED TO THOSE PROVIDED IN THIS AGREEMENT.

(b) In connection with the waivers, releases and limitations of liability set forth in this Agreement, each of Buyer and Sellers expressly waives any rights under section 1542 of the California Civil Code, which provides:

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"A GENERAL RELEASE DOES NOT EXTEND TO CLAIMS WHICH THE CREDITOR DOES NOT KNOW OR SUSPECT TO EXIST IN HIS FAVOR AT THE TIME OF EXECUTING THE RELEASE WHICH IF KNOWN BY HIM MUST HAVE MATERIALLY AFFECTED HIS SETTLEMENT WITH THE DEBTOR."

(c) Without limiting (a) and (b) above, Buyer acknowledge and assume the following specific disclaimers:

(i) Buyer has made their own estimates of prospective data such as future production rates, value of exploration prospects, operating costs and abandonment liabilities based on Buyer's own abilities and skills to explore, produce, operate, and abandon these properties, and is not relying on Sellers' own estimates of such data.

(ii) Low levels of naturally occurring radioactive material ("NORM") may be present at some locations where the Transferred Properties or Partnerships' Facilities are located.

(iii) Pursuant to the California Safe Drinking Water and Toxic Enforcement Act of 1986 (Proposition 65), Buyer is on notice that detectable amounts of chemicals known to the State of California to cause cancer, birth defects and other reproductive harm may be found in, on or around the Transferred Properties and the Partnerships' Facilities.

(iv) California Health and Safety Code Section 25359.7 provides that any owner of nonresidential real property who knows, or has reasonable cause to believe, that any release of hazardous substances, as defined under California law, has come to be located on or beneath that real property shall, prior to the sale of that real property by that owner, give written notice of that condition to the buyer of that real property. Buyer acknowledges that one or more hazardous substances as defined under California law may have come to be located in or on the Transferred Properties or the Partnerships' Facilities.

(v) The Transferred Properties and the Partnerships' Facilities are or may be deemed to be within a Seismic Hazard Zone as designated under the Seismic Hazards Mapping Act (California Public Resources Code Sections 2690-2699.6).

(vi) The Transferred Properties and the Partnerships' Facilities are or may be deemed to be within an Earthquake Fault Zone as designated under the Alquist-Priolo Earthquake Fault Zoning Act (California Public Resources Code Sections 2621-2630) and the construction or development on the Transferred Properties or the Partnerships' Facilities of any structure for human occupancy may be subject to the findings of a geologic report prepared by a geologist registered in California.

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(vii) Portions of the Transferred Properties or the Partnerships' Facilities are or may be located in a "Wetland" as defined in the "Federal Manual for Determining Jurisdictional Wetland" or relevant Laws.

(viii) Portions of the Transferred Properties or the Partnerships' Facilities are or may be located in a "Flood Zone" as defined by the U.S. Federal Emergency Management Administration or other Government Authorities.

(ix) Sellers do not warrant that ownership, use, operation, maintenance, improvement or abandonment of the Transferred Properties would not infringe any patent, copyright, trademark or trade secret rights of any Person.

By initialing where indicated below, the parties specifically agree to the foregoing acknowledgements, disclaimers and releases in this Section 7.5.

CUSA           ___________              BUYER    ____________
               (Initials)                         (Initials)

CPL            ___________
               (Initials)

7.6 YEAR 2000 DISCLAIMER, RELEASE AND INDEMNITY.

(a) In addition to, and not in alteration, amendment or limitation of, any other provisions of this Agreement, Buyer expressly acknowledges and agrees that: (1) Sellers either have not assessed, or, if they have assessed, have not (or may not have or not fully have) modified, replaced or otherwise remediated, the Transferred Properties, including any components thereof or systems related thereto or embedded therein, to determine whether they are Year 2000 Compliant, as defined herein. (2) If the Transferred Properties are not operated by Sellers, Sellers are either unaware of, or have not verified any statements or representations made by the operator pertaining to, whether or not the operator has made any such assessment or taken any actions relating thereto, including modification, replacement or other remediation. (3) IF ANY OF THE TRANSFERRED PROPERTIES, INCLUDING ANY COMPONENTS THEREOF OR SYSTEMS RELATED THERETO OR EMBEDDED THEREIN, ARE NOT YEAR 2000 COMPLIANT, THEIR ABILITY TO MAINTAIN PRODUCTION OR OTHERWISE FUNCTION OR OPERATE MAY BE AFFECTED. (4) As between Buyer and Sellers, Buyer assumes, releases Sellers from, and agrees to defend, indemnify and hold Sellers harmless from and against, any and all responsibility and liability for any Losses or problems relating to or arising from the Year 2000 Compliance status of the Transferred Properties, including any components thereof or systems related thereto or embedded therein, and Sellers shall have no liability whatsoever for any Losses or problems Buyer may incur or encounter arising from or associated in any way with the Year 2000 Compliance status of the Transferred Properties, including any components thereof or systems related thereto or embedded therein. (5) Any disclosures made by Sellers as to Year 2000 Compliance (including but not limited to disclosures as to

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Sellers' or the operator's or a manufacturer's/supplier's assessments, inventories, testing, modification, replacement, etc.), whether made orally or in writing, and whether made before or after Closing, are for informational purposes only and Buyer relies and depends on and uses any and all such disclosures exclusively and entirely at its own risk and without any recourse to Sellers whatsoever. SUCH DISCLOSURES DO NOT AND SHALL NOT CREATE OR BE CONSTRUED TO CREATE ANY EXPRESS OR IMPLIED WARRANTIES ON THE PART OF SELLERS, AND ANY SUCH EXPRESS OR IMPLIED WARRANTIES ARE EXPRESSLY DISCLAIMED, INCLUDING BUT NOT LIMITED TO ANY IMPLIED WARRANTIES OF MERCHANTABILITY OR FITNESS FOR A PARTICULAR PURPOSE. This Section 7.6 and the Disclosure Letter constitute "Year 2000 Readiness Disclosures" for purposes of the Year 2000 Information and Readiness Disclosure Act of 1998. (6) "Year 2000 Compliant" means the Transferred Properties, including any components thereof or systems related thereto or embedded therein, would: (i) Correctly process date information before and after midnight, December 31, 1999. This would include accepting date input, providing date output, and performing calculations and comparisons on dates or portions of dates. Date interpretation would be correct for all valid date values within the applicable domain; (ii) Function accurately and without interruption before and after January 1, 2000 without any change in operations associated with any date change and/or the advent of the new century; (iii) Respond to two-digit input in a way that would resolve the ambiguity as to the century in a disclosed, defined, and predetermined manner. Interfacing software would make the same century assumptions when processing the two-digit years; (iv) Process the Year 2000 as a leap year; (v) Correctly handle date fields containing non-date information and correctly handle a date held in a non-date field; and (vi) Correctly process any date with a year specified as "99" and "00", regardless of other subjective meanings attached to these values.

(b) Sellers shall be responsible for funding their share (based on percentage ownership in applicable units and partnerships) of the expenditure to third-party contractors incurred by the units and partnerships in which interests are transferred under this Agreement to perform preventive and replacement work with respect to Year 2000 Compliance conditions prior to January 1, 2000, as such work requirements are detailed in the document entitled "Point Arguello Y2K Work Schedule" dated June 2, 1999 prepared by Sellers and delivered to Buyer. Sellers shall provide at no cost to Buyer the services of supervisory personnel under the Services Agreement to monitor the work of such third-party contractors, but without any warranty by Sellers as to the performance of such work. Sellers shall use their best faith efforts to achieve completion of the work requirements in accordance with the schedule defined in the June 2, 1999 document, subject to any revisions mutually agreeable to Sellers and Buyer. Buyer shall be responsible for funding the share of the units' and partnerships' expenditures allocated to the unit and partnership interests transferred hereunder for work related to Year 2000 Compliance that is not contemplated by the June 2, 1999 document and that is performed on or after the Closing Date. This allocation of the costs of preventive and replacement work shall not affect in any way the indemnifications, releases and assumptions of liabilities with respect to Year 2000 Compliance conditions set forth in Section 7.6(a) above.

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ARTICLE 8

PRE-CLOSING COVENANTS

8.1 BUYER'S DUE DILIGENCE REVIEW.

(a) "AS IS" SALE. Following the execution of this Agreement by Buyer and Sellers, Buyer and its employees, agents and consultants shall have the right and opportunity as provided in this Article 8 to enter upon the Transferred Properties and the Partnerships' Facilities and to make such inspections of the Transferred Properties and the Partnerships' Facilities and matters related thereto as Buyer and its representatives desire, all at Buyer's sole cost, risk and expense, including but not limited to all of Sellers' records and files related to the Transferred Properties or the Partnerships' Facilities. Buyer acknowledges that it is experienced in oil and gas matters generally, and in the acquisition and operation of oil and gas properties, and in making the decision to enter into this Agreement and to consummate the transactions contemplated hereby, Buyer has evaluated the merits and risks of purchasing the Transferred Properties from Sellers and have formed an opinion based solely on Buyer's own knowledge, experience, independent investigation, research and analysis of the Transferred Properties and not upon any representations or warranties by Sellers, except the express written representations of Sellers set forth in Article 7.

EXCEPT TO THE EXTENT, IF ANY, EXPRESSLY SET FORTH IN ARTICLE 7 HEREOF OR IN THE CONVEYANCES, SELLERS MAKE NO REPRESENTATIONS OR WARRANTIES AND DISCLAIM ALL LIABILITY AND RESPONSIBILITY FOR ANY REPRESENTATION, WARRANTY, STATEMENT OR INFORMATION ORALLY OR IN WRITING MADE OR COMMUNICATED TO BUYER, INCLUDING, BUT NOT LIMITED TO, ANY OPINION, INFORMATION OR ADVICE WHICH MAY HAVE BEEN PROVIDED TO BUYER BY ANY OFFICER, DIRECTOR, EMPLOYEE, AGENT, CONSULTANT OR REPRESENTATIVE OF SELLERS, ANY ENGINEER OR ENGINEER FIRM, OR ANY OTHER AGENT, CONSULTANT OR REPRESENTATIVE. IN ADDITION, BUYER ACKNOWLEDGES THAT SELLERS HAVE NOT MADE, AND SELLERS HEREBY EXPRESSLY DISCLAIM AND NEGATE, ANY IMPLIED OR EXPRESS WARRANTY OF MERCHANTABILITY, FITNESS FOR PARTICULAR PURPOSE, OR CONFORMITY TO MODELS OR SAMPLES OR MATERIALS AND ANY OTHER REPRESENTATION OR WARRANTY, EXPRESS, STATUTORY OR IMPLIED RELATING TO THE TRANSFERRED PROPERTIES. EXCEPT AS EXPRESSLY SET FORTH IN ARTICLE 7, AND WITHOUT LIMITATION ON THE DISCLAIMERS SET FORTH IN ARTICLE 7, BUYER IS ACQUIRING THE TRANSFERRED PROPERTIES IN AN "AS-IS, WHERE-IS" CONDITION WITH ALL FAULTS.

(b) DUE DILIGENCE. Subject to Section 8.2, Buyer shall have the right to conduct its own due diligence review of the Transferred Properties and the Partnerships' Facilities, the title and other public records applicable thereto, and the records made available by Sellers to Buyer pursuant to the Confidentiality Agreement with respect to (i) the quality and validity of Sellers' title to the Transferred Properties and the Partnerships' Facilities, (ii) the

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environmental condition of the Transferred Properties and the Partnerships' Facilities, (iii) the structural condition of the Transferred Properties and the Partnerships' Facilities, and (iv) confirmation that financial and operational results for 1998 and the portion of 1999 through the Approval Date are consistent with previously disclosed financial and operating information. Such due diligence shall be conducted in substantial compliance with a timetable and plan to be agreed upon in writing by Sellers and Buyer. If Buyer's examination results in a Material Discovery of Title Defects, Environmental Conditions, Structural Conditions or adverse condition revealed by the confirmation described in clause (iv) above (an "Item (iv) Condition") of the Transferred Properties and the Partnerships' Facilities, then Buyer shall have the right to bring the results of its examination and investigation to the attention of Sellers by written notice if and only if such notice is given to Sellers by the earlier of (i) 15 days prior to the scheduled Closing Date in accordance with Section 5.2 above or (ii) June 15, 1999 (the "Approval Date"). For purposes of this Section 8.1, a "Material Discovery" shall mean the discovery of Title Defects, Environmental Conditions, Structural Conditions or Item (iv) Conditions not known to Buyer as of the Execution Date, or not set forth with reasonable specificity in the data room or Disclosure Letter, which could reasonably be expected to reduce the economic value of the Transferred Properties and the Partnerships' Facilities by (or impose a liability on Buyer of) at least Fifty Thousand Dollars ($50,000) per individual Title Defect, Environmental Condition, Structural Condition or Item (iv) Condition and total at least One Hundred Thousand Dollars ($100,000) in the aggregate in order to cure or remediate such matters.

(c) RECOURSE FOR DUE DILIGENCE MATTERS. If written notice of such facts constituting a Material Discovery is given to Sellers on or before the Approval Date, the parties agree to discuss appropriate remedial actions or adjustments to this Agreement to take into account the individual Title Defects, Environmental Conditions, Structural Conditions or Item (iv) Conditions constituting such Material Discovery. If (i) Sellers receive such timely notice from Buyer and (ii) Sellers undertake to Buyer's reasonable satisfaction to cure or indemnify Buyer against the individual Title Defects, Environmental Conditions, Structural Conditions or Item (iv) Conditions constituting such Material Discovery, then the closing condition specified in Section 6.2(g) shall be deemed satisfied. If Sellers do not provide such an undertaking and the parties cannot agree on an appropriate amendment to this Agreement within 15 calendar days after such written notice is given, then Buyer shall have the right to terminate this Agreement within 10 calendar days after such written notice by giving written notice of termination to Sellers; otherwise, Buyer shall accept the Transferred Properties and the Partnerships' Facilities in their "as is" condition and the parties shall proceed with the Closing without exclusion of assets or reduction of Purchase Price.

(d) SELLERS' ADDITIONAL DISCLOSURES. Sellers may similarly conduct such examination or investigation as it may choose with respect to the Transferred Properties and should it determine that a matter exists which should have been disclosed in any of the schedules or in any other written disclosure made prior to the execution of this Agreement, it shall add such matter (any matter so added being called a "Sellers Defect") to the appropriate schedule or disclosure by giving written notice of such addition to Buyer promptly after Sellers' discovery thereof but in no event less than 15 calendar days prior to the Closing Date, and for the purposes of Sellers' representations and warranties, each such Sellers Defect shall be deemed to have been disclosed on such schedule or disclosure on the Execution Date. If

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any such Sellers Defect is a Title Defect, Environmental Condition, Structural Condition or Item (iv) Condition that would result in or be part of a Material Discovery, Buyer shall have the right to include the Sellers Defect in a notice of Material Discovery given to Sellers within 10 calendar days after Buyer is notified of the Sellers Defect.

8.2 BUYER'S RIGHT TO ENTER.

(a) As contemplated to facilitate Buyer's due diligence review under
Section 8.1 above, Sellers hereby grant to Buyer and its representatives the right at Buyer's sole risk to enter onto the Transferred Properties from time to time upon reasonable notice to Sellers, for the purposes of inspection of the Transferred Properties, including both internal and external inspection, evaluation and appraisal of such facilities. If Buyer plans to perform any excavation, take soil samples, or conduct other activities on the Transferred Properties which may affect Sellers' operations, Buyer shall provide Sellers with written notification of such plans and shall obtain Sellers' written approval and all necessary approvals from Government Authorities prior to conducting any such activities. Buyer shall restore the Transferred Properties to their condition existing prior to Buyer's operations or activities upon the Transferred Properties pursuant hereto, including repairs or maintenance as such are required as a result of Buyer's operations or activities. When and as reasonably requested by Buyer, Sellers shall endeavor to secure comparable rights for Buyer to enter onto and to conduct due diligence activities with respect to the Partnerships' Facilities, on terms and conditions protecting the partnerships and their partners (including Sellers) comparable to those set forth in this Article 8.

(b) Buyer shall obtain and maintain at a minimum the following types and amounts of insurance with respect to the exercise by Buyer and its representatives of the rights granted in this Section 8.2:

(i) comprehensive public liability and property damage insurance with limits of not less than $2,000,000 combined single limit per occurrence;

(ii) automobile, aircraft and watercraft liability insurance with a $2,000,000 limit;

(iii) workers' compensation insurance with limits as required by law; and

(iv) employer's liability insurance with a $2,000,000 limit.

Prior to any exercise of the rights granted hereby, Buyer shall furnish to Sellers a certificate evidencing the existence of the insurance required hereunder, confirming that the insurance:

(v) is obtained from and maintained with an insurer acceptable to Sellers;

(vi) covers Buyer's obligations under the indemnity provisions of this Agreement;

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(vii) names Chevron Corporation and its Affiliates as additional insureds (or, in the case of workers' compensation insurance, provides a waiver of subrogation to any rights against Chevron Corporation and its Affiliates); and

(viii) contains a provision pursuant to which the insurer agrees not to cancel or modify the insurance coverage without furnishing at least thirty (30) days' prior written notice to Sellers.

(c) Buyer waives and releases all claims against Chevron Corporation and its Affiliates, and their directors, officers, employees and agents, for injury to or death of any persons or damage to property arising in any way from the exercise of rights granted to Buyer by this Section 8.2 or the activities performed pursuant to this Section 8.2 by Buyer or its representatives on the Transferred Properties and the Partnerships' Facilities.

(d) Buyer shall release, defend, indemnify and hold harmless Chevron Corporation and its Affiliates, and their directors, officers, employees and agents, from and against any and all Losses arising out of (i) any and all statutory or common law liens or other encumbrances for labor or materials furnished in connection with such rights granted hereunder, including but not limited to samplings, studies or surveys that Buyer may conduct with respect to the Transferred Properties pursuant to this Section, or (ii) any injury to or death of persons or damage to property occurring in, on or about the Transferred Properties as a result of such exercise of the rights granted hereunder or activities conducted pursuant to this Section 8.2. Such indemnity shall apply whether or not an indemnitee was or is claimed to be passively, concurrently, or actively negligent, and regardless of whether liability without fault is imposed or sought to be imposed on one or more of the indemnitees. This indemnity shall not apply to the extent that it is void or otherwise unenforceable under applicable law in effect on or validly retroactive to the execution date of this Agreement and shall not apply where such loss, cost, damage, injury, liability or claim is the result of the sole negligence or willful misconduct of any indemnitee.

(e) Buyer agrees not to permit its activities permitted by this Section to unreasonably interfere with the business and operations of the Transferred Properties, and agrees that such inspections and all such documents shall be subject to the Confidentiality Agreement. Such activities shall also be conducted in compliance with Laws and Sellers' reasonable safety regulations.

8.3 OPERATION OF TRANSFERRED PROPERTIES PRIOR TO CLOSING.

(a) Sellers shall promptly notify Buyer of any casualty to the Transferred Properties or the Partnerships' Facilities, or any eminent domain or other condemnation proceeding commenced with respect to such properties, between the Execution Date and the Closing. If any such Losses relate to or may result in the loss of any material portion of the Transferred Properties or the Partnerships' Facilities ("material" for purposes of this Section 8.3 shall mean a net loss incurred by or allocated to Sellers' interest in excess of $500,000), either Sellers or Buyer may, at their option, elect to terminate this Agreement by written notice to the other parties given within 15 calendar days after becoming aware of such

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casualty or condemnation proceeding, in which event Sellers shall refund the Deposit as provided in Article 4, and none of the parties shall have any further rights or obligations hereunder. If no such notice of termination is timely given, the Agreement shall continue in effect, and upon the Closing, Buyer shall be entitled to any property insurance proceeds, compensation, awards, or other payments or relief resulting from such casualty or condemnation proceeding (other than proceeds or other relief expended by Sellers in remedying the casualty).

(b) Except as otherwise provided herein, Sellers will not, without the prior written approval of Buyer, sell, transfer or abandon any portion of the Transferred Properties belonging to them other than the sale, transfer or abandonment in the ordinary course of the operations consistent with past practices of (i) Hydrocarbon Inventories of any value or (ii) other items having a per item fair market value of less than Twenty-Five Thousand Dollars ($25,000) of materials, supplies, spare parts, inventories, furniture, motor vehicles, rolling stock, tools, implements, appliances, machinery, equipment, improvements or other tangible personal property or fixtures forming a part of the Transferred Properties.

(c) Sellers shall use commercially reasonable efforts to cause the PAPCO, PANGL, PATC and GGP partnerships to distribute to their partners, including Sellers, prior to Closing, any cash that is not necessary for the ordinary course of business funding requirements of the applicable entity. Such cash shall be allocated between Sellers and Buyer in accordance with
Section 2.4 above.

8.4 ANNOUNCEMENTS. Except for disclosures that Sellers or Buyer reasonably believe are required by Law or any securities exchange to which Sellers or Buyer may be subject, neither Sellers nor Buyer shall issue any press release or otherwise make any public announcement on or prior to the Closing Date with respect to this transaction without the prior written consent of the other parties, which shall not be unreasonably withheld or delayed.

8.5 REQUIREMENTS FOR TRANSFER OF TRANSFERRED PROPERTIES.

(a) RIGHTS OF FIRST REFUSAL. Certain of the Transferred Properties, identified in Schedules 10 and 11 attached to this Agreement, are potentially subject to rights of first refusal. Sellers and Buyer have in good faith allocated the Purchase Price among the Transferred Properties potentially subject to such rights of first refusal in Schedule 10 attached to this Agreement. Sellers and Buyer shall cooperate and shall promptly undertake such action as may be required to satisfy obligations under any rights of first refusal with respect to the Transferred Properties; provided that neither Sellers nor Buyer shall be required to pay any additional consideration beyond that contemplated (if any is contemplated) by the terms of such rights. If a third party shall properly exercise any such right, the Transferred Properties shall be excluded from the sale to Buyer hereunder and the Purchase Price reduced by the consideration received by Sellers from the third party in exercise of such right; provided, however, that should the Purchase Price be reduced more than ten percent (10%) due to the exercise of such rights of first refusal, Buyer may terminate this Agreement and receive a full reimbursement of its Deposit.

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(b) TRANSFER OF APPLICABLE CONTRACTS. At and effective as of the Closing, Sellers shall assign all their rights and delegate performance of all their duties to Buyer under the contracts included in the Applicable Contracts as described in Schedule 5, and Buyer shall assume and agree to perform all duties of Sellers under each such contract. Without limitation, this assumption by Buyer includes their assumption of any termination charges associated with a termination of any such contract made after the Closing. Notwithstanding the foregoing, if any contract provides that any notice to or consent by any third party is required as a condition of assignment, such contract shall not be assigned until and unless such requirements shall have been satisfied. Buyer and Sellers shall use their commercially reasonable efforts, each as to matters within its control, to satisfy such requirements as of the Closing Date. If any such requirement is not satisfied as of the Closing and the Closing occurs, Sellers and Buyer shall consider whether to exclude the affected contracts from the transfer hereunder or to enter into alternative arrangements with each other or with third parties, but in no event shall the Purchase Price be adjusted in respect of exclusion of any contract.

(c) TRANSFER OF APPLICABLE PERMITS. Buyer and Sellers shall use their commercially reasonable efforts, each as to matters within its control, to obtain all regulatory approvals, including the Applicable Permits as described in Schedule 6, to be transferred or reissued in favor of Buyer as soon as practicable following the Closing Date and, if possible, during the four-month transition period under the Services Agreement. If the transfer or reissuance of regulatory approvals in favor of Plains has not been obtained or is not reasonably likely to be obtained within such time period, Chevron and Plains shall make alternative arrangements for operatorship that shall be sufficient to ensure that ongoing operational services and responsibilities are transferred to the fullest extent permitted by law. Such alternative arrangements may include, but are not limited to, (i) transfer of the applicable regulatory approvals to a party mutually acceptable to Chevron, Plains, the applicable unit or partnership and regulatory agencies, or (ii) Chevron's and Plains's entering into an agency or contractor relationship in which Chevron remains the named operator or permittee of record. Notwithstanding the continuation of Chevron as a named operator or permittee of record, for purposes of the applicable Unit and Partnership Agreements, Plains shall be recognized as the duly designated operator and manager of the unit and partnership facilities.

(d) TRANSFER OF CONTRACTS AND PERMITS TO PARTNERSHIPS AND SUCCESSOR OPERATORS. Certain additional contracts and permits identified in Schedule 7 attached to this Agreement have been issued in the name of CUSA or CPL but are associated with assets or operations now owned or conducted by PANGL, PAPCO, PATC or GGP. Such contracts and permits are not to be transferred to Buyer, but Sellers and Buyer shall use their commercially reasonable efforts, each as to matters within its control, to cause such contracts and permits to be transferred or reissued in favor of the applicable partnership or successor operator. Notwithstanding the foregoing, if any contract or permit provides that any notice to or consent by any Government Authority is required as a condition of assignment, such contract or permit shall not be assigned until and unless such requirements shall have been satisfied. Sellers and Buyer shall use their commercially reasonable efforts, each as to matters within its control, to satisfy such requirements as soon as reasonably practicable following the Closing, during the transition period in which Sellers continue as permittee or operator of record under the Services Agreement.

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(e) COSTS OF TRANSFER OF APPLICABLE PERMITS. Buyer shall bear all costs and expenses incurred in connection with the transfer, amendment, reissuance or issuance of Applicable Permits to Buyer. Buyer, at its sole expense, shall provide bonds or other security as may be required by Government Authorities for the transfer or reissuance of the Applicable Permits to Buyer. These bonds or other security shall be independent of the security furnished by Buyer to Sellers under Section 3.6. Sellers shall bear all costs and expenses incurred in the transfer, amendment, reissuance or issuance of the contracts and permits identified in Schedule 7 to the applicable partnerships.

(f) ADMISSION TO PARTNER OR MEMBER STATUS. It is understood that the transfer of the Partnership Interests or the interests in Clean Seas does not automatically result in Buyer's being admitted to partner status under the terms of the applicable partnership or limited liability company agreements. Sellers and Buyer shall use their commercially reasonable efforts, each as to matters within its control, to cause Buyer to be admitted to partner status under each such partnership or limited liability company agreement effective as of the Closing Date.

(g) UNIT OPERATORSHIP. CUSA is the current operator of the Point Arguello Unit pursuant to the applicable unit operating agreements identified in Part B of Schedule 2. Sellers and Buyer shall use their commercially reasonable efforts, each as to matters within its control, to cause Buyer to be designated as the successor operator for such unit effective as of the Closing Date.

(h) MANAGING PARTNER AND OPERATOR SUCCESSION. CPL is the current managing general partner of PATC, and the managing general partner and operator of PAPCO and PANGL, and CUSA is the current managing general partner and operator of GGP pursuant to the applicable partnership agreements and management services agreements between each partnership and CPL or CUSA. Sellers and Buyer shall use their commercially reasonable efforts, each as to matters within its control, to cause Buyer to be designated as the successor managing general partner and operator for each such partnership effective as of the Closing Date.

8.6 OTHER GOVERNMENT AUTHORITY REVIEWS AND APPROVALS.

(a) PRE-MERGER NOTIFICATION. The consummation of the transactions contemplated by this Agreement may be subject to the premerger notification requirements of Section 7A of the Clayton Act (15 U.S.C. Section 18a) as enacted by the Hart-Scott-Rodino Antitrust Improvements Act of 1976. Sellers and Buyer shall cooperate and promptly undertake all filings and other actions as may be required to comply with such requirements. Should the reviewing agency advise any party of its need for additional information, that party, with the cooperation of the other parties if appropriate, shall promptly respond to the reviewing agency's request. Should the reviewing agency or another interested governmental agency advise any party of its opposition to the transactions contemplated herein, the parties shall diligently endeavor to persuade the agency concerned to abandon its opposition and, failing to do so, the parties shall take such additional action as they may agree.

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(b) TARIFFS FILED WITH FERC. Certain of the Transferred Properties being conveyed hereunder are operated as a common carrier pipeline system subject to tariffs filed with the Federal Energy Regulatory Commission ("FERC") identified in Schedule 13. Buyer shall adopt such FERC tariffs as of the Closing or, upon notification by Buyer, Sellers shall withdraw such tariffs as Buyer may designate.

(c) CHANGE OF OPERATOR. To the extent that Buyer is designated and approved as operator of any of the Transferred Properties, Buyer shall promptly and diligently make all necessary filings and satisfy all necessary requirements with the MMS and any other appropriate Government Authorities in order to transfer operations of such Transferred Properties from Sellers to Buyer.

ARTICLE 9

POST-CLOSING COVENANTS

9.1 TERMINATION OF RIGHTS TO SELLERS' INSURANCE.

(a) Sellers and Buyer acknowledge that Chevron Corporation has maintained worldwide programs of property and liability insurance coverage for itself and its Affiliates, including with respect to the Partnership Interests owned by its Affiliates and the other Transferred Properties. Such programs have been designed to achieve a cost-effective, coordinated risk-management package for the entire corporate group. All of the insurance policies through which such worldwide programs of coverage are presently or have previously been provided are herein called the "Chevron Corporation Policies."

(b) It is the understanding and intention of Sellers and Buyer that:

(i) from and after the Closing, no insurance coverage shall be provided for Buyer under the Chevron Corporation Policies relating to the Transferred Properties; and

(ii) from and after the Closing, no claims regarding any matter whatsoever, whether or not arising from events occurring prior to the Closing, shall be made against or with respect to the Chevron Corporation Policies by Buyer.

(c) Buyer, on behalf of itself and its successors and assigns, hereby releases, to the extent permitted by applicable Law, Sellers and their Affiliates from any claim made after the Closing against or with respect to any of the Chevron Corporation Policies by or through Buyer (except for Buyer's entitlement to proceeds of insurance with respect to casualties as provided in
Section 8.3(a)).

(d) Nothing contained in the foregoing provision of this Section 9.1 shall in any

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way limit, impair or constitute a release or discharge of any right of Buyer or obligation of Sellers with respect to any representation, warranty, covenant, agreement, indemnity or other obligation of Sellers contained in this Agreement (regardless of whether the same was, is or may be covered by any insurance described herein), all of which rights and obligations shall continue in full force and effect.

9.2 BUYER'S INSURANCE. Prior to the Closing Date, Buyer shall purchase and shall thereafter maintain in full force and effect Commercial General Liability Insurance (Claims Made Basis) including, but not limited to, pollution liability coverage for sudden and accidental leaks or spills covering Buyer's ownership and operation of the Transferred Properties (including Sellers' obligations under any Applicable Permit pertaining to the Transferred Properties and any liability of Seller as a result of being named on or the holder of such Applicable Permit) of $250,000,000 per accident or occurrence with a policy aggregate totaling $250,000,000 onshore and offshore, with a deductible not in excess of $1,000,000, from insurance carriers having a claims payment rating of A or better from Standard & Poor's, and having an endorsement naming Sellers as the additional insureds with severability of interest clause (cross liability) and waiving subrogation against Sellers, which shall be primary as to any other existing, valid and collectible insurance, self-insurance or fronting policy of insurance of Buyer and/or Sellers or their Affiliates. Such insurance shall specifically provide that covered liabilities include those indemnities and other obligations assumed by Buyer pursuant to Article 3 above. Such insurance shall specifically provide that the insurer agrees not to cancel or materially reduce the insurance coverage without furnishing at least thirty (30) days' prior written notice to Sellers. Such insurance is to remain in effect until all necessary federal, state or local agencies and contract parties have approved the completion of all Abandonment Obligations assumed by Buyer hereunder. Such insurance in no way limits Buyer's obligation with respect to any claim, damage or loss resulting from Buyer's ownership and operation of the Transferred Properties, oil spills, abandonment of wells, facilities and remediation of the surface, subsurface and waters as required herein or Buyer's obligations and agreements (including indemnity obligations) under any provision of this Agreement.

9.3 REMOVAL OF PROPRIETARY TECHNICAL INFORMATION. Except as provided in any third party license included in the Transferred Properties, Sellers may remove all proprietary technical information in written form that is owned by a third party (or is not in use or has not been in use within one (1) year prior to Closing) at the Transferred Properties or that is proprietary to Sellers or their Affiliates. Schedule 14 identifies the items containing such proprietary technical information as of the Execution Date.

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9.4 REPLACEMENT OF SELLERS' IDENTIFICATION. Buyer shall, at its own expense and in a timely manner not exceeding three months after the Closing, remove or cause to be removed all signs and placards which identify Sellers as prior owner or operator of each of the Transferred Properties, including any usage of trademarks or trade names of Sellers and their Affiliates. Buyer shall, at its own expense and in a timely manner not to exceed one week after the Closing, erect or install signs and placards as may be required by state or other governmental agencies identifying Buyer as the owner and/or operator of each of the Transferred Properties.

9.5 ACCESS BY SELLERS AFTER CLOSING. In the event of Closing, Buyer shall grant to Sellers a right of entry to the Transferred Properties to perform retained Abandonment Obligations at Sellers' sole cost, risk and expense, if Sellers, in their sole discretion, determine that such action is necessary to reduce alleged future liabilities of Sellers. Sellers agree to indemnify, hold harmless, and defend Buyer from and against all loss, liability, claims, fines, expenses, costs (including attorneys' fees and expenses), and causes of action caused by or arising out of Sellers' use of the right of entry granted hereby and/or Sellers' performance of retained Abandonment Obligations hereunder. Any such entry or action on the Transferred Properties by Sellers shall not be construed as an admission of responsibility by Sellers, nor shall Sellers' action lessen or reduce Buyer's responsibility for liability. A perpetual right of entry for retained Abandonment Obligations shall be incorporated in the final documents transferring title to Buyer. Promptly after all Abandonment Obligations allocated to Sellers have been completed, Sellers shall execute, acknowledge and deliver such documents as Buyer may reasonably request to terminate such rights of entry.

9.6 ABANDONMENT PROJECT PERMITTING, PLANNING AND EXECUTION SERVICES. Effective on the Closing Date, Sellers and Buyer shall each perform certain project permitting, planning and execution services as described in Schedule 13 attached to this Agreement.

9.7 SERVICES AGREEMENT. Effective on the Closing Date, Sellers and Buyer shall enter into a Services Agreement for (a) the provision of administrative and operational services by Sellers and their Affiliates to Buyer during a transition period not exceeding four months commencing on the Closing Date (provided that Sellers' Y2K supervisory services shall be provided for the full duration of the Y2K work program described in Section 7.6(b) above), and
(b) the provision of project management services by Sellers to Buyer with respect to the Reconfiguration 2 Project defined in the letter dated April 29, 1999 from Sellers to the PAPCO and PATC partners attaching a proposed Application for Expenditure, effective when an Application for Expenditure relating to such project is approved by the PAPCO and PATC partnerships. The Services Agreement shall be substantially in the form of Exhibit E attached hereto. Sellers and Buyer shall negotiate mutually satisfactory definitions of the transition services and Reconfiguration 2 Project services, and the compensation applicable to such services, promptly following the Execution Date and in any event prior to the Closing Date. In connection with CUSA's performance of transition services, CUSA will not terminate its retained Point Arguello Unit Contract Personnel Agreement (the "Texaco Personnel Agreement") dated as of October 1, 1996 with Texaco Exploration and Production, Inc. ("Texaco") until CUSA's operatorship of Platform Harvest is transferred to Buyer or until the end of the transition period under the Services Agreement, whichever occurs earlier.

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ARTICLE 10

TAXES

10.1 TRANSFER TAXES. Any recording fees, transfer taxes and other charges imposed on the conveyance of the Transferred Properties by any governmental body shall be paid by Buyer or reimbursed to Sellers by Buyer in accordance with the Law or Government Authority levying such tax or fee.

10.2 PROPERTY AND EXCISE TAXES.

(a) All real estate, occupation, ad valorem, personal property taxes and charges (e.g., direct assessments) on any of the Transferred Properties shall be prorated as of the Closing Date. Sellers shall pay all such items for all periods prior to such date and shall be entitled to all refunds and rebates with regard to such periods. Sellers shall be responsible for all oil and gas production taxes and any other similar taxes applicable to oil and gas production occurring prior to the Closing Date and Buyer shall be responsible for all such taxes applicable to oil and gas production occurring on and after the Closing Date.

(b) Buyer shall be responsible for all sales, use and similar taxes arising out of the sale of the Transferred Properties. At the Closing Date, Buyer shall pay Sellers all state and local sales or use taxes determined by Buyer's independent accounting firm, PricewaterhouseCoopers LLP, to be applicable, and Sellers shall remit such amount to the appropriate taxing authority in accordance with applicable law, provided, however, that if Buyer hold a direct payment permit which is valid on the Closing Date, Buyer shall assume all responsibility for remitting to the appropriate taxing authority the state and local sales and use taxes due and shall provide Sellers with any exemption certificates or other documentation required under applicable Law in lieu of paying Sellers the taxes due. Buyer shall hold harmless and shall indemnify Sellers for any sales or use taxes assessed against Sellers by any taxing authority in respect of this sale including the amounts of any penalties, interest and attorney's fees.

(c) In the event that the transferor or transferee of any of the Transferred Properties receives a notice of liability for additional taxes or charges (the party receiving such notice of liability will hereafter be referred to as the liable party) which are assessed upon or levied against any of the Transferred Properties after the Closing Date with respect to any period for which the liable party is not responsible for payment under the above terms then the other party (being the transferee or transferor, respectively) (hereafter referred to as the responsible party) after receiving such notice of liability shall have the option of either:

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(i) Paying the tax directly, including payment under protest to preserve the right to contest the liability, or

(ii) Challenging the liability asserted in such notice, taking all action necessary and incident to such challenge. If the responsible party elects to challenge the validity of such bill or any portion thereof, the liable party shall extend reasonable cooperation to the responsible party in such efforts at no expense to the responsible party.

Notwithstanding the foregoing, the liable party may elect to pay such notice of liability; however, the responsible party will not have to reimburse such payment unless the responsible party has consented to that payment and reimbursement and the responsible party's right to contest such liability is preserved.

(d) Should this purchase and sale constitute an isolated or occasional sale and not be subject to sales or use tax with any of the taxing authorities having jurisdiction over this transaction, no sales tax will be collected by Sellers from Buyer at the Closing Date. Sellers agree to cooperate with Buyer in demonstrating that the requirements for an isolated or occasional sale or any other sales tax exemption have been met.

10.3 PARTNERSHIPS AND PARTNERSHIP INTERESTS. Sellers shall be responsible for the discharge of all notice requirements contained in the partnership agreements related to the transferred partnership interests. These responsibilities include notifying the Tax Matters Partner or equivalent person regarding the change of ownership of the partnership interest. Sellers will provide any relevant documentation requested by the Tax Matters Partner.

10.4 REFUNDS. Other than taxes covered in Section 10.2, Sellers shall be entitled to any refund of taxes (associated with operations related to the assets and entities subject to this agreement) paid by Sellers to any governmental entity. Other than taxes covered in Section 10.2, Buyer shall be entitled to any refund of taxes (associated with operations related to the assets and entities subject to this agreement) paid by Buyer to any governmental entity. The party receiving a refund shall make a good faith effort to ascertain the source of the refund and to resolve by mutual consent the ownership of any refunds related to the subject properties.

10.5 COMPLIANCE AND CONTESTS. Subject to the reimbursement of reasonable out-of-pocket expenses, the parties hereto will provide each other such records and assistance as may be reasonably requested by any of them in connection with the preparation of any tax return, and audit or other examination by any taxing authority, and any judicial and administrative proceedings related to the liability for taxes (including without limitation, any additions to or refund of taxes).

ARTICLE 11

[INTENTIONALLY OMITTED]

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ARTICLE 12

GENERAL TERMS

12.1 COSTS AND EXPENSES. Buyer shall pay the cost of title insurance if they desire to acquire title insurance. In addition, Buyer shall pay all filing fees, costs of assignments of Applicable Contracts and Applicable Permits and costs of recording required in connection with the Closing. Each party shall pay its own attorneys' fees related to the preparation and execution of this Agreement.

12.2 BULK TRANSFER LAW. Buyer waives compliance with the provisions of any applicable bulk sales or bulk transfers Law. Sellers shall indemnify and hold Buyer harmless from any claims, loss or liability incurred by Buyer as a result of the failure to so comply; provided, however, such indemnity shall not apply to obligations and liabilities assumed by Buyer.

12.3 FURTHER ASSURANCES. Sellers and Buyer will cause to be executed and delivered from time to time at the request of the other parties all such further instruments of conveyance, assignments and further assurances as reasonably may be required to transfer and assign the Sellers' interest in the Transferred Properties or otherwise to implement the provisions and intent of this Agreement.

12.4 NOTICES. All notices and other communications required or permitted to be given or delivered hereunder shall be in writing and shall be delivered personally, transmitted by facsimile with answerback confirmed or sent by recognized overnight courier service or United States mail, postage prepaid and return receipt requested, directed to the party intended at the address set forth below, or at such other address as may be designated by such party by notice given to the other party in the manner aforesaid, and shall be effective upon receipt:

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If to Sellers:                          If to Buyer:

Chevron U.S.A. Production Company       Plains Resources Inc.
1301 McKinney Street                    One Allen Center
Houston, Texas 77002                    500 Dallas Street, Suite 700
Attention:  Ms. Melody Meyer            Houston, Texas 77010
Facsimile:  (713) 754-3088              Attention:  Mr. W. C. Egg, Jr.,
                                                Executive Vice President
                                        Facsimile: (713) 654-4915

With a copy to:

Chevron Pipe Line Company
1400 Woodloch Forest Drive
The Woodlands, Texas  77380
Attention:  Mr. Dave Rogers
Facsimile:  (281) 363-7214

12.5 ASSIGNMENT. Buyer shall not assign any right granted them under this Agreement or delegate performance of any duty to be performed by them hereunder without the express written consent of Sellers, which consent shall not be unreasonably withheld. Subject to the foregoing, all rights and duties of each party hereunder shall inure to the benefit of and be binding upon its successors and assigns. Notwithstanding the foregoing, Buyer shall have the right, prior to the Approval Date and effective on notice given to Sellers, to designate one or more of its wholly-owned subsidiaries, or Plains All American Pipeline, L.P. or its affiliated partnerships, to receive all or designated portions of the Transferred Properties and interests in GGP, PANGL, PAPCO, PATC and Clean Seas to be transferred at the Closing Date, PROVIDED that at the Closing Buyer shall furnish Sellers with (i) a Guaranty Agreement in substantially the form of Exhibit J attached hereto executed by Plains Resources Inc. in favor of Sellers, guaranteeing full payment and performance when due of any obligations hereunder assumed by such subsidiaries, and (ii) certificates by officers of such designated subsidiaries certifying the accuracy of the matters required to be certified by Buyer under Article 7 above and evidencing each such subsidiary's assumption of the duties of Buyer under this Agreement associated with the Transferred Properties and partnership or limited liability company interests to be transferred to such subsidiary; and PROVIDED FURTHER that Buyer shall be solely responsible for securing any consents required from unit members, partners or Government Authorities for designation of such subsidiaries as owners, partners or operators of the applicable units and partnerships.

12.6 GOVERNING LAW AND DISPUTE RESOLUTION.

(a) The interpretation and enforcement of this Agreement, and any arbitration and arbitral decision pursuant to subparagraph (c) below, shall be governed by the substantive law of the State of California, without the application of its conflict of law rules; provided, however, questions concerning arbitrability under the dispute resolution provision hereof shall be governed exclusively by the United States Arbitration Act.

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(b) Should any party hereto institute any arbitration or court proceeding permitted under this Section 12.6 to enforce any provision hereof or for damages by reason of the breach, default or liability of the other party arising out of any provision of this Agreement or otherwise, the prevailing party (as determined by the arbitral panel or court) shall be entitled to recover costs of the arbitration or court proceeding and reasonable attorneys' fees to be fixed by the arbitral panel or court.

(c) The parties desire to avoid all forms of traditional litigation and therefore agree that all disputes, controversies or claims arising out of or relating to this Agreement (collectively "Disputes") shall be resolved in accordance with the following procedures:

(i) The parties shall use all commercially reasonable efforts to resolve Disputes through direct discussions. The management of each party commits itself to respond promptly to any communications concerning Disputes.

(ii) Within thirty (30) days of written notice that there is a Dispute, representatives of the parties with authority to settle the matter shall meet at a mutually acceptable time and place in San Francisco, California, or such other location as may be agreed, and as often thereafter as they deem reasonably necessary in an effort to reach an amicable resolution. If a negotiator intends to be accompanied at a meeting by an attorney, the other negotiator shall be given at least three (3) Business Days' notice of such intention and may also be accompanied by an attorney.

(iii) If no amicable resolution is reached as a result of the procedure in subparagraph (ii) hereof,

(A) Within sixty (60) days of the written notice referenced in subparagraph (ii), the parties shall exchange written statements of their positions concerning the Dispute, and thereafter shall participate in a final meeting for the purpose of attempting to settle such Dispute. Each party's written statement of position shall state whether the party desires to present live witnesses (and, if so, who) at the next meeting to resolve the Dispute (described hereinafter);

(B) Within three (3) weeks of the exchange of written statements, the parties represented by the respective presidents or vice presidents of Sellers and Buyer and with the assistance of such counsel, experts and others as may be appropriate, shall meet and again attempt to reach an amicable resolution or settlement of the Dispute.

(iv) If no amicable resolution or settlement is reached as a result of the procedures in subparagraph (i), (ii) or (iii) herein, the Dispute shall be finally resolved through binding arbitration which shall be conducted expeditiously. The parties and arbitration panel shall endeavor to complete the arbitration process within one hundred twenty (120) days of the conclusion of the procedures set forth in paragraph (iii) hereof. Unless otherwise agreed to by the parties, such arbitration shall be conducted in accordance with the Center for Public Resources ("CPR") Rules of Non-Administered

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Arbitration of Business Disputes (the "CPR Rules"), with Sellers collectively being considered one "party" and Buyer and any of its subsidiaries collectively being considered one "party" for purposes of the CPR Rules. A panel of three (3) arbitrators shall be selected in accordance with the CPR Rules, provided that if the parties fail to select three arbitrators from one or more panels submitted by CPR, CPR shall not have the power to make appointments but shall continue to submit additional panels until all three arbitrators have been selected.
Unless the parties agree otherwise, the place of arbitration shall be San Francisco, California. The arbitrators shall not be empowered to award any form of exemplary or punitive damages. As part of any arbitral award pursuant to this paragraph, the arbitrators shall render a reasoned award. The parties consent to judgment on such award being entered in any court having jurisdiction.

(d) All negotiations, discussions and documents pursuant to or in furtherance of this dispute resolution are confidential and shall be treated as compromise and settlement negotiations for purposes of the Federal Rules of Evidence and state rules of evidence.

(e) Each party is required to continue to perform its obligations under this Agreement pending final resolution of any Dispute.

(f) Any judicial proceedings permitted to be brought with respect to this Agreement shall be brought in any state or federal court of competent jurisdiction in the State of California, and the parties generally and unconditionally accept the exclusive jurisdiction of such courts. The parties waive, to the fullest extent permitted by applicable law, any objection which they may now or hereafter have to the bringing of any such action or proceeding in such jurisdiction.

BINDING ARBITRATION

NOTICE: BY INITIALING IN THE SPACE PROVIDED BELOW YOU ARE AGREEING TO HAVE ANY DISPUTE ARISING OUT OF THE MATTERS INCLUDED IN THE "GOVERNING LAW AND DISPUTE RESOLUTION" PROVISION DECIDED BY NEUTRAL ARBITRATION AS PROVIDED BY CALIFORNIA LAW AND YOU ARE GIVING UP ANY RIGHTS YOU MIGHT POSSESS TO HAVE THE DISPUTE LITIGATED IN A COURT OR JURY TRIAL. BY INITIALLING IN THE SPACE PROVIDED BELOW YOU ARE GIVING UP YOUR JUDICIAL RIGHTS TO DISCOVERY AND APPEAL, UNLESS THOSE RIGHTS ARE SPECIFICALLY INCLUDED IN THIS PROVISION. IF YOU REFUSE TO SUBMIT TO ARBITRATION AFTER AGREEING TO THIS PROVISION, YOU MAY BE COMPELLED TO ARBITRATE UNDER THE AUTHORITY OF THE CALIFORNIA CODE OF CIVIL PROCEDURE. YOUR AGREEMENT TO THIS ARBITRATION PROVISION IS VOLUNTARY.

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WE HAVE READ AND UNDERSTAND THE FOREGOING AND AGREE TO SUBMIT DISPUTES ARISING OUT OF THE MATTERS INCLUDED IN THE "GOVERNING LAW AND DISPUTE RESOLUTION" PROVISON TO NEUTRAL ARBITRATION.

CUSA _____________ BUYER _____________

CPL _____________

12.7 ENTIRE AGREEMENT AND MODIFICATIONS.

(a) This Agreement constitutes the entire agreement between Sellers and Buyer with respect to the subject matter hereof, superseding all prior statements, representations, discussions, agreements and understandings relating to such subject matter; provided, however, that the Confidentiality Agreement shall remain in effect until and unless the Closing occurs.

(b) Except as otherwise specifically provided in this Agreement, all covenants, agreements, representations, guaranties, indemnities, and warranties shall survive the Execution Date of this Agreement, the Closing Date, and the delivery and recordation of deeds, assignments or bills of sale which convey the Transferred Properties to Buyer.

(c) No modification to this Agreement shall be binding unless in writing and signed by representatives of all parties hereto. The waiver or failure of any party to enforce any provision of this Agreement shall not be construed or operate as a waiver of any further breach of such provision or of any other provision of this Agreement.

12.8 PARTIES IN INTEREST. Nothing in this Agreement, whether express or implied, is intended to confer any rights or remedies under or by reason of this Agreement on any persons other than the parties to it and their respective successors and assigns, nor is anything in this Agreement intended to relieve or discharge the obligation or liability of any third person to any party to this Agreement, nor shall any provision of this Agreement give any third persons any right of subrogation or action over and against any party to this Agreement.

12.9 SEVERABILITY. In the event any provision of this Agreement is held to be invalid by a court or arbitrator of competent jurisdiction, the invalidity of any such provision shall in no way affect any other provision contained herein; provided, however, that any such invalidity does not materially prejudice either Buyer or Sellers in their respective rights and obligations contained in the valid provisions of this Agreement.

12.10 RECORDS AND ASSISTANCE.

(a) For a period of seven years after the Closing Date, Buyer will retain the CUSA Records and the CPL Records defined in Sections 2.1 and 2.2 above (the "Records") and will make such Records available to Sellers for inspection and copying upon reasonable notice at

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Buyer's headquarters (or at such other location in the United States as Buyer shall designate in writing to Sellers) at reasonable times and during regular office hours. Following the expiration of such seven-year period, Buyer shall provide Sellers with 60 days' prior written notice of Buyer's intent to destroy any Records transferred to Buyer pursuant to this Agreement. If Sellers do not consent to the proposed destruction of Records, Buyer shall either continue to retain the Records and continue to make them available to Sellers as provided in the preceding sentence or require Sellers to remove such records at Sellers' cost and expense. To the extent Buyer receive copies of the Records because such Records relate to both the Transferred Properties and properties excluded from the Transferred Properties, Buyer shall maintain those portions of the Records which do not relate solely to the Transferred Properties strictly confidential and shall not disclose any such Records to any person or agency, unless such disclosure is required by Law.

(b) In the event of any dispute with respect to the ownership or operation of the Transferred Properties arising out of events which occurred prior to Closing, Buyer shall cooperate with Sellers, at no cost to Buyer, in the resolution of such dispute, including, without limitation, appearing in any litigation which may result therefrom; provided, however, that Buyer's agreement so to cooperate shall not be deemed an acceptance by Buyer of any liability arising from such dispute, as to which the other provisions of this Agreement shall control. Buyer, acknowledging that Sellers have continuing obligations with respect to outstanding lawsuits and claims associated with the Transferred Properties and that Sellers may be parties to claims and litigation asserted after Closing arising out of ownership or operations prior to Closing, shall make available to Sellers, upon Sellers' request at all reasonable times, but at no cost to Buyer, any and all files and business records in Buyer's custody or control transferred by Sellers to Buyer hereunder and, except in the case of a conflict of interest between the parties, any and all individuals employed by Buyer whose testimony or knowledge in the opinion of Sellers' counsel may be necessary or useful to it respecting the issues involved in such claims or litigation or in anticipation thereof.

(c) While Sellers are transferring books and records pertaining to the Transferred Properties to Buyer, Sellers by such act in no way intend to waive their attorney-client and work product privileges as to such documents which may be contained in such books and records and in particular with respect to those files associated with outstanding claims and lawsuits which have been identified in this Agreement. Buyer shall continue to maintain the confidential status of those files or turn them over to Sellers if so requested.

12.11 COUNTERPARTS. This Agreement may be executed in two or more counterparts and by different parties on separate counterparts, all of which shall be considered one and the same agreement, and each of which shall be deemed an original.

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IN WITNESS WHEREOF, Sellers and Buyer have caused this Agreement to be executed by their duly authorized representatives as of the Execution Date.

CHEVRON U.S.A. INC.,
a Pennsylvania corporation

By    /s/ G. R. STEIBACH
  -------------------------------------
  G. R. Steibach

CHEVRON PIPE LINE COMPANY,
a Delaware corporation

By    /s/ M. L. ELLINGSON
  -------------------------------------
  M. L. Ellingson

PLAINS RESOURCES INC.,
a Delaware corporation

By    /s/ JIM HESTER
  -------------------------------------

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EXHIBIT 10.8


CRUDE OIL MARKETING AGREEMENT

among

PLAINS RESOURCES INC.
PLAINS ILLINOIS INC.
STOCKER RESOURCES, L.P.
CALUMET FLORIDA, INC.

and

PLAINS MARKETING, L.P.



                               TABLE OF CONTENTS


ARTICLE I
DEFINITIONS.................................................   -5-
1.1  Definitions............................................   -5-

ARTICLE II
PURCHASE AND SALE...........................................   -3-
2.1  Purchase and Sale......................................   -3-
2.2  Addition or Release of Properties or Sellers...........   -4-
2.3  Delivery...............................................   -5-
2.4  Price..................................................   -5-
2.5  Payment................................................   -5-
2.6  General Provisions.....................................   -6-
2.7  No Restrictions........................................   -6-

ARTICLE III
RENEGOTIATION...............................................   -6-

ARTICLE IV
ADDITIONAL SERVICES.........................................   -7-
4.1  Additional Services....................................   -7-
4.2  Sellers Indemnity......................................   -7-

ARTICLE V
TERM........................................................   -8-

ARTICLE VI
REPRESENTATIONS AND WARRANTIES..............................   -8-
6.1  Representations and Warranties of Sellers..............   -8-
6.2  Representations and Warranties of Buyer................   -9-

ARTICLE VII
CREDIT REQUIREMENTS.........................................   -9-

ARTICLE VIII
SPECIFIED EVENTS............................................  -10-
8.1  Buyer Specified Events.................................  -10-
8.2  Seller Specified Events................................  -11-
8.3  Early Termination......................................  -12-
8.4  Specified Damages......................................  -12-

ARTICLE IX
FORCE MAJEURE...............................................  -12-
9.1  Excuse for Nonperformance..............................  -12-
9.2  Definition.............................................  -12-
9.3  Notice and Cure........................................  -13-

ARTICLE X
GENERAL PROVISIONS..........................................  -13-
10.1  No Survival of Representations and Warranties.........  -13-
10.2  Headings..............................................  -13-
10.3  Rights and Remedies Cumulative........................  -13-
10.4  Entire Agreement; Supersedure.........................  -13-
10.5  Severability..........................................  -13-
10.6  Choice of Law; Submission to Jurisdiction.............  -13-
10.7  Binding Agreement.....................................  -14-
10.8  No Agency.............................................  -14-
10.9  Notice................................................  -14-
10.10  Effect of Waiver or Consent..........................  -14-
10.11  Assignment...........................................  -14-
10.12  Counterparts.........................................  -14-
10.13  Amendment or Modification............................  -15-
10.14  Further Assurances...................................  -15-
10.15  Withholding or Granting of Consent...................  -15-
10.16  U.S. Currency........................................  -15-
10.17  Laws and Regulations.................................  -15-
10.18  Construction of Agreement............................  -15-

3

CRUDE OIL MARKETING AGREEMENT

This CRUDE OIL MARKETING AGREEMENT (this "Agreement"), dated November ___, 1998, is by and between PLAINS RESOURCES INC., a Delaware corporation ("Plains Resources"), PLAINS ILLINOIS INC., a Delaware corporation ("Plains Illinois"), STOCKER RESOURCES, L.P., a California limited partnership ("Stocker"), CALUMET FLORIDA, INC., a Delaware corporation ("Calumet"), and PLAINS MARKETING, L.P., a Delaware limited partnership ("Buyer"). Plains Resources, Plains Illinois, Stocker, and Calumet are sometimes referred to herein individually as a "Seller" and collectively as the "Sellers." Sellers and Buyer are sometimes referred to herein individually as a "Party" and collectively as the "Parties."

R E C I T A L S:

A. Sellers own and produce crude oil from properties located within the lower 48 states of the United States.

B. Sellers desire to sell and Buyer desires to purchase all of the crude oil which is produced and owned by Sellers from such properties.

NOW, THEREFORE, the Parties agree as follows:

ARTICLE I
DEFINITIONS

1.1 Definitions. As used herein, the following terms shall have the following meanings:

"Affiliate" means, with respect to any Person, any other Person that directly or indirectly through one or more intermediaries controls, is controlled by or is under common control with, the Person in question. As used herein, the term "control" means the possession, direct or indirect, of the power to direct or cause the direction of the management and policies of a Person, whether through ownership of voting securities, by contract or otherwise.

"Agreement" means this Agreement and all exhibits, schedules, amendments, modifications, and supplements to this Agreement.

"Anniversary Date" has the meaning assigned in Article III.

"Barrel" means forty-two (42) United States gallons of Crude Oil measured in accordance with the General Provisions.

"Business Day" means Monday through Friday of each week, except that a legal holiday recognized as such by the government of the United States of America or the states of New York or Texas shall not be regarded as a Business Day.


"Buyer Specified Event" has the meaning assigned in Section 8.1.

"Change of Control" has the meaning assigned in that certain Omnibus Agreement, dated as of the Closing Date (as defined therein), among Plains Resources, Buyer, General Partner, Plains All American Pipeline, L.P., a Delaware limited partnership, and All American, L.P., a Texas limited partnership.

"Conflicts Committee" means a committee of the Board of Directors of the General Partner composed entirely of two or more directors who are neither securityholders, officers nor employees of the General Partner nor officers, directors or employees of any Affiliate of the General Partner.

"Corporate Governance Documents" means, with respect to any Person, the Certificate or Articles of Incorporation, or Partnership Agreement (or their equivalents), the by-laws (or their equivalents), and the other corporate governance documents of such Person.

"Crude Oil" means crude oil meeting the specifications set forth in the General Provisions.

"Defaulting Party" means (a) in the case of a Buyer Specified Event, Buyer, and (b) in the case of a Seller Specified Event, any Seller affected by such Seller Specified Event.

"Delivery Point" has the meaning assigned in Section 2.3.

"Effective Date" means the date of execution of this Agreement.

"Existing Contract" has the meaning assigned in Section 2.2(g).

"Force Majeure" has the meaning assigned in Article IX.

"General Partner" means Plains All American Inc., a Delaware corporation, and its predecessors, successors and permitted assigns as general partner of the Buyer.

"General Provisions" has the meaning assigned in Section 2.6.

"Governmental Requirements" means all judgments, orders, writs, injunctions, decrees, awards, laws, ordinances, statutes, regulations, rules, franchises, permits, certificates, licenses, authorizations, and the like of any government, or any commission, board, court, agency, instrumentality, or political subdivision thereof.

"Marketing and Administrative Fee" has the meaning assigned in Section 2.4.

"Marketing Area" means the lower 48 states of the United States.

2

"Non-defaulting Party" means (i) in the case of a Buyer Specified Event, any Seller which is affected by such Buyer Specified Event, and (ii) in the case of a Seller Specified Event, Buyer.

"Person" means an individual or a corporation, limited liability company, partnership, joint venture, trust, unincorporated organization, association, government agency or political subdivision thereof or other entity.

"Platt's P+ Average" means the arithmetic average of the Platt's Prices for P-Plus WTI during a Trading Cycle.

"Platt's Difference" means the arithmetic average for a Trading Cycle of the difference between the Platt's Prices of the applicable grade of crude to be exchanged (i.e. WTS, LLS, HLS, Eugene Island, Bonito, etc.) and the prompt month WTI.

"Platt's Prices" means the average of the price range of a particular grade of crude oil as published in the Crude Price Assessments table of Platt's Oilgram Price Report.

"Purchase Price" has the meaning assigned in Section 2.4.

"Sales Price" has the meaning assigned in Section 2.4.

"Seller Specified Event" has the meaning assigned in Section 8.2.

"Specified Event" means a Buyer Specified Event or a Seller Specified Event, as the case may be.

"Trading Cycle" means for a particular month of delivery, a cycle beginning on the 26th day of the second month preceding such month of delivery through the 25th day of the month preceding such month of delivery.

"Trade Location" has the meaning assigned in Section 2.4(b).

ARTICLE II
PURCHASE AND SALE

2.1 Purchase and Sale. Buyer hereby agrees to purchase and receive and Sellers hereby agree to sell and deliver all of the Crude Oil produced and owned by Sellers from properties located within the Marketing Area. Currently, such properties are set forth on Exhibit A attached hereto and incorporated herein. Exhibit A shall be promptly updated to add or delete, as the case may be, Crude Oil production dedicated to this Agreement.

3

2.2 Addition or Release of Properties or Sellers. Crude Oil producing properties and Sellers shall be added or released from the terms and provisions of this Agreement upon the occurrence of the following events:

(a) If a Person who owns Crude Oil producing properties within the Marketing Area becomes an Affiliate of Plains Resources, Plains Resources shall cause such Affiliate to become a Seller hereunder by executing and delivering a ratification of this Agreement to Buyer as soon as practicable after the date such Person became an Affiliate of Plains Resources.

(b) If a Seller acquires additional Crude Oil properties within the Marketing Area, such additional properties and the Crude Oil owned and produced therefrom by such Seller shall become subject to this Agreement as soon as practicable after the date of acquisition of such properties.

(c) If a Seller, other than Plains Resources, ceases to be an Affiliate of Plains Resources, this Agreement shall terminate with respect to such Seller, its properties, and the Crude Oil produced therefrom, with such termination to be effective as soon as practicable following the date such Seller gives written notice to Buyer that it has ceased to be an Affiliate of Plains Resources.

(d) If a Seller sells, transfers or otherwise disposes of any of its properties or the interests therein which are within the Marketing Area, such properties or interests shall cease to be subject to this Agreement as soon as practicable following the date of such sale, transfer or disposition; but in no event shall such properties or interests cease to be subject to this Agreement prior to the termination of any agreement Buyer has previously entered into for the sale of Crude Oil attributable to production from such properties or interests.

(e) If a Seller and Buyer determine that it is impracticable for Buyer to purchase Crude Oil from any property owned by such Seller within the Marketing Area, such Seller and Buyer may, by mutual written agreement with the concurrence of the Conflicts Committee, terminate this Agreement with respect to such properties. Thereafter, neither such Seller nor Buyer shall have any further obligations under this Agreement with respect to such properties.

(f) Upon the occurrence of any of the foregoing events under subparagraphs
(a), (b), (c), (d) or (e) above, the affected Seller shall give written notice to Buyer as soon as practicable and Exhibit A shall be revised to reflect the effect of such event. Upon request by any Party affected by such event, all Parties hereto shall execute and deliver to the requesting Party such documents and instruments as may be reasonably necessary to evidence additions or releases of Parties or properties to this Agreement.

(g) Notwithstanding the provisions of subparagraphs (a) and (b) above, the addition of any Seller or properties to this Agreement shall be subject to any crude oil sales contract to which such Seller or properties are bound at the time such Seller or properties would otherwise become subject to this Agreement (an "Existing Contract"). Accordingly, no Crude Oil shall be sold

4

hereunder in contravention of an Existing Contract by such Seller or from such properties until the Existing Contract has expired or been terminated.

2.3 Delivery. Delivery shall be made from the lease tankage on the properties, or such other point as is mutually agreed to and reflected on Exhibit A (a "Delivery Point"), into transportation facilities designated by Buyer.

2.4 Price. The price to be paid by Buyer for Crude Oil sold hereunder (the "Purchase Price") shall be equal to the Sales Price for each Barrel as determined in this Section 2.4, less the sum of (i) a marketing and administrative fee of $.20 for each Barrel sold (the "Marketing and Administrative Fee") and (ii) with respect to Crude Oil which is not sold by Buyer at a Delivery Point, the reasonable out-of-pocket expenses (if any) incurred by Buyer to transport or exchange each Barrel of such Crude Oil.

(a) For Crude Oil which Buyer resells at a Delivery Point, the Sales Price shall be the price received by Buyer for each Barrel sold at the Delivery Point.

(b) For Crude Oil which Buyer either (i) transports to a location other than a Delivery Point (a "Trade Location") or (ii) exchanges for other Crude Oil at a Trade Location, the Sales Price shall be determined as follows:

(x) if such Crude Oil is not aggregated with other Crude Oil owned by Buyer, the Sales Price shall be equal to the price received by Buyer for each Barrel sold at the Trade Location; or

(y) if such Crude Oil is aggregated with other Crude Oil owned by Buyer, the Sales Price shall be equal to the sum of (i) the posted price received by Buyer for each Barrel sold at the Trade Location and
(ii) a premium equal to the Platt's P+ Average and plus or minus, as applicable, the Platt's Difference at the Trade Location. If the Platt's P+ Average or the Platt's Difference is not published, then the price shall be the weighted average for each Barrel of Buyer's sales at such Trade Location.

2.5 Payment. Payments by Buyer for Crude Oil purchased hereunder shall be based on the applicable Purchase Price, the volumes delivered by Sellers, and 100% of the interest shown on Exhibit A attached hereto, less state taxes which are withheld by Buyer. All payments shall be wired to Plains Resources for the account of the Sellers in accordance with written instructions from Plains Resources. Such wire transfers shall be made on the twentieth day of the month following the month of actual receipt of Crude Oil; provided that, if the twentieth day of the month falls on a Sunday or a banking holiday, payment will be made on the following Business Day, or if the twentieth day of the month falls on a Saturday, payment will be made on the preceding Business Day.

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2.6 General Provisions. Plains Marketing, L.P.'s General Provisions dated November 1, 1998, is attached hereto as Exhibit B and is incorporated by reference and made a part of this Agreement. If any conflict should arise between the General Provisions and the information stated herein, this Agreement shall apply.

2.7 No Restrictions. No provision contained in this Agreement shall in any way be interpreted as being a restriction on the ability of any Seller to convey or transfer Crude Oil to any other Seller, or to any of their subsidiaries. However, all such Crude Oil conveyed or transferred to a Seller or subsidiary is and shall remain subject to this Agreement including the obligations contained in this Article II.

ARTICLE III
RENEGOTIATION

Prior to the third anniversary of this Agreement, and the end of each successive three-year period thereafter (an "Anniversary Date"), either the Sellers or Buyer may request, in writing, to renegotiate the Marketing and Administrative Fee. Any such renegotiation request must be accompanied with documentation supporting the request to either increase or decrease the Marketing and Administrative Fee, and shall be in accordance with the following procedures:

(a) At least 120 days prior to the applicable Anniversary Date, either the Sellers or Buyer may request, in writing, to renegotiate the Marketing and Administrative Fee.

(b) Sellers and Buyer shall renegotiate the Marketing and Administrative Fee in good faith. If a revised Marketing and Administrative Fee has not been agreed upon at least 75 days prior to the applicable Anniversary Date, then Sellers may enter into negotiations for the sale of their Crude Oil with any Person who is not an Affiliate of Sellers. If Sellers do not reach an agreement with such non-affiliated Person at least 30 days prior to applicable Anniversary Date, then this Agreement shall continue and the Marketing and Administrative Fee shall be revised, effective the first day after the applicable Anniversary Date, to equal the Marketing and Administrative Fee last offered by Buyer.

(c) If Sellers are successful in reaching agreement with such non- affiliated Person which provides for (i) a term of not less than one year nor more than three years; (ii) a Marketing and Administrative Fee which is less than the Marketing and Administrative Fee last offered by Buyer; and (iii) additional services substantially similar to those provided for in Article IV below, this Agreement shall terminate. Such termination shall be effective on the next Anniversary Date and, thereafter, Sellers may sell their Crude Oil to such non-affiliated Person during the term of their agreement with such Person. Within 120 days prior to the end of the term of such other agreement, either the Sellers or Buyer may request negotiations to resume this Agreement and to negotiate a revised Marketing and Administrative Fee in accordance with the procedures set forth above.

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(d) Sellers' and Buyer's right to request a renegotiation of the Marketing and Administrative Fee in order to resume this Agreement shall continue until such time that this Agreement terminates pursuant to Article V, or until such time that Sellers have sold their Crude Oil production to a Person who is not an Affiliate of Sellers for a period of five (5) consecutive years.

ARTICLE IV
ADDITIONAL SERVICES

4.1 Additional Services. Upon request, Buyer agrees to provide Sellers with the following services which shall be provided at no additional cost to Sellers except for reimbursement of all reasonable out-of-pocket costs incurred by Buyer to provide such services:

(a) Provide Sellers with (i) historical information related to crude oil and natural gas prices in the possession of, or accessible to, Buyer, and (ii) Buyer's assessment of crude oil and natural gas prices to assist Sellers in their hedging strategies and decisions.

(b) Execute hedges on behalf of, or for the benefit of, Sellers' crude oil and natural gas production.

(c) Assist Sellers in their evaluation of potential acquisitions of oil and gas properties.

(d) Assist Sellers in preparing information relating to their potential disposition of any of their crude oil and natural gas properties.

(e) Market the production of their natural gas and natural gas liquids produced in association with Sellers' crude oil production.

(f) Negotiate natural gas purchase agreements required for the operation of Sellers' properties.

(g) Provide royalty distribution services.

4.2 SELLERS INDEMNITY. SELLERS AGREE TO RELEASE, PROTECT, DEFEND, INDEMNIFY AND HOLD BUYER, THE GENERAL PARTNER, AND THEIR PARENTS, SUBSIDIARIES, AFFILIATES, SUCCESSORS AND ASSIGNS, AND THEIR AGENTS, OFFICERS, DIRECTORS, EMPLOYEES, REPRESENTATIVES AND CONTRACTORS (HEREINAFTER COLLECTIVELY REFERRED TO AS THE "BUYER GROUP") HARMLESS FROM AND AGAINST ALL CLAIMS, LOSSES, COSTS, DEMANDS, DAMAGES, SUITS, JUDGMENTS, PENALTIES, LIABILITIES, DEBTS, EXPENSES AND CAUSES OF ACTION OF WHATSOEVER NATURE OR CHARACTER, INCLUDING BUT NOT LIMITED TO REASONABLE ATTORNEY'S FEES AND OTHER COSTS AND EXPENSES, WHICH IN ANY WAY ARISE OUT OF OR ARE RELATED TO THIS AGREEMENT, INCLUDING, WITHOUT LIMITATION, (I) THE PERFORMANCE OR SUBJECT MATTER OF THIS AGREEMENT, (II) THE PERFORMANCE OF THE SERVICES IN SECTION 4.1, (III) THE BREACH BY SELLERS OF ANY TERMS OF THIS AGREEMENT, OR (IV) THE INGRESS, EGRESS OR PRESENCE ON ANY PREMISES, WHETHER LAND, BUILDINGS, OR OTHERWISE, IN CONJUNCTION WITH THIS AGREEMENT (COLLECTIVELY, THE "CLAIMS"), INCLUDING CLAIMS DUE TO PERSONAL INJURY, DEATH, OR LOSS OR DAMAGE OF PROPERTY, WHETHER OR NOT CAUSED BY THE SOLE, JOINT AND/OR CONCURRENT NEGLIGENCE, FAULT OR STRICT LIABILITY OF ANY MEMBER

7

OF THE BUYER GROUP, BUT IN NO EVENT DOES THIS INDEMNITY INCLUDE CLAIMS CAUSED BY THE BUYER GROUP'S OWN GROSS NEGLIGENCE OR WILFUL MISCONDUCT.

ARTICLE V
TERM

The term of this Agreement shall commence on the date of this Agreement, and unless sooner terminated as provided herein, shall continue in effect until the earlier to occur of: (i) the time at which any Affiliate of Plains Resources ceases to be the general partner of Buyer, or (ii) a Change of Control of Plains Resources.

ARTICLE VI
REPRESENTATIONS AND WARRANTIES

6.1 Representations and Warranties of Sellers. Each Seller represents and warrants to Buyer as of the date hereof that:

(a) Each Seller is a corporation or limited partnership duly organized, validly existing, and in good standing under the laws of the state of their respective formation, and has all requisite corporate or partnership power and authority to execute, deliver, and perform this Agreement.

(b) The execution, delivery, and performance by each Seller of this Agreement, and the consummation of the transactions contemplated herein, are within its corporate or partnership power and authority and have been duly authorized by all necessary corporate or partnership action.

(c) No authorization, consent, or approval of, or other action by, or notice to, or filing with, any governmental authority, regulatory body, or any other Person is required for the due authorization, execution, delivery, or performance by any Seller of this Agreement, or the consummation of the transactions contemplated herein, except those authorizations, consents, and approvals which have been obtained and remain in full force and effect, and those notices and filings which have been made and remain in full force and effect.

(d) This Agreement has been duly executed and delivered by each Seller, and is the legal, valid, and binding obligation of each Seller enforceable against it in accordance with its terms, except that enforceability may be subject to applicable bankruptcy, insolvency, reorganization, moratorium, or other similar laws affecting the rights of creditors generally, and by general equitable principles (whether enforcement is sought by proceedings in equity or at law).

(e) Neither the execution, delivery, or performance by any Seller of this Agreement, nor the consummation of the transactions contemplated herein, will violate any provision of any Seller's Corporate Governance Documents, or any agreement, indenture, or instrument to which any Seller

8

is a party or by which any of its property or assets are bound, or any provision of any existing Governmental Requirement.

6.2 Representations and Warranties of Buyer. Buyer represents and warrants to Sellers as of the date hereof that:

(a) Buyer is a limited partnership duly organized, validly existing, and in good standing under the laws of the state of Delaware, and has all requisite power and authority to execute, deliver, and perform this Agreement.

(b) The execution, delivery, and performance by Buyer of this Agreement, and the consummation of the transactions contemplated herein, are within Buyer's partnership power and authority and have been duly authorized by all necessary partnership action.

(c) No authorization, consent, or approval of, or other action by, or notice to, or filing with, any governmental authority, regulatory body, or any other Person is required for the due authorization, execution, delivery, or performance by Buyer of this Agreement, or the consummation of the transactions contemplated by this Agreement, except those authorizations, consents, and approvals which have been obtained and remain in full force and effect, and those notices and filings which have been made and remain in full force and effect.

(d) This Agreement has been duly executed and delivered by Buyer, and is the legal, valid, and binding obligation of Buyer enforceable against Buyer in accordance with its terms, except that enforceability may be subject to applicable bankruptcy, insolvency, reorganization, moratorium, or other similar laws affecting the rights of creditors generally, and by general equitable principles (whether enforcement is sought by proceedings in equity or at law).

(e) Neither the execution, delivery, or performance by Buyer of this Agreement, nor the consummation of the transactions contemplated hereby, will violate any provision of Buyer's Corporate Governance Documents, or any agreement, indenture, or instrument to which Buyer is a party or by which any of its property or assets are bound, or any provision of any existing Governmental Requirement.

ARTICLE VII
CREDIT REQUIREMENTS

Purchases made by Buyer hereunder shall be on open account provided that:

(a) Buyer or its Affiliates are not in default in the payment when due of any of its indebtedness in excess of $2,500,000 in the aggregate; and

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(b) Buyer's sales of Crude Oil hereunder are in accordance with the credit policies set forth by Plains Resources' chief financial officer.

ARTICLE VIII
SPECIFIED EVENTS

8.1 Buyer Specified Events. Each of the following shall constitute a Buyer Specified Event for all purposes of this Agreement:

(a) Any amount due hereunder for the purchase of Crude Oil shall not be paid in full when due and Buyer does not cause the cure of such failure on or before the fifteenth (15th) Business Day after notice from a Seller of such failure is received by Buyer;

(b) Buyer fails to receive and purchase Crude Oil production dedicated to this Agreement for reasons other than Force Majeure or any action or inaction of a Seller, and such failure is not remedied on or before the earlier of the thirtieth (30th) day after (i) any officer of the General Partner becomes aware of such failure or (ii) a Seller has given written notice of such failure to Buyer;

(c) any representation and warranty made in Section 6.2 shall prove to have been incorrect in any material respect when made, and (i) such default or breach shall continue unremedied for a period of thirty (30) days after the earlier of
(x) any officer of the General Partner becomes aware of such default or (y) a Seller has given written notice of such default to Buyer, and (ii) a Seller reasonably determines that the continuation of such default or breach may materially and adversely affect Buyer's ability to satisfy its obligations hereunder;

(d) Buyer and Sellers fail to agree upon a revised Marketing and Administrative Fee as provided in Article III;

(e) Buyer (i) is dissolved (other than pursuant to a consolidation, amalgamation or merger); (ii) becomes insolvent or is unable to pay its debts or fails or admits in writing its inability generally to pay its debts as they become due; (iii) makes a general assignment, arrangement or composition with or for the benefit of its creditors; (iv) institutes or has instituted against it a proceeding seeking a judgment of insolvency or bankruptcy or any other relief under any bankruptcy or insolvency law or other similar law affecting creditors' rights, or a petition is presented for its winding-up or liquidation, and, in the case of any such proceeding or petition instituted or presented against it, such proceeding or petition (A) results in a judgment or insolvency or bankruptcy or the entry of an order for relief or the making of an order for its winding-up or liquidation or (B) is not dismissed, discharged, stayed or restrained in each case within thirty (30) days of the institution or presentation thereof, (v) has a resolution passed for its winding-up or liquidation (other than pursuant to a consolidation, amalgamation or merger);
(vi) seeks or becomes subject to the appointment of an administrator, provisional liquidator, conservator, receiver, trustee, custodian or other similar official

10

for it, or for all or substantially all its assets; (vii) has a secured party take possession of all or substantially all of its assets or has an execution, attachment, sequestration or other legal process levied, enforced or sued on or against all or substantially all of its assets and such secured party maintains possession or any such process is not dismissed, discharged, stayed or restrained in each case within thirty (30) days thereafter; (viii) causes or is subject to any event with respect to it which, under the applicable laws of any jurisdiction, has an analogous effect to any of the events specified in clauses
(i) to (vii) (inclusive); or (ix) takes any action in furtherance of, or indicating its consent to, approval of, or acquiescence in, any of the foregoing acts.

8.2 Seller Specified Events. Each of the following shall constitute a Seller Specified Event for all purposes of this Agreement:

(a) A Seller shall fail to deliver Crude Oil production subject to this Agreement and such failure is not remedied by such Seller on or before the fifteenth (15th) Business Day after notice from Buyer of such failure is received by the Seller;

(b) Any representation and warranty made in Section 6.1 shall prove to have been incorrect in any material respect when made, and (i) such default or breach shall continue unremedied for a period of thirty (30) days after the earlier of
(x) any officer of a Seller becomes aware of such default or (y) Buyer has given written notice of such default to a Seller, and (ii) Buyer reasonably determines that the continuation of such default or breach may materially adversely affect Seller's ability to satisfy its obligations hereunder;

(c) A Seller (i) is dissolved (other than pursuant to a consolidation, amalgamation or merger); (ii) becomes insolvent or is unable to pay its debts or fails or admits in writing its inability generally to pay its debts as they become due; (iii) makes a general assignment, arrangement or composition with or for the benefit of its creditors; (iv) institutes or has instituted against it a proceeding seeking a judgment of insolvency or bankruptcy or any other relief under any bankruptcy or insolvency law or other similar law affecting creditors' rights, or a petition is presented for its winding-up or liquidation, and, in the case of any such proceeding or petition instituted or presented against it, such proceeding or petition (A) results in a judgment or insolvency or bankruptcy or the entry of an order for relief or the making of an order for its winding-up or liquidation or (B) is not dismissed, discharged, stayed or restrained in each case within thirty (30) days of the institution or presentation thereof, (v) has a resolution passed for its winding-up or liquidation (other than pursuant to a consolidation, amalgamation or merger);
(vi) seeks or becomes subject to the appointment of an administrator, provisional liquidator, conservator, receiver, trustee, custodian or other similar official for it or for all or substantially all its assets; (vii) has a secured party take possession of all or substantially all of its assets or has an execution, attachment, sequestration or other legal process levied, enforced or sued on or against all or substantially all its assets and such secured party maintains possession, or any such process is not dismissed, discharged, stayed or restrained, in each case within thirty (30) days thereafter; (viii) causes or is subject to any event with respect to it which, under the applicable laws of any jurisdiction, had an analogous effect to any of the events specified

11

in clauses (i) to (vii) (inclusive); or (ix) takes any action in furtherance of, or indicating its consent to, approval of, or acquiescence in, any of the foregoing acts;

(d) Sellers and Buyer fail to agree upon a revised Marketing and Administrative Fee as provided in Article III.

8.3 Early Termination. If any Specified Event shall have occurred and be continuing, then the Non-defaulting Party may by notice to the Defaulting Party designate a date (which date shall not be earlier than 60 days after receipt of such notice) on which this Agreement shall terminate as between the Non- defaulting Party and the Defaulting Party, and this Agreement shall terminate as between the Non-defaulting Party and the Defaulting Party on such designated date whether or not such Specified Event is then continuing; provided that the provisions of Section 8.4 shall survive such termination.

8.4 Specified Damages. The Defaulting Party shall pay all damages and expenses incurred by the Non-defaulting Party as a result of the termination of this Agreement under Section 8.3 arising out of or in connection with any collection, bankruptcy, insolvency, or other enforcement proceedings resulting from the occurrence of the Specified Event giving rise to such termination. Payment of such damages and expenses shall be the Defaulting Party's only liability, and the Non-defaulting Party's sole remedy and exclusive claim, as a result of the Specified Event and the resulting termination of this Agreement under Section 8.3 as between the Non-defaulting Party and the Defaulting Party.

ARTICLE IX
FORCE MAJEURE

9.1 Excuse for Nonperformance. Subject to the other provisions of this Agreement, the obligations of a Party under this Agreement (including the obligation of Sellers to deliver Crude Oil), except the obligation to pay money to the other Party, may be suspended for a reasonable period as a result of an event of Force Majeure, to the extent that nonperformance is caused by Force Majeure, and the affected Party shall be relieved of liability for failing to perform from the inception of such event and during the continuance thereof and the time of any such suspension of obligations shall be added to the term of this Agreement.

9.2 Definition. An event of "Force Majeure" means war, riots, insurrections, fire, explosions, sabotage, strikes, and other labor or industrial disturbances, acts of God or the elements, Governmental Requirements, disruption or breakdown of production or transportation facilities, delays of pipeline carrier in receiving and delivering crude oil tendered, or any other cause, whether similar or not, reasonably beyond the control of the affected Party.

9.3 Notice and Cure. A Party affected by Force Majeure shall, as a condition to invoking Force Majeure as an excuse for nonperformance under this Agreement, promptly give notice of the

12

occurrence of Force Majeure to the other Party, with reasonably detailed information about the event of Force Majeure and the effect it has had, and is anticipated to have, on the performance of the invoking Party, and shall confirm such notice of Force Majeure and its consequences in writing no later than two
(2) Business Days after the occurrence of such event of Force Majeure. The invoking Party shall exercise due diligence in good faith to remedy the Force Majeure and resume full performance under this Agreement as soon as reasonably practicable.

ARTICLE X
GENERAL PROVISIONS

10.1 No Survival of Representations and Warranties. Notwithstanding anything to the contrary herein, all representations and warranties provided by Sellers and Buyer in Article VI shall not survive the termination of this Agreement.

10.2 Headings. The headings, captions, and arrangements contained in this Agreement have been inserted for convenience only and shall not be deemed in any manner to modify, explain, enlarge, or restrict any of the provisions hereof.

10.3 Rights and Remedies Cumulative. Except as provided in Section 8.4, the rights and remedies of each of the Parties under this Agreement shall be cumulative and non-exclusive of any other rights or remedies which each Party may have under any other agreement or instrument, by operation of law, or otherwise.

10.4 Entire Agreement; Supersedure. This Agreement constitutes the entire agreement of the parties relating to the matters contained herein, superseding all prior contracts or agreements, whether oral or written, relating to the matters contained herein.

10.5 Severability. If any provision of this Agreement or the application thereof to any Person or circumstance shall be held invalid or unenforceable to any extent, the remainder of this Agreement and the application of such provision to other Persons or circumstances shall not be affected thereby and shall be enforced to the greatest extent permitted by law.

10.6 Choice of Law; Submission to Jurisdiction. This Agreement shall be subject to and governed by the laws of the State of Texas, excluding any conflicts-of-law rule or principle that might refer the construction or interpretation of this Agreement to the laws of another state. Each party hereby submits to the jurisdiction of the state and federal courts in the State of Texas and to venue in Houston, Harris County, Texas.

10.7 Binding Agreement. This Agreement is entered into for the benefit of the Parties and their permitted successors and assigns. It shall be binding upon and shall inure to the benefit of such Parties and their successors and assigns.

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10.8 No Agency. Except as otherwise provided in this Agreement, nothing herein shall serve to create any agency, employment, master and servant relationship, partnership, or joint venture between Sellers and Buyer, their Affiliates, or any officer, director, employee or agent thereof.

10.9 Notice. All notices or requests or consents provided for or permitted to be given pursuant to this Agreement must be in writing and must be given by depositing same in the United States mail, addressed to the Person to be notified, postpaid, and registered or certified with return receipt requested or by delivering such notice in person or by telecopier or telegram to such party. Notice given by personal delivery or mail shall be effective upon actual receipt. Notice given by telegram or telecopier shall be effective upon actual receipt if received during the recipient's normal business hours, or at the beginning of the recipient's next business day after receipt if not received during the recipient's normal business hours. All notices to be sent to a party pursuant to this Agreement shall be sent to or made at the address set forth below, or at such other address as such party may stipulate to the other parties in the manner provided in this Section 10.9.

If to Buyer:                        If to Sellers:

Plains Marketing, L.P.              Plains Resources Inc.
500 Dallas, Suite 700               500 Dallas, Suite 700
Houston, Texas 77002                Houston, Texas 77002
Attention:  President of            Attention:  President
Plains All American Inc.

 10.10 Effect of Waiver or Consent.   No waiver or consent, express or

implied, by any party to or of any breach or default by any Person in the performance by such Person of its obligations hereunder shall be deemed or construed to be a consent or waiver to or of any other breach or default in the performance by such Person of the same or any other obligations of such Person hereunder. Failure on the part of a party to complain of any act of any Person or to declare any Person in default, irrespective of how long such failure continues, shall not constitute a waiver by such party of its rights hereunder until the applicable statute of limitations period has run.

10.11 Assignment. No party shall have the right to assign its rights or obligations under this Agreement without the consent of the other parties hereto.

10.12 Counterparts. This Agreement may be executed in any number of counterparts with the same effect as if all signatory parties had signed the same document. All counterparts shall be construed together and shall constitute one and the same instrument.

10.13 Amendment or Modification. This Agreement may be amended or modified from time to time only by the written agreement of all the parties hereto. Each such instrument shall be reduced to writing and shall be designated on its face an "Amendment" or an "Addendum" to this Agreement.

10.14 Further Assurances. In connection with this Agreement and all transactions

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contemplated by this Agreement, each signatory party hereto agrees to execute and deliver such additional documents and instruments and to perform such additional acts as may be necessary or appropriate to effectuate, carry out and perform all of the terms, provisions and conditions of this Agreement and all such transactions.

10.15 Withholding or Granting of Consent. Each party may, with respect to any consent or approval that it is entitled to grant pursuant to this Agreement, grant or withhold such consent or approval in its sole and uncontrolled discretion, with or without cause, and subject to such conditions as it shall deem appropriate.

10.16 U.S. Currency. All sums and amounts payable to or to be payable pursuant to the provisions of this Agreement shall be payable in coin or currency of the United States of America that, at the time of payment, is legal tender for the payment of public and private debts in the United States of America.

10.17 Laws and Regulations. Notwithstanding any provision of this Agreement to the contrary, no party hereto shall be required to take any act, or fail to take any act, under this Agreement if the effect thereof would be to cause such party to be in violation of any applicable law, statute, rule or regulation.

10.18 Construction of Agreement. In construing this Agreement:

(a) no consideration shall be given to the fact or presumption that one Party had a greater or lesser hand in drafting this Agreement;

(b) examples shall not be construed to limit, expressly or by implication, the matter they illustrate;

(c) the word "includes" and its derivatives means "includes, but is not limited to" and corresponding derivative expressions;

(d) a defined term has its defined meaning throughout this Agreement, regardless of whether it appears before or after the place where it is defined;

(e) the plural shall be deemed to include the singular, and vice versa;

(f) each gender shall be deemed to include the other genders;

(g) each reference to an article, section, or subsection refers to an article, section, or subsection of this Agreement unless expressly otherwise provided; and

(h) all references to a party shall include all successors and permitted assigns of such party.

15

[The next page is the signature page]

16

IN WITNESS WHEREOF, the Parties have executed this Agreement as of the date and year first above written.

BUYER:

PLAINS MARKETING, L.P.
By: Plains All American Inc.,
its General Partner

By:    /s/ Michael R. Patterson
       ------------------------
Name:  Michael R. Patterson
Title: Senior Vice President

SELLERS:

PLAINS RESOURCES INC.

By:    /s/ Michael R. Patterson
       ------------------------
Name:  Michael R. Patterson
Title: Senior Vice President

PLAINS ILLINOIS INC.

By:    /s/ Michael R. Patterson
       ------------------------
Name:  Michael R. Patterson
Title: Senior Vice President

STOCKER RESOURCES, L.P.
By: Stocker Resources, Inc., its General Partner

By:    /s/ Michael R. Patterson
       ------------------------
Name:  Michael R. Patterson
Title: Senior Vice President

CALUMET FLORIDA INC.

By:    /s/ Michael R. Patterson
       ------------------------
Name:  Michael R. Patterson
Title: Senior Vice President

17

EXHIBIT 10.9

October 23, 2001

Stocker Resources, L.P.
500 Dallas, Suite 700
Houston, Texas 77002

Attention: Mr. Timothy T. Stephens

Subject:        Crude Oil Sales Agreement dated April 1, 2001 between
                Tosco Refining Co. ("Tosco") and Plains Marketing, L.P. for
                Arroyo Grande Crude Oil (the "Tosco Agreement")

Dear Tim:

         This is to confirm our understanding and agreement that in the event

the Crude Oil Marketing Agreement ("Marketing Agreement") dated November, 1998 among Plains Marketing, L.P. ("Plains Marketing") and Plains Resources Inc., et al., terminates prior to the termination of the Tosco Agreement, a copy of which is attached hereto as Exhibit "A", then in such event, the parties hereby agree that Stocker Resources, L.P.'s ("Stocker") Arroyo Grande oil production will nonetheless continue to be committed and sold to Plains Marketing for the term of the Tosco Agreement under the same terms and conditions as provided for in the Marketing Agreement (except for the term thereof). Further, if there is any conflict between the terms of the Marketing Agreement and the terms of this agreement, the terms of this agreement shall prevail.

No person, including Tosco (and its successors and assigns) and its affiliates, other than the parties hereto is an intended beneficiary of this agreement or any portion hereof. Neither this agreement nor any of the rights or obligations hereunder may be assigned by a party without the other party's prior written consent. Plains Marketing shall indemnify and hold harmless Stocker, and its employees, and its controlling persons and affiliates, and their officers, directors and stockholders, from any liability, damage, deficiency, loss, penalty, cost or expense arising from or attributable to Plains Marketing's performance, or failure to perform for any reason (unless such failure to perform is caused by Stocker's failure to perform under the Marketing Agreement), under the Tosco Agreement.


Please confirm your agreement by signing and returning one copy of this letter.

Thank you for your consideration.

Very truly yours,

PLAINS MARKETING, L.P.
By Plains Marketing G.P. Inc.
Its General Partner

By:     /s/ Harry N. Pefanis
        --------------------------
Name:   Harry N. Pefanis
Title:  President

py

ACKNOWLEDGED AND AGREED:

STOCKER RESOURCES, L.P.
By Stocker Resources, Inc.
Its General Partner

By:      /s/ Timothy T. Stephens
         -----------------------------------
Name:    Timothy T. Stephens
Title:   Vice President and Secretary


EXHIBIT 23.1

CONSENT OF INDEPENDENT ACCOUNTANTS

We hereby consent to the use in this Registration Statement on Form S-1 of our report dated April 17, 2002 relating to the combined financial statements of the Upstream Subsidiaries of Plains Resources Inc., which appears in such Registration Statement. We also consent to the use of our report dated June 21, 2002 relating to the balance sheet of Plains E&P Company, which appears in such Registration Statement. We also consent to the references to us under the headings "Experts" in such Registration Statement.

PricewaterhouseCoopers LLP

Houston, Texas
June 21, 2002


EXHIBIT 23.3

CONSENT OF NETHERLAND, SEWELL & ASSOCIATES, INC.

We hereby consent to the references to our firm in this Registration Statement on Form S-1 (including any amendments thereto) filed by Plains Exploration & Production Company, as well as in the notes to the combined financial statements included in such Form S-1, to the reserve reports dated as of December 31, 1999, January 1, 2000, December 31, 2000, January 1, 2001, December 31, 2001 and January 1, 2002 setting forth the interests of Plains Exploration & Production Company, L.P. and its subsidiaries, and Arguello Inc., relating to the estimated quantities of such companies' proved reserves of oil and gas and present values thereof for the periods included therein.

NETHERLAND, SEWELL & ASSOCIATES, INC.

                                          By:     /s/ DANNY D. SIMMONS
                                             -----------------------------------
                                          Danny D. Simmons
                                          Senior Vice President

Houston, Texas
June 20, 2002


EXHIBIT 23.4

CONSENT OF RYDER SCOTT COMPANY, L.P.

As independent petroleum engineers, we hereby consent to the incorporation by reference in this Registration Statement on Form S-1 filed by Plains Exploration & Production Company, L.P. as well as in the notes to the combined financial statements included in such Form S-1, information contained in certain reserve reports effective December 31, 1999, December 31, 2000, and December 31, 2001, nine (9) reports in total, setting forth certain interests of Plains Exploration & Production Company, L.P. and its subsidiary, Plains Illinois Inc., relating to the estimated quantities of such companies' proved reserves of oil and gas and future net income therefrom discounted at ten percent (10%) for the periods included therein.

We further consent to the reference to this firm under the heading
"EXPERTS".

                                          /s/ RYDER SCOTT COMPANY, L.P.

                                          RYDER SCOTT COMPANY, L.P.

Houston, Texas
June 20, 2002


[H.J. GRUY AND ASSOCIATES, INC. LETTERHEAD]

EXHIBIT 23.5

CONSENT OF H.J. GRUY AND ASSOCIATES, INC.

We hereby consent to the use of the name H.J. Gruy and Associates, Inc. and of references to H.J. Gruy and Associates, Inc. and to the inclusion of and references to our reports, or information contained therein, dated March 10, 2000, and dated March 9, 2001, prepared for Stocker Resources, Inc. in the Registration Statement on form S-1 of Plains Exploration & Production Company, L.P. for the filing dated on or about June 21, 2002.

H.J. GRUY AND ASSOCIATES, INC.
Texas Registration Number F-000637

                                        by: /s/ SYLVIA CASTILLEJA
                                           ---------------------------------
                                        Sylvia Castilleja, P.E.
                                        Vice President



June 20, 2002
Houston, Texas