##### Table of Contents

---



UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549



---



FORM 10-K



x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934



For the fiscal year ended December 31, 2003



OR



 ̈ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934



Commission file number: 001-31470



PLAINS EXPLORATION
& PRODUCTION COMPANY

(Exact name of registrant as specified in its charter)



|                                                               |  |                                     
|-------------------------------------------------------------- |  | ------------------------------------
|Delaware                                                       |  | 33-0430755                          
|(State or other jurisdiction of incorporation or organization) |  | (I.R.S. Employer Identification No.)



700 Milam Street, Suite 3100

Houston, Texas 77002

(Address of
principal executive offices)

(Zip Code)



(832) 239-6000

(Registrants telephone number,
including area code)



Securities registered pursuant to Section
12(b) of the Act:



|                                        |  |                                          
|--------------------------------------- |  | -----------------------------------------
|Title of each class                     |  | Name of each exchange on which registered
|Common Stock, par value $0.01 per share |  | New York Stock Exchange                  



Securities registered pursuant
to Section 12(g) of the Act: none



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



Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrants knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.   ̈



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



On February 29, 2004, there were approximately 40.4 million shares of the
registrants Common Stock outstanding. The aggregate market value of the Common Stock held by non-affiliates of the registrant (treating all executive officers and directors of the registrant, for this purpose, as if they may be affiliates of
the registrant) was approximately $417 million on June 30, 2003 (based on $10.81 per share, the last sale price of the Common Stock as reported on the New York Stock Exchange on such date).



DOCUMENTS INCORPORATED BY REFERENCE: The information required in Part III of the
Annual Report on Form 10-K is incorporated by reference to the registrants definitive proxy statement to be filed pursuant to Regulation 14A for the registrants 2004 Annual Meeting of Stockholders.



---



---

##### Table of Contents

PLAINS EXPLORATION & PRODUCTION COMPANY.

2003 ANNUAL REPORT ON FORM 10-K



Table of Contents



|             |  |                                                                                                             |  |   
|------------ |  | ----------------------------------------------------------------------------------------------------------- |  | --
|             |  | Part I                                                                                                      |  |   
|Items 1 & 2. |  | Business and Properties                                                                                     |  | 6 
|Item 3.      |  | Legal Proceedings                                                                                           |  | 31
|Item 4.      |  | Submission of Matters to a Vote of Security Holders                                                         |  | 31
|             |  |                                                                                                            
|             |  | Part II                                                                                                     |  |   
|Item 5.      |  | Market for Registrants Common Stock, Related Stockholder Matters and Issuer Purchases of Equity Securities |  | 33
|Item 6.      |  | Selected Financial Data                                                                                     |  | 34
|Item 7.      |  | Managements Discussion and Analysis of Financial Condition and Results of Operations                       |  | 36
|Item 7A.     |  | Quantitative and Qualitative Disclosures About Market Risks                                                 |  | 49
|Item 8.      |  | Financial Statements and Supplementary Data                                                                 |  | 52
|Item 9.      |  | Changes in and Disagreements with Accountants on Accounting and Financial Disclosure                        |  | 52
|Item 9A.     |  | Controls and Procedures                                                                                     |  | 52
|             |  |                                                                                                            
|             |  | Part III                                                                                                    |  |   
|Item 10.     |  | Directors and Executive Officers of the Registrant                                                          |  | 53
|Item 11.     |  | Executive Compensation                                                                                      |  | 53
|Item 12.     |  | Security Ownership of Certain Beneficial Owners and Management And Related Stockholder Matters              |  | 53
|Item 13.     |  | Certain Relationships and Related Transactions                                                              |  | 53
|Item 14.     |  | Principal Accountant Fees and Services                                                                      |  | 53
|             |  |                                                                                                            
|             |  | Part IV                                                                                                     |  |   
|Item 15.     |  | Exhibits, Financial Statement Schedules and Reports on Form 8-K                                             |  | 54



1



---

##### Table of Contents

STATEMENT REGARDING FORWARD-LOOKING STATEMENTS



This Annual Report on Form 10-K includes forward-looking statements based 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 will, would, 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:



| |  |  | uncertainties inherent in the development and production of oil and gas and in estimating reserves;
| | - |  | ---------------------------------------------------------------------------------------------------



| |  |  | unexpected difficulties in integrating our operations with those of Nuevo Energy Corporation after the proposed acquisition;
| | - |  | ----------------------------------------------------------------------------------------------------------------------------



| |  |  | the consequences of our officers and employees providing services to both us and Plains Resources and not being required to spend any specified percentage or amount of time on our business;
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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



| |  |  | impact of oil and gas price fluctuations;
| | - |  | -----------------------------------------



| |  |  | the effects of our indebtedness, which could adversely restrict our ability to operate, could make us vulnerable to general adverse economic and industry conditions, could place us at a
competitive disadvantage compared to our competitors that have less debt, and could have other adverse consequences;
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | 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, industry or business conditions.
| | - |  | ----------------------------------------------------------



All forward-looking statements in this report are made as of the date hereof, and you should not place undue certainty on these statements without also considering
the risks and uncertainties associated with these statements and our business that are discussed in this report. 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. Except as required by applicable securities laws, we do not intend to update these forward-looking statements and information. See Items 1 &
2.Business and PropertiesRisk Factors and Item 7.Managements Discussion and Analysis of Financial Condition and Results of OperationsCritical Accounting Policies and Factors That May Affect Future
Results in this report for additional discussions of risks and uncertainties.



AVAILABLE INFORMATION



We file annual, quarterly and
current reports, proxy statements and other information with the SEC. You may read and copy any document we file at the SECs Public Reference Room at 450 Fifth Street, N.W., Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for
further information on the SECs Public Reference Room. Our SEC filings are also available to the public at the SECs



2



---

##### Table of Contents

web site at www.sec.gov. No information from such web site is incorporated by reference herein. Our web site is www.plainsxp.com. You may also obtain
copies of our annual, quarterly and current reports, proxy statements and certain other information filed with the SEC, as well as amendments thereto, free of charge from our web site. These documents are posted to our web site as soon as reasonably
practicable after we have filed or furnished these documents with the SEC. We have placed on our website copies of our Corporate Governance Guidelines, charters of our Audit, Organization and Compensation and Nominating and Corporate Governance
Committees, and our Policy Concerning Corporate Ethics and Conflicts of Interest. Stockholders may request a printed copy of these governance materials by writing to the Corporate Secretary, Plains Exploration & Production Company, 700 Milam,
Suite 3100, Houston, TX 77002.



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 information statement:



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.



Bcf.    One billion cubic feet of gas.



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 a person or entity has a working interest.



Gross oil and gas wells.    The total wells in which a person or entity owns 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.



3



---

##### Table of Contents

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.



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



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



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 from the production of proved reserves, computed by applying sales prices in effect as of the dates of such
estimates and held constant throughout the productive life of the reserves (except for consideration of price changes to the extent provided by contractual arrangements), and deducting the estimated future costs to be incurred in developing,
producing and abandoning the proved reserves (computed based on current costs and assuming continuation of existing economic conditions).



Proved developed reserves.    Proved developed oil and gas reserves are reserves that can be expected to be recovered
through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms
of primary recovery should be included as proved developed reserves only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.



Proved reserves.    Per
Article 4-10(a)(2) of Regulation S-X, the SEC defines proved oil and gas reserves as the estimated quantities of crude oil, natural 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, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual
arrangements, but not on escalations based upon future conditions.



Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes: (i) that portion delineated by drilling and
defined by gas-oil and/or oil-water contacts, if any; and (ii) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the
absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.



Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the
proved classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.



4



---

##### Table of Contents

Estimates of proved reserves do not include: (i) oil that may become available from known
reservoirs but is classified separately as indicated additional reserves; (ii) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir
characteristics, or economic factors; (iii) crude oil, natural gas, and natural gas liquids, that may occur in undrilled prospects; and (iv) crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and
other such sources.



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



Proved undeveloped reserves.    Proved undeveloped oil and gas reserves are 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. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive
units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation.
Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved
effective by actual tests in the area and in the same reservoir.



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 changes in proved reserves due to revisions of previous estimates, extensions, discoveries, improved recovery and other additions and purchases of reserves in-place.



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 the
production of proved reserves, computed by applying sales prices in effect as of the dates of such estimates and held constant throughout the productive life of the reserves (except for consideration of price changes to the extent provided by
contractual arrangements), and deducting the estimated future costs to be incurred in developing, producing and abandoning the proved reserves (computed based on current costs and assuming continuation of existing economic conditions). Future income
taxes are 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.



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.



5



---

##### Table of Contents

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.



References herein to Plains Exploration, Plains, PXP, the Company, we, us
and our mean Plains Exploration & Production Company.



Items 1 and 2.Business and Properties.



General



We are an independent oil and gas company primarily engaged in the activities of acquiring, developing, exploiting and producing oil and gas in the United States. We own oil and gas properties in ten states with principal
operations in:



| |  |  | the Los Angeles and San Joaquin Basins in California;
| | - |  | -----------------------------------------------------



| |  |  | the Santa Maria Basin offshore California;
| | - |  | ------------------------------------------



| |  |  | the Gulf Coast Basin onshore and offshore Louisiana; and
| | - |  | --------------------------------------------------------



| |  |  | the East Texas Basin in east Texas and north Louisiana.
| | - |  | -------------------------------------------------------



Assets in our principal focus areas include mature properties with long-lived reserves and significant development and exploitation opportunities as well as newer
properties with development, exploitation and exploration potential. We opportunistically hedge portions of our oil and gas production to manage our exposure to commodity price risk.



Proposed Acquisition of Nuevo Energy Corporation



On February 12, 2004 we announced that we had entered into a definitive agreement to acquire Nuevo Energy Company, or Nuevo, in a stock for stock transaction valued
at approximately $945 million, based on our February 11, 2004 closing stock price of $15.89 per share. Under the terms of the definitive agreement, Nuevo stockholders will receive 1.765 shares of our common stock for each share of Nuevo common
stock. If completed, we will issue up to 38.8 million shares to Nuevo shareholders and assume $234 million of net debt (as of December 31, 2003) and $115 million of Trust Convertible Preferred Securities.



The transaction is expected to qualify as a tax free reorganization under Section
368(a) and is expected to be tax free to our stockholders and tax free for the stock consideration received by Nuevo stockholders. The Boards of directors of both companies have approved the merger agreement and each has recommended it to their
respective stockholders for approval. The transaction is subject to stockholder approval from both companies and other customary conditions. Post closing, it is anticipated that PXP stockholders will own approximately 52 of the combined company and
Nuevo stockholders will own approximately 48 of the combined company.



The transaction will be accounted for as a purchase of Nuevo by PXP under purchase accounting rules and PXP will continue to use the full cost method of accounting for its oil and gas properties.



Acquisition of 3TEC Energy Corporation



On June 4, 2003, we acquired 3TEC Energy Corporation, or 3TEC, the merger, for
approximately $312.9 million in cash and common stock plus $90.0 million to retire 3TECs outstanding debt and $14.7 million to retire outstanding 3TEC preferred stock. Prior to



6



---

##### Table of Contents

the merger, 3TEC was engaged in the upstream activities of acquiring, exploiting, developing and producing oil and gas in East Texas and the Gulf Coast region, both
onshore and in the shallow waters of the Gulf of Mexico. In the transaction, each 3TEC common share was converted in to 0.85 of a share of our common stock and $8.50 in cash. In connection with the merger, we paid cash consideration to the common
shareholders of approximately $152.4 million and issued 15.3 million shares. In addition, we paid cash consideration of $8.3 million and issued 0.8 million common shares to redeem outstanding warrants. The cash portion of the purchase price was
funded by the issuance of $75.0 million of senior subordinated notes and amounts borrowed under our revolving credit facility. We have accounted for the acquisition of 3TEC as a purchase effective June 1, 2003.



Corporate Reorganization and Spin-off



Prior to December 18, 2002 we were a wholly owned subsidiary of Plains Resources. On
December 18, 2002 Plains Resources distributed 100% of the issued and outstanding shares of our common stock to the holders of record of Plains Resources common stock as of December 11, 2002. Each Plains Resources stockholder received one
share of our common stock for each share of Plains Resources common stock held. Prior to the spin-off, Plains Resources made an aggregate of $52.2 million in cash contributions to us and transferred to us certain assets and we assumed certain
liabilities of Plains Resources, primarily related to land, unproved oil and gas properties, office equipment and compensation obligations. We used the cash contributions to reduce outstanding debt under our revolving credit facility.



In contemplation of the spin-off, under the terms of a Master Separation Agreement
between us and Plains Resources, on July 3, 2002 Plains Resources contributed to us 100% of the capital stock of its wholly owned subsidiaries that own oil and gas properties in offshore California and Illinois. As a result, we indirectly own our
offshore California and Illinois properties and directly own our onshore California properties. Plains Resources also contributed to us $256.0 million of intercompany payables that we or our subsidiaries owed to it. On July 3, 2002 we and Plains
E&P Company, our wholly owned subsidiary that has no material assets and was formed for the sole purpose of being a corporate co-issuer of certain of our indebtedness, issued $200 million of 8.75% Senior Subordinated Notes due 2012, or the 8.75%
notes. On July 3, 2002 we also entered into a $300 million revolving credit facility. We distributed the net proceeds of $195.3 million from the 8.75% notes and $116.7 million of initial borrowings under our credit facility to Plains Resources.



Plains Resources received a favorable private letter ruling from the
Internal Revenue Service stating that for United States federal income tax purposes, the distribution of our common stock qualified as a tax-free distribution under Section 355 of the Internal Revenue Code.



Oil and Gas Operations



We own a 100% working interest in and operate all of our onshore California and Illinois Basin properties. On a pro forma basis for
the 3TEC merger, we operated approximately 85% of our 2003 production. As a result, we benefit from economies of scale and control the level, timing and allocation of a significant amount of our capital expenditures and expenses. Our onshore
California reserves are generally mature but underdeveloped, have produced significant volumes since initial discovery and have significant estimated remaining reserves while our East Texas and Gulf Coast properties generally have higher initial
production rates.



We have a large inventory of projects in our core
areas that we believe will support at least three years of development and exploitation activity at historical levels of capital investment. In addition, we have exploration projects at various levels of maturity including a recently acquired 102
square mile 3-D seismic survey in South Louisiana where we operate.



7



---

##### Table of Contents

We actively manage our exposure to commodity price fluctuations by hedging significant portions of our 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 25%-40% of our production for the following year. We may hedge to the higher end of the range depending on attractive price levels and
expected capital spending requirements. For example, assuming fourth quarter production levels are held constant at 39.0 MBOE per day, as of February 29, 2004 our hedge positions would have resulted in our having hedged approximately 69% of
production for 2004, 45% of production for 2005 and 39% of production for 2006.



As of December 31, 2003 we had estimated proved reserves of 281 MMBOE, of which 81% was comprised of oil and 58% was proved developed. We have a reserve life of over 19 years and a proved developed reserve life of over 11 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, 2003 and based on year-end 2003 spot market prices of $32.52 per Bbl
of oil and $5.97 per MMBtu of gas, our reserves had a PV-10 of $2.0 billion and a standardized measure of $1.3 billion.



The following table sets forth information with respect to our oil and gas properties as of and for the year ended December 31, 2003 (dollars in millions):



|                                |  |                             |         |   |           |   |       |       |  |   |         |  
|------------------------------- |  | --------------------------- | ------- | - | --------- | - | ----- | ----- |  | - | ------- | -
|                                |  | Onshore &OffshoreCalifornia |         |   | Other (1) |   |       | Total | 
|Proved reserves                 |  |                             |         |   |           |   |       |       |  |   |         |  
|MMBOE                           |  |                             | 216.9   |   |           |   | 64.0  |       |  |   | 280.9   |  
|Percent oil                     |  |                             | 93      | % |           |   | 41    | %     |  |   | 81      | %
|Proved Developed ReservesMMBOE |  |                             | 118.3   |   |           |   | 45.7  |       |  |   | 164.0   |  
|2003 ProductionMMBOE           |  |                             | 8.5     |   |           |   | 3.8   |       |  |   | 12.3    |  
|PV-10 (2)                       |  | $                           | 1,327.0 |   |           | $ | 642.3 |       |  | $ | 1,969.3 |  
|Standardized measure (3)        |  |                             |         |   |           |   |       |       |  | $ | 1,256.8 |  

---

|(1) |  | Includes 22.7 MMBOE of proved reserves, 12.6 MMBOE of proved developed reserves and $89.2 million PV-10 attributable to our Illinois Basin properties, for which we have a sales agreement that
is expected to close in mid-March 2004.
|--- |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|(2) |  | Based on year-end 2003 spot market prices of $32.52 per Bbl of oil and $5.97 per MMBtu of gas. PV-10 represents the standardized measure before deducting estimated future income taxes.
|--- |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|(3) |  | Estimated future income taxes are calculated on a combined basis using the statutory income tax rate, accordingly, the standardized measure is presented in total only.
|--- |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------



8



---

##### Table of Contents

Oil and Gas Reserves



The following table sets 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. The reserve volumes and values were determined under the method prescribed by the SEC, which requires the application of year-end prices for each year, held constant throughout the
projected reserve life.



|                                     |  |                                          |           |   |      |   |           |      |  |   |         |  
|------------------------------------ |  | ---------------------------------------- | --------- | - | ---- | - | --------- | ---- |  | - | ------- | -
|                                     |  | As of or for the Year Ended December 31, |          
|                                     |  | 2003                                     |           |   | 2002 |   |           | 2001 | 
|                                     |  | (dollars in thousands)                   |          
|Oil and Gas Reserves                 |  |                                          |           |   |      |   |           |      |  |   |         |  
|Oil (MBbls)                          |  |                                          |           |   |      |   |           |      |  |   |         |  
|Proved developed                     |  |                                          | 124,822   |   |      |   | 127,415   |      |  |   | 119,248 |  
|Proved undeveloped                   |  |                                          | 102,906   |   |      |   | 112,746   |      |  |   | 104,045 |  
|                                     |  |                                          |           |   |      |   |           |      |  |   |         |  
|                                     |  |                                          | 227,728   |   |      |   | 240,161   |      |  |   | 223,293 |  
|                                     |  |                                          |           |   |      |   |           |      |  |   |         |  
|Gas (MMcf)                           |  |                                          |           |   |      |   |           |      |  |   |         |  
|Proved developed                     |  |                                          | 235,070   |   |      |   | 53,317    |      |  |   | 59,101  |  
|Proved undeveloped                   |  |                                          | 84,107    |   |      |   | 23,837    |      |  |   | 37,116  |  
|                                     |  |                                          |           |   |      |   |           |      |  |   |         |  
|                                     |  |                                          | 319,177   |   |      |   | 77,154    |      |  |   | 96,217  |  
|                                     |  |                                          |           |   |      |   |           |      |  |   |         |  
|MBOE                                 |  |                                          | 280,924   |   |      |   | 253,020   |      |  |   | 239,329 |  
|                                     |  |                                          |           |   |      |   |           |      |  |   |         |  
|PV-10 (1):                           |  |                                          |           |   |      |   |           |      |  |   |         |  
|Proved developed                     |  | $                                        | 1,390,995 |   |      | $ | 916,373   |      |  | $ | 454,095 |  
|Proved undeveloped                   |  |                                          | 578,300   |   |      |   | 598,671   |      |  |   | 189,125 |  
|                                     |  |                                          |           |   |      |   |           |      |  |   |         |  
|                                     |  | $                                        | 1,969,295 |   |      | $ | 1,515,044 |      |  | $ | 643,220 |  
|                                     |  |                                          |           |   |      |   |           |      |  |   |         |  
|Standardized Measure                 |  | $                                        | 1,256,803 |   |      | $ | 883,507   |      |  | $ | 384,467 |  
|                                     |  |                                          |           |   |      |   |           |      |  |   |         |  
|Average year-end realized prices (2) |  |                                          |           |   |      |   |           |      |  |   |         |  
|Oil (per Bbl)                        |  | $                                        | 28.22     |   |      | $ | 26.91     |      |  | $ | 15.31   |  
|Gas (per Mcf)                        |  | $                                        | 5.53      |   |      | $ | 4.63      |      |  | $ | 2.56    |  
|Year-end spot market prices          |  |                                          |           |   |      |   |           |      |  |   |         |  
|Oil (per Bbl)                        |  | $                                        | 32.52     |   |      | $ | 31.20     |      |  | $ | 19.84   |  
|Gas (per Mcf)                        |  | $                                        | 5.97      |   |      | $ | 4.79      |      |  | $ | 2.58    |  
|Reserve replacement ratio            |  |                                          | 356       | % |      |   | 261       | %    |  |   | 321     | %
|Reserve life (years) (3)             |  |                                          | 19.6      |   |      |   | 27.1      |      |  |   | 27.3    |  
|Reserve replacement cost per BOE     |  | $                                        | 10.98     |   |      | $ | 2.64      |      |  | $ | 4.47    |  

---

|(1) |  | PV-10 represents the standardized measure before deducting estimated future income taxes. Our year-end 2003 PV-10 and standardized measure include future development costs related to proved
undeveloped reserves of $37.8 million in 2004, $69.2 million in 2005 and $49.2 million in 2006.
|--- |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|(2) |  | Based on price in effect at year-end with adjustments based on location and quality.
|--- |  | ------------------------------------------------------------------------------------

|(3) |  | 2003 based on annualized fourth quarter production to reflect the effect of the 3TEC merger.
|--- |  | --------------------------------------------------------------------------------------------



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



9



---

##### Table of Contents

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. Historically, the prices for oil and gas have been volatile and are likely to continue to
be volatile in the future.



Since December 31, 2002 we have not filed any
estimates of total net proved oil or gas reserves with any federal authority or agency other than the SEC.



Exploitation, Development and Exploration



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;
| | - |  | ---------------------------------------------



| |  |  | 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 nearby acreage, pursuing farm-in drilling arrangements and purchasing minority interests in the property.



Exploration strategy.    We implement our exploitation plan with respect to our properties by:



| |  |  | focusing geophysical and geological talent;
| | - |  | -------------------------------------------



| |  |  | employing modern seismic applications;
| | - |  | --------------------------------------



| |  |  | establishing land and prospect inventory practices to reduce costs; and
| | - |  | -----------------------------------------------------------------------



| |  |  | using new technology applications in drilling and completion practices.
| | - |  | -----------------------------------------------------------------------



Description of Properties



Los Angeles and San Joaquin Basins in California



LA Basin



In 1992 we acquired substantially all of our producing oil properties in the LA Basin. These interests included the Inglewood and Inglewood satellite fields.
Following the initial acquisition, we expanded our holdings by acquiring all of ChevronTexacos interest in their Inglewood Vickers lease, which further consolidated our holdings in this field. We essentially hold a 100% working interest in the
LA Basin properties and operate approximately 536 production and 208 waterflood injection wells in the fields.



10



---

##### Table of Contents

The LA Basin properties consist of oil producing reservoirs discovered between 1924 and 1966. Since 1992 we have
drilled many production and injection wells, returned previously marginal wells to economic production, optimized pre-existing waterflood operations, initiated new waterfloods, optimized and installed innovative artificial lift systems, increased
the capacity and efficiency of water and gas-handling facilities, upgraded tank batteries and facilities to maintain regulatory compliance, reduced unit production expenses and improved marketing margins. Additionally, we continuously update and
execute new technical studies to identify more investment opportunities on these properties.



Seismic technology is being utilized in 2004 to further evaluate the unproved reserves in our LA Basin properties and enhance development of proved undeveloped reserves: conventional 3-D at the Inglewood field and innovative,
passive seismic at one of the Inglewood satellite fields. Interpretation of the Inglewood 3-D data was initiated in 2003, and will continue in 2004. Drilling based on the results will take place in 2004 and beyond. This is the first application of
3-D seismic technology for exploitation of an onshore LA Basin oil field.



In March 1997 we expanded our operations in the LA Basin by acquiring ChevronTexaco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 ownership of approximately 480 acres of surface fee land. A 2-D seismic line was completed in 2002 and in 2004 we expect to evaluate additional seismic and technical studies that may lead to additional seismic iniatives
potentially including 3-D seismic or passive seismic data acquisition. The potential value of our real estate holdings at Montebello will be evaluated in what may be a multi-year process beginning in 2004.



In 2003 we spent $34.3 million on capital projects in the LA Basin. We drilled 15
production wells and 10 injection wells, performed several recompletions, oil fracture and acid-stimulations, and completed a 21.5 square mile 3-D seismic survey over the Inglewood oilfield and contiguous areas. In 2004 we will drill additional
wells, workover other wells, stimulate and convert several wells to waterflood injectors, execute various technical studies including reservoir simulation, and complete a 3-D geologic model of Inglewood incorporating seismic interpretation, and
upgrade facilities to increase capacities and efficiencies. Several of the drilled wells are designed to produce deeper reservoirs at Inglewood that have been extensively studied and are under exploited, potentially holding significant reserves on
our leasehold. Our net average daily production from these properties was 14.4 MBOE per day in 2003.



San Joaquin Basin



In 1998 we acquired the Mt. Poso field from Aera Energy LLC. The Mt. Poso field is located near Bakersfield, California, in Kern County. Since
acquisition, we have undertaken an aggressive drilling program targeting the Pyramid Hill formation, completing a 107-well drilling program in 2000-2001. In 2002, we completed the installation of electrical generation facilities. In 2003 capital
investment was $10.2 million as 96 new wells were drilled and successfully fracture-stimulated. Our net average daily production from this field was 1.6 MBOE during 2003. The Mt. Poso oilfield is being exposed to the marketplace for potential
divestment in 2004.



Other Onshore California



In November 1997 we acquired a 100% working interest (94% 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 1,047 acres (net to our interest) included in the
1,500-acre producing unit. The field is primarily under continuous steam injection and in 2003 our net production from the field averaged 1.7 MBOE per day. Since acquiring



11



---

##### Table of Contents

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. In 2003 we spent $5.5 million, drilled 14 producing wells and 4 steam injection wells, and installed a cogeneration facility
rated to produce approximately 70% of current electrical demand in order to reduce electricity costs and provide additional steam.



Santa Maria Basin Offshore California



Point Arguello.    In 1999 and 2002 we acquired separate 26.3% working interests 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. The sellers of those interests retained responsibility for certain
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 the sellers 52.6% share of all other abandonment costs, primarily well-bore abandonments and conductor removals.



In 2003 we spent $8.2 million on exploitation capital projects, which included drilling two development wells and converting two wells to electric submersible lift
systems. In 2004 we expect to continue with our successful workover and high volume lift programs in the unit. In January 2003 our net average daily oil production for the unit was 6.2 MBOE and ended the year at 5.4 MBOE per day for December. Our
net average daily oil production for the unit for the year 2003 was 5.7 MBOE



P-0451 E/2 Development.    We have applied for and received all the appropriate permits or modifications to existing permits from federal, state, and local agencies to allow for drilling into the
east half of offshore lease P-0451 or E/2 P-0451. The West half of lease P-0451 has already been developed as part of the Point Arguello unit. In 1983-1984 five exploratory wells were drilled into the P-0451 and adjacent P-0452 leases. These wells
tested at rates of 3,500, 1,629, 1,100, 604, and 120 barrels of oil per day, respectively, from an oil accumulation considered separate from the Point Arguello field. Based on geologic and geophysical interpretations, we believe approximately 60
percent of that accumulation underlies the E/2 P-0451. We are the operator of P-0451 and have agreements in place between the P-0451 owners and the Point Arguello unit owners that will allow us to participate with at least a 52.6% working interest
in the development of the P-0451 E/2 lease. We are now upgrading and mobilizing a rig which will be capable of developing this reservoir by means of extended reach wells drilled from two of the three Point Arguello unit platforms. It is anticipated
the drilling will commence in the first half of 2004. While there can be no assurance that drilling will recover economic quantities of oil and gas from the E/2 P-0451, the earlier exploration work indicates a potentially economically viable
reservoir.



Gulf Coast Basin Onshore and Offshore Louisiana



We are expanding along the Gulf Coast of Louisiana from the
established base of proven reserves and undeveloped acreage acquired in the 2003 3TEC merger. We have entered into additional joint ventures which, as operator, will allow us to continue our expansion in our core areas. In 2003 we spent $37.3
million on exploration and development projects (all subsequent to the 3TEC merger). Our net average daily oil and gas production for this area was 1.2 MBbls of oil per day and 27.2 MMcf of gas per day in December 2003.



State Waters.    We have multiple drilling projects
in Breton Sound, Main Pass and Chandeleur Sound (Breton Sound Area or BSA). During 2001-2002, 3TEC participated in six exploratory wells in Louisiana state waters, of which five were gas discoveries. In 2003 an additional eight exploratory



12



---

##### Table of Contents

wells were drilled in the Breton/Chandeleur Sound areas. Seven were successful. We are continuing our work in the area to drill additional identified prospects. To
complement and extend our success in the Breton Sound Area, we acquired a 56.25% interest in 32 new prospects we will operate in an area we refer to as Breton Sound Extension or BSE. Drilling in BSE began in November 2003 with three
successful wells and no dry holes drilled by year-end. Additionally, we acquired a 37.5% interest in an ongoing 178 square mile 3-D seismic acquisition program to the west of BSA. We refer to this new 178 square mile area as Breton Sound
Extension-West or BSE-W. To further build on our activities in this area we acquired previously shot 3-D seismic data in an approximately 79 square mile area east of our original BSA activity area. We refer to this area as Breton Sound Extension
East or BSE-E. PXP will operate in this area with a 75% interest. The 3-D data will be reprocessed to assist in the identification and validation of prospect locations.



South Louisiana.    We are building an inventory of prospects based on our 102 square miles of new
3-D seismic data in the Garden City area. PXP operates this area with a 66.7% interest.



East Texas Basin in East Texas and North Louisiana



As a result of the 3TEC merger we acquired interests included in the Rosewood, White Oak/Glenwood, Beckville, Carthage, East Henderson and Oak Hill fields in east Texas. The predominant producing formation is the Cotton Valley Sand gas
reservoir with indicated additional pay in the shallower Travis Peak and Pettit formations. There are many proven undeveloped Cotton Valley drilling locations under regulatory field rules that now permit wells to be drilled on 80 acre spacing as
opposed to 160 acre or larger spacing. At year-end 2003 we had 142 identified proved undeveloped locations in this area. During 2003 we or our predecessor 3TEC drilled nine development wells and participated in 36 wells drilled by others. All wells
encountered productive intervals except one which was abandoned for mechanical reasons above the target interval. In 2003 we spent $16.3 million on exploitation and development projects on these properties (all subsequent to the 3TEC merger). Our
net average daily oil and gas production for this area was 0.5 MBbls of oil per day and 38.2 MMcf of gas per day in December 2003.



White Oak/Glenwood Fields.    In connection with the 3TEC merger, we acquired an interest in 247 producing wells in the fields. Our
working interest varies from well to well and ranges from 3% to 39%.



Beckville Field.    We are the operator of the Beckville field with a working interest that varies from well to well and ranges from 48% to 100%. In December 2003 we operated 35 producing wells in this field.



We have a non-exclusive seismic license to access 1,465 square miles of
3D seismic data within the area encompassed within Texas and Louisiana. We also have a joint venture with another company whereby collectively we will evaluate 374 square miles of this data located in south Texas for the purposes of generating
exploration prospects.



Other



Illinois Basin.    In 2003 our production from these
properties averaged 2.3 MBOE of oil per day. We have an agreement to sell these properties via the sale of the stock of our Illinois subsidiary with an expected closing in mid-March 2004.



Property Divestments.    The Company periodically evaluates and from time to time has elected to sell
certain of its mature producing properties that it considers to be nonstrategic or fully valued. Such sales enable the Company to focus on its core properties, maintain financial flexibility, reduce overhead and redeploy the proceeds therefrom to
activities that the Company believes potentially have a higher financial return. In 2003, we sold our interest in 36 predominantly non-operated and noncore



13



---

##### Table of Contents

fields in the Permian Basin, the Texas Panhandle, east Texas, the Mid-continent Area, Alabama, Arkansas, Mississippi, North Dakota and New Mexico for aggregate
proceeds of approximately $23 million. Production from these fields was approximately 800 net equivalent barrels per day and proved reserves were 3.6 MMBOE.



Acquisition, Exploration, Exploitation and Development Expenditures



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



|                                   |  |                         |         |      |   |        |      |  |   |        
|---------------------------------- |  | ----------------------- | ------- | ---- | - | ------ | ---- |  | - | -------
|                                   |  | Year Ended December 31,
|                                   |  | 2003                    |         | 2002 |   |        | 2001
|Property acquisitions costs:       |  |                         |         |      |   |        |      |  |   |        
|Unproved properties                |  |                         |         |      |   |        |      |  |   |        
|3TEC Acquisition                   |  | $                       | 61,116  |      | $ |       |      |  | $ |       
|Other                              |  |                         | 19,025  |      |   | 65     |      |  |   | 44     
|Proved properties (1)              |  |                         |         |      |   |        |      |  |   |        
|3TEC Acquisition                   |  |                         |         |      |   |        |      |  |   |        
|Asset retirement cost              |  |                         | 4,577   |      |   |       |      |  |   |       
|Other                              |  |                         | 289,779 |      |   |       |      |  |   |       
|Other                              |  |                         | 1,197   |      |   | (4,516 | )    |  |   | 1,645  
|Exploration costs                  |  |                         | 8,947   |      |   | 602    |      |  |   | 286    
|Exploitation and development costs |  |                         | 101,334 |      |   | 68,346 |      |  |   | 123,778
|                                   |  |                         |         |      |   |        |      |  |   |        
|                                   |  | $                       | 485,975 |      | $ | 64,497 |      |  | $ | 125,753
|                                   |  |                         |         |      |   |        |      |  |   |        

---

|(1) |  | In connection with the acquisition of an additional interest in the Point Arguello field, offshore California, in 2002 we assumed certain obligations of the seller. As consideration for
receiving the transferred properties and assuming such obligations, we received $2.4 million. In addition, we received $2.7 million as our share of revenues less costs for the period April 1 to July 31, 2002, the period prior to ownership.
|--- |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



Exploitation and development costs include expenditures of
$30.2 million in 2003, $27.3 million in 2002 and $58.5 million in 2001 related to the development of proved undeveloped reserves included in our proved oil and gas reserves at the beginning of each year. Exploitation and development costs include
capital costs required to maintain our proved developed producing reserves. Amounts presented do not include the cumulative effect adjustment for the January 1, 2003 adoption of SFAS 143 of $15.9 million.



14



---

##### Table of Contents

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 realized and our average production expenses during the years ended December 31, 2003, 2002 and 2001.



|                                         |  |                         |         |   |      |   |         |      |  |   |         |  
|---------------------------------------- |  | ----------------------- | ------- | - | ---- | - | ------- | ---- |  | - | ------- | -
|                                         |  | Year Ended December 31, |        
|                                         |  | 2003                    |         |   | 2002 |   |         | 2001 | 
|Sales                                    |  |                         |         |   |      |   |         |      |  |   |         |  
|Oil (MBbls)                              |  |                         | 9,267   |   |      |   | 8,783   |      |  |   | 8,219   |  
|Gas (MMcf)                               |  |                         | 18,195  |   |      |   | 3,362   |      |  |   | 3,355   |  
|MBOE                                     |  |                         | 12,300  |   |      |   | 9,343   |      |  |   | 8,778   |  
|Revenue                                  |  |                         |         |   |      |   |         |      |  |   |         |  
|Oil                                      |  | $                       | 249,500 |   |      | $ | 193,615 |      |  | $ | 174,614 |  
|Oil hedging                              |  |                         | (51,352 | ) |      |   | (15,577 | )    |  |   | 281     |  
|                                         |  |                         |         |   |      |   |         |      |  |   |         |  
|                                         |  |                         | 198,148 |   |      |   | 178,038 |      |  |   | 174,895 |  
|                                         |  |                         |         |   |      |   |         |      |  |   |         |  
|Gas                                      |  |                         | 91,267  |   |      |   | 10,299  |      |  |   | 28,771  |  
|Gas hedging                              |  |                         | 13,787  |   |      |   |        |      |  |   |        |  
|                                         |  |                         |         |   |      |   |         |      |  |   |         |  
|                                         |  |                         | 105,054 |   |      |   | 10,299  |      |  |   | 28,771  |  
|                                         |  |                         |         |   |      |   |         |      |  |   |         |  
|Other                                    |  |                         | 888     |   |      |   | 226     |      |  |   | 473     |  
|                                         |  |                         |         |   |      |   |         |      |  |   |         |  
|                                         |  | $                       | 304,090 |   |      | $ | 188,563 |      |  | $ | 204,139 |  
|                                         |  |                         |         |   |      |   |         |      |  |   |         |  
|Average Prices and Costs                 |  |                         |         |   |      |   |         |      |  |   |         |  
|Average Oil Sales Price ($/Bbl)          |  |                         |         |   |      |   |         |      |  |   |         |  
|Average NYMEX                            |  | $                       | 30.99   |   |      | $ | 26.15   |      |  | $ | 26.01   |  
|Hedging revenue (cost)                   |  |                         | (5.54   | ) |      |   | (1.77   | )    |  |   | 0.03    |  
|Differential                             |  |                         | (4.07   | ) |      |   | (4.11   | )    |  |   | (4.76   | )
|                                         |  |                         |         |   |      |   |         |      |  |   |         |  
|Net realized                             |  | $                       | 21.38   |   |      | $ | 20.27   |      |  | $ | 21.28   |  
|                                         |  |                         |         |   |      |   |         |      |  |   |         |  
|Average Gas Sales Price ($/Mcf)          |  |                         |         |   |      |   |         |      |  |   |         |  
|Average NYMEX                            |  | $                       | 5.24    |   |      | $ | 3.34    |      |  | $ | 4.34    |  
|Hedging revenue (cost)                   |  |                         | 0.76    |   |      |   |        |      |  |   |        |  
|Differential                             |  |                         | (0.23   | ) |      |   | (0.28   | )    |  |   | 4.24    |  
|                                         |  |                         |         |   |      |   |         |      |  |   |         |  
|Net realized                             |  | $                       | 5.77    |   |      | $ | 3.06    |      |  | $ | 8.58    |  
|                                         |  |                         |         |   |      |   |         |      |  |   |         |  
|Average Realized Price per BOE           |  | $                       | 24.65   |   |      | $ | 20.16   |      |  | $ | 23.20   |  
|                                         |  |                         |        
|Costs and Expenses per BOE               |  |                         |         |   |      |   |         |      |  |   |         |  
|Production expenses                      |  |                         | 7.49    |   |      |   | 7.94    |      |  |   | 6.86    |  
|Production and ad valorem taxes          |  |                         | 0.82    |   |      |   | 0.46    |      |  |   | 0.41    |  
|Gathering and transportation             |  |                         | 0.21    |   |      |   |        |      |  |   |        |  
|G&A                                      |  |                         |         |   |      |   |         |      |  |   |         |  
|G&A excluding items below                |  |                         | 1.62    |   |      |   | 1.15    |      |  |   | 1.16    |  
|Stock appreciation rights                |  |                         | 1.46    |   |      |   | 0.39    |      |  |   |        |  
|Merger related costs                     |  |                         | 0.43    |   |      |   |        |      |  |   |        |  
|Spinoff related costs                    |  |                         |        |   |      |   | 0.09    |      |  |   |        |  
|Depletion, depreciation and amortization |  |                         | 3.86    |   |      |   | 3.17    |      |  |   | 2.70    |  



15



---

##### Table of Contents

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 and gas sales. Our hedging
arrangements provide us protection on the hedged volumes if prices decline below the prices at which these hedges are set. However, ceiling prices in our hedges may cause us to receive less revenue on the hedged volumes than we would receive in the
absence of 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 and trucks
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 from properties owned prior to the 3TEC merger. The marketing agreement provides that PAA will purchase for resale at market prices
all of our equity oil production from properties owned prior to the merger. We pay PAA a marketing and administration fee and reimburse PAA for its reasonable expenses incurred in transporting or exchanging our oil. We have agreed to renegotiate the
marketing and administration fee in good faith every three years. Under the marketing agreement, PAA has also agreed to, upon our request and reimbursement for its reasonable expenses, market certain of our gas and gas liquids and negotiate our gas
purchase agreements. If we were to lose PAA as the exclusive purchaser of our equity production, we believe PAA could be replaced by other purchasers under contracts with similar terms and conditions. However, PAAs role as the exclusive
purchaser for all of our equity oil production does have 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. During 2003,
2002 and 2001 no other purchaser accounted for more than 10% of our total revenues.



16



---

##### Table of Contents

Productive Wells and Acreage



As of December 31, 2003 we had working interests in 2,188 gross (2,170 net) active producing oil wells and 767 gross (331 net) active producing gas wells. The
following table sets forth information with respect to our developed and undeveloped acreage as of December 31, 2003.



|                        |  |                 |  |                       |  |         |  |       
|----------------------- |  | --------------- |  | --------------------- |  | ------- |  | ------
|                        |  | Developed Acres |  | Undeveloped Acres (1)
|                        |  | Gross           |  | Net                   |  | Gross   |  | Net   
|Onshore California      |  | 8,889           |  | 8,844                 |  | 3,072   |  | 89    
|Offshore California (2) |  | 15,326          |  | 8,066                 |  | 41,720  |  | 2,898 
|Illinois                |  | 16,670          |  | 14,676                |  | 13,857  |  | 5,620 
|Indiana                 |  | 1,155           |  | 854                   |  | 1,280   |  | 575   
|Kansas                  |  |                |  |                      |  | 48,147  |  | 37,647
|Louisiana               |  | 25,594          |  | 10,781                |  | 31,736  |  | 14,453
|Mississippi             |  | 1,836           |  | 315                   |  |        |  |      
|New Mexico              |  | 64,006          |  | 36,930                |  |        |  |      
|Oklahoma                |  | 14,093          |  | 5,284                 |  | 550     |  | 47    
|Texas                   |  | 121,531         |  | 58,102                |  | 7,881   |  | 5,141 
|Other                   |  |                |  |                      |  | 1,961   |  | 1,161 
|                        |  |                 |  |                       |  |         |  |       
|Total                   |  | 269,100         |  | 143,852               |  | 150,204 |  | 67,631
|                        |  |                 |  |                       |  |         |  |       

---

|(1) |  | Less than 10% of total net undeveloped acres are covered by leases that expire from 2003 through 2005.
|--- |  | ------------------------------------------------------------------------------------------------------

|(2) |  | Excludes 1,632 undeveloped acres (net) that we have the right to acquire under an option agreement.
|--- |  | ---------------------------------------------------------------------------------------------------



Drilling Activities



Information with regard to our drilling activities during the years ended December 31, 2003, 2002 and 2001 is set forth below:



|                  |  |                         |  |       |  |       |  |      |  |       |  |      
|----------------- |  | ----------------------- |  | ----- |  | ----- |  | ---- |  | ----- |  | -----
|                  |  | Year Ended December 31,
|                  |  | 2003                    |  | 2002  |  | 2001 
|                  |  | Gross                   |  | Net   |  | Gross |  | Net  |  | Gross |  | Net  
|Exploratory Wells |  |                         |  |       |  |       |  |      |  |       |  |      
|Oil               |  |                        |  |      |  |      |  |     |  |      |  |     
|Gas               |  | 7.0                     |  | 2.2   |  |      |  |     |  |      |  |     
|Dry               |  | 3.0                     |  | 1.0   |  |      |  |     |  |      |  |     
|                  |  |                         |  |       |  |       |  |      |  |       |  |      
|                  |  | 10.0                    |  | 3.2   |  |      |  |     |  |      |  |     
|                  |  |                         |  |       |  |       |  |      |  |       |  |      
|Development Wells |  |                         |  |       |  |       |  |      |  |       |  |      
|Oil               |  | 121.0                   |  | 121.0 |  | 79.0  |  | 77.4 |  | 168.0 |  | 163.4
|Gas               |  | 32.0                    |  | 14.0  |  |      |  |     |  |      |  |     
|Dry               |  | 1.0                     |  | 0.4   |  | 1.0   |  | 0.5  |  | 1.0   |  | 1.0  
|                  |  |                         |  |       |  |       |  |      |  |       |  |      
|                  |  | 154.0                   |  | 135.4 |  | 80.0  |  | 77.9 |  | 169.0 |  | 164.4
|                  |  |                         |  |       |  |       |  |      |  |       |  |      
|                  |  | 164.0                   |  | 138.6 |  | 80.0  |  | 77.9 |  | 169.0 |  | 164.4
|                  |  |                         |  |       |  |       |  |      |  |       |  |      



17



---

##### Table of Contents

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:



|              |  |                                    |  |                                       
|------------- |  | ---------------------------------- |  | --------------------------------------
|Property      |  | Location                           |  | ApproximateAcreage(Net to OurInterest)
|Inglewood     |  | Los Angeles County, California     |  | 25                                    
|Montebello    |  | Los Angeles County, California     |  | 480                                   
|Arroyo Grande |  | San Luis Obispo County, California |  | 1,047                                 
|Mt. Poso      |  | Kern County, California            |  | 1,236                                 
|Gaviota       |  | Santa Barbara County, California   |  | 84                                    



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 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



18



---

##### Table of Contents

believe that we are affected in a significantly different manner by these laws and regulations than are our competitors. Due to the myriad 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.



MMS.    The
Minerals Management Service, or MMS, has broad authority to regulate our oil and gas operations on offshore leases in federal waters. It must approve and grant permits in connection with our drilling and development plans. Additionally, the MMS has
promulgated regulations requiring offshore production facilities to meet stringent engineering and construction specifications restricting the flaring or venting of gas, governing the plugging and abandonment of wells and controlling the removal of
production facilities. Under certain circumstances, the MMS may suspend or terminate any of our operations on federal leases, as discussed in Risk FactorsGovernmental agencies and other bodies, including those in California, might impose
regulations that increase our costs and may terminate or suspend our operations, and has proposed regulations that would permit it to expel unsafe operators from offshore operations. The MMS has also established rules governing the calculation
of royalties and the valuation of oil produced from federal offshore leases and regulations regarding costs for gas transportation. Delays in the approval of plans and issuance of permits by the MMS because of staffing, economic, environmental or
other reasons could adversely affect our operations.



Regulation of
production.    Oil and gas production is regulated 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



19



---

##### Table of Contents

intended to foster increased competition within all phases of the gas industry. To date, the 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. 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. 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.



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. 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.



Permits.    Our operations are subject to various federal, state and local regulations that include requiring permits for the
drilling of wells, maintaining bonding and insurance requirements to drill, operate, plug and abandon, and restore the surface associated with our wells, and regulating the location of wells, the method of drilling and casing wells, the surface use
and restoration of properties upon which wells are drilled, the plugging and abandonment of wells, the disposal of fluids and solids used in connection with our operations and air emissions associated with our operations. Also, we have permits from
the city and county of Los Angeles, California, the city of Culver City, California, the county of Kern, California, and the county of Santa Barbara, California to operate crude oil, natural gas and related pipelines and equipment that run within
the boundaries of these governmental entities. The permits required for various aspects of our operations are subject to revocation, modification and renewal by issuing authorities.



Plugging, Abandonment and Remediation Obligations



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



20



---

##### Table of Contents

non-producing wellbores, remove tanks, production equipment and flow lines and restore the wellsite. Typically when producing oil and gas assets are purchased, one
assumes the obligation to plug and abandon wells that are part of such assets. However, in some instances, we receive an indemnity with respect to those costs.



Although we obtained environmental studies on our properties in California 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 over 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 these properties, other than our obligation to plug existing wells and those normally associated with customary oil field
operations of similarly situated properties. Current or future local, state or federal rules and regulations may require us to spend material amounts to comply with such rules and regulations, and there can be no assurance that any portion of such
amounts will be recoverable under the indemnity.



In connection with the
purchase of certain of our onshore California properties, each year we are required to plug and abandon 20% of the then remaining inactive wells (there were 158 inactive wells at December 31, 2003). If we do not meet this commitment, and the
requirement is not waived, we must escrow funds to cover the cost of the wells that were not abandoned. To date we have not been required to escrow any funds. In addition, until the end of 2005, we are required to spend at least $600,000 per year
(and $300,000 per year from 2006 through 2010) to remediate oil contaminated soil from existing well sites that require remediation.



Spin-off Agreements



In connection with the spin-off we entered into certain agreements with Plains Resources, including a master separation agreement; an intellectual property
agreement; the Plains Exploration & Production transition services agreement; the Plains Resources transition services agreement; and a technical services agreement. For the year ended December 31, 2003, Plains Resources billed us $0.1 million
for services provided to us under these agreements and we billed Plains Resources $0.5 million for services we provided under these agreements.



The master separation agreement provides that for a period of three years, (1) Plains Resources 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 oil and 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 oil and gas (except to the extent any such activities are ancillary to, or in support of, any of our upstream activities).



The technical services agreement provides that we will provide services
with respect to the operations of Plains Resources upstream subsidiary, Calumet Florida Inc. 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 the 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.



21



---

##### Table of Contents

Employees



As of February 29, 2004 we had 424 full-time employees, 213 of whom were field personnel involved in oil and gas producing activities. We believe our relationship
with our employees is good. None of our employees is represented by a labor union.



Risk Factors



You should carefully consider the
following risk factors in addition to the other information included in this report. Each of these risk factors could adversely affect our business, operating results and financial condition, as well as adversely affect the value of an investment in
our common stock.



Our levels of indebtedness may limit our
financial and operating flexibility.



We have a substantial
amount of debt and the ability to incur substantially more debt. We have outstanding a total of $275.0 million of 8.75% senior subordinated notes due in 2012 which are supported by guarantees of our subsidiaries. In addition, we have a $500.0
million revolving credit facility, which is collateralized by a pledge of the equity of our subsidiaries and substantially all of our other assets and supported by guarantees of our subsidiaries. At February 29, 2004 we had $212.0 million
outstanding under this credit facility. We will incur substantial additional indebtedness in connection with the Nuevo acquisition.



We have been assigned a Ba3 senior implied rating and our 8.75% senior subordinated notes have been assigned a B2 rating by Moodys Investor Service Inc. We
have also been assigned a BB- corporate credit rating by Standard and Poors Ratings Group. All of these ratings are below investment grade. As a result, at times we may have difficulty accessing capital markets or raising capital on favorable
terms as we will incur higher borrowing costs than our competitors that have higher ratings. Therefore, our financial results may be negatively affected by our inability to raise capital or the cost of such capital as a result of our credit ratings.



We and all of our restricted subsidiaries must comply with various
covenants contained in our revolving credit facility, the indenture related to our senior subordinated notes and any of our future debt arrangements which, among other things, limit the ability of us and those subsidiaries to:



| |  |  | incur additional debt or liens;
| | - |  | -------------------------------



| |  |  | make payments in respect of or redeem or acquire any debt or equity issued by us;
| | - |  | ---------------------------------------------------------------------------------



| |  |  | sell assets;
| | - |  | ------------



| |  |  | make loans or investments;
| | - |  | --------------------------



| |  |  | acquire or be acquired by other companies; and
| | - |  | ----------------------------------------------



| |  |  | amend some of our contracts.
| | - |  | ----------------------------



Our substantial debt could have important consequences to you. For example, it could:



| |  |  | increase our vulnerability to general adverse economic and industry conditions;
| | - |  | -------------------------------------------------------------------------------



| |  |  | limit our ability to fund future working capital and capital expenditures, to engage in future acquisitions, or development activities, or to otherwise realize the value of our assets and
opportunities fully because of the need to dedicate a substantial portion of our cash flow from operations to payments on our debt or to comply with any restrictive terms of our debt;
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



22



---

##### Table of Contents

| |  |  | limit our flexibility in planning for, or reacting to, changes in the industry in which we operate; and
| | - |  | -------------------------------------------------------------------------------------------------------



| |  |  | place us at a competitive disadvantage as compared to our competitors that have less debt.
| | - |  | ------------------------------------------------------------------------------------------



In addition, if we fail to comply with the terms of any of our debt, our lenders will have the right to accelerate the maturity of
that debt and foreclose upon the collateral, if any, securing that debt. Realization of any of these factors could adversely affect our financial condition.



Plains will incur significant charges and expenses as a result of the Nuevo acquisition which will reduce the amount of capital available to fund its
operations.



Plains and Nuevo expect to incur approximately $32
million of costs related to the merger. These expenses will include investment banking, bank commitment, legal, accounting and reserve engineering fees, printing costs, transition costs, severance payments to Nuevo management and other related
charges. We may also incur unanticipated costs in the acquisition. As a result, we will have less capital available to fund its exploitation, exploration and development activities.



Our results of operations could be adversely affected as a result of goodwill impairments.



In a purchase transaction, goodwill represents the excess of the purchase price plus
the liabilities assumed, including deferred income taxes recorded in connection with the merger, over the fair value of the net assets acquired. In our acquisition of 3TEC, goodwill totaled $147.3 million and represents 12% of our total assets at
December 31, 2003.



Goodwill is not amortized, but instead must be tested
at least annually for impairment by applying a fair-value based test. Goodwill is deemed impaired to the extent of any excess of its carrying amount over the residual fair value of the reporting unit. Such impairment could significantly reduce
earnings during the period in which the impairment occurs and would result in a corresponding reduction to goodwill and stockholders equity. The most significant factors that could result in the impairment of our goodwill would be significant
declines in oil and gas prices and/or reserve volumes which would result in a decline in the fair value of our oil and gas properties.



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.
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 including the possibility of insurgency or war in such areas;
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------



| |  |  | the prices of foreign exports and the availability of alternate fuel sources;
| | - |  | -----------------------------------------------------------------------------



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



| |  |  | governmental regulations.
| | - |  | -------------------------



23



---

##### Table of Contents

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



| |  |  | our revenues, cash flows, profitability 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. We may also have to shut-in some of our wells temporarily due to a lack of market or adverse weather conditions including hurricanes. If the
demand for oil and gas diminishes, our financial results would be negatively impacted.



In addition, there are limitations related to the methods of transportation for our production. Substantially all of our oil and gas production is transported by pipelines and trucks 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.



The United States activities in Iraq, recent terrorist activities and the potential for other global events could adversely affect our business.



The United States activities in Iraq and recent terrorist
attacks of unprecedented scope have caused instability in the world financial markets and may generate global economic instability. The continued threat of terrorism and the impact of military or other action have led to and will likely lead to
increased volatility in prices for oil and gas and could affect the markets for our operations. Further, the United States government has issued public warnings that indicate that energy assets might be specific targets of terrorist organizations.
As a result of such a terrorist attack or of terrorist activities in general, the ability to obtain insurance coverages and other coverages and endorsements at prices that we consider reasonable may not be available. These developments have
subjected our operations to increased risk and, depending on the ultimate magnitude, could have a material adverse affect on our business.



Our oil production in California and Illinois 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 Plains All
American Pipeline, L.P., or PAA, under which PAA is the exclusive purchaser of all of our net oil production in California. 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



24



---

##### Table of Contents

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 may not 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, our exploitation and development and exploration operations may not 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 would 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.



Furthermore, exploration for oil and gas, particularly offshore, has inherent and historically higher risk than exploitation and development activities. Future
reserve increases and production may be dependent on our success in our exploration efforts, which may be unsuccessful.



Estimates of oil and gas reserves depend on many assumptions that may be inaccurate. Any material inaccuracies could adversely affect the quantity and value
of our oil and gas reserves.



The proved oil and gas reserve
information included in this document 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 reports.
Any significant price changes will have a material effect on the quantity and 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.
| | - |  | -----------------------------------------------------------------------------------------------------------------------------



25



---

##### Table of Contents

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 document 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.



The geographic concentration and lack of marketable characteristics of our oil reserves may have a greater effect on our ability
to sell our oil compared to other companies.



A substantial
portion of our oil and gas reserves are located in California. Because our reserves are not as diversified geographically as many of our competitors, our business is more subject to local conditions than other, more diversified companies. Any
regional events, including price fluctuations, natural disasters, and restrictive regulations, that increase costs, reduce availability of equipment or supplies, reduce demand or limit our production may impact our operations more than if our
reserves were more geographically diversified.



Our California oil
production averages 23 degrees API gravity, which is heavier than premium grade light oil. Due to the processes required to refine this type of oil and the transportation requirements, it is difficult to market our oil outside California.
Additionally, the margin (sales price minus production costs) on heavy oil sales is generally less than that of lighter oil due to price differentials, and the effect of material price decreases will more adversely affect the profitability of heavy
oil production compared with lighter oil grades.



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;
| | - |  | ----------



26



---

##### Table of Contents

| |  |  | explosions;
| | - |  | -----------



| |  |  | uncontrollable flows of oil, gas or well fluids;
| | - |  | ------------------------------------------------



| |  |  | fires;
| | - |  | ------



| |  |  | pollution; and
| | - |  | --------------



| |  |  | releases of toxic gas.
| | - |  | ----------------------



In addition, our operations in California are especially susceptible to damage from natural disasters such as earthquakes, mudslides and fires. Any of these operating hazards could cause serious injuries, fatalities, oil
spills, discharge of hazardous materials, remediation and clean-up costs and other environmental damages, 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. The insurance
market in general and the energy insurance market in particular have been difficult markets over the past several years. As a result, we do not believe that insurance coverage for the full potential liability, especially environmental liability, is
currently available at reasonable cost. 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.



Our offshore operations are subject to substantial regulations and risks, which could adversely affect our ability to operate and our financial results.



We conduct operations offshore California and Louisiana. Our
offshore 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:



| |  |  | hurricanes and other adverse weather conditions;
| | - |  | ------------------------------------------------



| |  |  | oil field service costs and availability;
| | - |  | -----------------------------------------



| |  |  | compliance with environmental and other laws and regulations;
| | - |  | -------------------------------------------------------------



| |  |  | remediation and other costs resulting from oil spill releases of hazardous materials and other environmental damages; and
| | - |  | -------------------------------------------------------------------------------------------------------------------------



| |  |  | failure of equipment or facilities.
| | - |  | -----------------------------------



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



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 much authority relating to the exploration for, and the development, production and transportation of, oil and gas, as well as environmental and safety matters. Existing laws and regulations could be changed, and any changes could
increase costs of compliance and costs of operating drilling equipment or significantly limit drilling activity.



27



---

##### Table of Contents

Under certain circumstances, the United States Minerals Management Service, or MMS, 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. The requirements imposed by these laws and regulations are frequently changed
and subject to new interpretations.



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, 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 and impose strict requirements for, among other things:



| |  |  | well drilling or workover, 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.



In addition, environmental laws may, 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.



Some fields in our onshore California and Illinois Basin properties have been in operation for more than 90 years, and current or future local, state and federal
environmental and other laws and regulations may require substantial expenditures to remediate the properties or to otherwise comply with these laws and regulations. In addition, approximately 183 acres of our 480 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. A variety of existing laws, rules and guidelines govern
activities that can be conducted on properties that contain coastal sage scrub and gnatcatchers and generally limit the scope of operations that we can conduct on this property. The presence of coastal sage scrub and gnatcatchers in the Montebello
field and other existing or future laws, rules and guidelines could prohibit or limit our operations and our planned activities for this property.



28



---

##### Table of Contents

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 may not 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 of the acquired companies;
| | - |  | ----------------------------------------------------------



| |  |  | difficulty in assuming recoverable reserves, future production rates, operating costs, infrastructure requirements, environmental and other liabilities, and other factors beyond our control;
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | 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 the 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 also prevents
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 must 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, if we have less production than we have hedged when the floating price exceeds the fixed price, we must make payments against which there are 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 if the counterparty to a hedging contract defaults
on its contract obligations.



Loss of key executives and failure to
attract qualified management could limit our growth and negatively impact our operations.



Successfully implementing our strategies will depend, in part, on our management team. The loss of members of our management team could have an adverse effect on
our business. Our exploration and exploitation success and the success of other activities integral to our operations will depend, in part, on our ability to attract and retain experienced engineers, geoscientists and other professionals.
Competition for experienced professionals is extremely intense. If we cannot attract or retain experienced technical personnel, our ability to compete could be harmed. Plains does not have key man insurance.



29



---

##### Table of Contents

Under our tax allocation agreement with our former parent Plains Resources, 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 the resulting tax liability and may not have sufficient financial resources to
achieve our growth strategy or ability to repay debt or may prevent a change in control of us.



We have agreed with Plains Resources that we will not take any action inconsistent with any information, covenant or representation provided to the Internal Revenue
Service in connection with obtaining the tax ruling stating that the spin-off will generally be tax-free to Plains Resources and its stockholders and we further agreed to be liable for any taxes arising from a breach of that agreement. In addition,
we have agreed that, for three years following the spin-off, we will not engage in any transaction that could adversely affect the tax treatment of the spin-off without the prior written consent of Plains Resources, unless we obtains a supplemental
tax ruling from the Internal Revenue Service 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-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 would likely
result in events of default under all of our credit arrangements. As a result, we likely would not have sufficient financial resources to achieve our growth strategy or, possibly, repay our indebtedness after making these payments.



As a result of the tax principles and agreements with Plains Resources discussed above,
we may be highly limited in our ability to take the following steps in the future:



| |  |  | issue equity in public or private offerings;
| | - |  | --------------------------------------------



| |  |  | issue equity as part of the consideration in acquisitions of additional assets; or
| | - |  | ----------------------------------------------------------------------------------



| |  |  | undergo a change of control.
| | - |  | ----------------------------



Our net income could be adversely affected by stock appreciation rights charges.



As part of the spin-off, all outstanding options to acquire Plains Resources common stock at the time of the spin-off were
split between Plains Resources stock options and stock appreciation rights with respect to our common stock.



Stock appreciation rights are subject to variable accounting treatment. As a result, at the end of each quarter, we compare the per share closing price of our
common stock to the exercise price of each stock appreciation right that is vested or for accounting purposes is deemed vested at the end of the quarter. To the extent the closing price exceeds the exercise price, we will recognize the excess as an
accounting charge to the extent we did not previously recognize such excess. If, at the end of the quarter, the per share closing price of our common stock decreased, the stock appreciation right accounting charge would decrease, resulting in
increased net income for Plains. In 2003 we recognized $18.0 million of SAR expense.



30



---

##### Table of Contents

Item 3.Legal Proceedings



We are a defendant in various lawsuits arising in the ordinary course of our business. While the outcome of these lawsuits cannot be predicted with certainty and
could have a material adverse effect on our financial position, 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.



In September 2002, Stocker Resources Inc., or Stocker, our
general partner before we converted from a limited partnership to a corporation, filed a declaratory judgment action against Commonwealth Energy Corporation, or Commonwealth, in the Superior Court of Orange County, California relating to the
termination of an electric service contract. Stocker was seeking a declaratory judgment that it was entitled to terminate the contract and that Commonwealth had no basis for proceeding against Stockers related $1.5 million performance bond.
Also in September 2002, Stocker was named a defendant in an action brought by Commonwealth in the Superior Court of Orange County, California for breach of the electric service contract. In January 2004 Plains Resources signed a settlement agreement
with Commonwealth. Under the terms of our master separation agreement with Plains Resources, we indemnified them for damages they might incur as a result of this action. As such, we reimbursed Plains Resources settlement amount.



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



No matters were submitted to a vote of the security holders, through solicitation of proxies or otherwise, during the fourth quarter of the fiscal year covered by
this report.



Directors and Executive Officers of Plains Exploration & Production
Company



Listed below are our directors and executive officers,
their age as of February 29, 2003 and their business experience for the last five years.



Directors



James C. Flores, age 44,
Chairman of the Board, Chief Executive Officer and a Director since September 2002 and President since March 2004.    He also has been Plains Resources Chairman of the Board since December 2002. He was Chairman of the
Board and Chief Executive Officer of Plains Resources from May 2001 to December 2002. He was Co-founder and Chairman from inception of Ocean Energy Inc., an oil and gas company, and, at various times, President and Chief Executive Officer from 1992
until March 1999. In March 1999 Ocean Energy, Inc. was merged into Seagull Energy Corporation where 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. From January 2001 to May 2001 Mr. Flores managed various private investments.



Alan R. Buckwalter, III, age 57, Director since March 2003.    He retired in January 2003 as Chairman of JPMorgan Chase Bank, South
Region, a position he had held since 1998. From 1990 to 1998 he was President of Texas Commerce Bank-Houston, the predecessor entity of JPMorgan Chase Bank. Prior to 1990 Mr. Buckwalter held various executive management positions within the
organization. Mr. Buckwalter currently serves on the board of Service Corporation International (SCI), the Texas Medical Center, the Greater Houston Area Red Cross, the University of St. Thomas and St. Lukes Hospital System. He sits on the
Audit Committee and is Chairman of the Compensation Committee for SCI.



Jerry L. Dees, age 64, Director since September 2002.    He also was a director of Plains Resources from 1997 to December 2002. He retired in 1996 as Senior Vice President, Exploration and



31



---

##### Table of Contents

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, age 63, Director since September
2002.    He also was a director of Plains Resources from 1988 to December 2002. 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
publicly-traded energy services company. He currently serves as Chairman for three privately-owned companies. Previously, he has served as President and CEO for Magna Corporation, (now Baker Petrolite, a unit of Baker Hughes). From 1983 to 1988, Mr.
Delimitros was a General Partner of Sunwestern Investment Funds and Senior Vice President of Sunwestern Management, Inc.



John H. Lollar, age 65, Director since September 2002.    He also was a director of Plains Resources from 1995 to December 2002. 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, where he is a member of the Compensation Committee and Chair of the Audit Committee. 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.



Executive Officers



Stephen A. Thorington, age 48, Executive Vice President and Chief Financial Officer since September
2002.    He also has been Plains Resources Executive Vice President and Chief Financial Officer since February 2003. He was Plains Resources Acting Executive Vice President and Chief Financial Officer from
December 2002 to February 2003. Previously, he was Senior Vice PresidentFinance and Corporate Development of Ocean Energy, Inc. from July 2001 to September 2002 and Senior Vice PresidentFinance, Treasury and Corporate Development of
Ocean Energy, Inc. from March 1999 to July 2001. He also served as Vice President, Finance and Treasurer of Seagull Energy Corporation from May 1996 to March 1999. Mr. Thorington served as a Managing Director of Chase Securities, Inc. from April
1994 to May 1996.



John F. Wombwell, age 42, has been Executive
Vice President, General Counsel and Secretary of our company and of Plains Resources since September 2003. Prior to Plains Exploration and Production Company, Mr. Wombwell was General Counsel of ExpressJet Airlines, Inc. from April 2002 to September
2003 and Integrated Electrical Services, Inc. from January 1998 to April 2002. Prior to that time, Mr. Wombwell was a partner at the law firm of Andrews & Kurth L.L.P., where he practiced law in the area of corporate and securities matters,
representing a variety of public companies.



Thomas M. Gladney, age
51, Executive Vice PresidentExploration & Production since June 2003.    He was our Senior Vice President of Operations from September 2002 to June 2003. He also was Plains Resources Senior Vice President of
Operations from November 2001 to December 2002. He was President of Arguello, Inc., a subsidiary of Plains, from December 1999 to November 2001. From July 1999 to December 1999 he served as a Project Manager for Torch Energy Services, a contract
operating services company. From January 1999 to June 1999 he served as a Project Manager for Venoco Inc., an oil and gas company. From September 1998 to January 1999 he was a self-employed engineering services consultant. 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.



Cynthia A. Feeback, age 46, Senior Vice PresidentAccounting and Treasurer since September
2002.    She also was Plains Resources Senior Vice PresidentAccounting and Treasurer from July



32



---

##### Table of Contents

2001 to December 2002. 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.



Item 5.Market for Registrants Common Stock and Related Stockholder Matters



Price Range of Common stock



Our common stock is listed on the New York Stock Exchange under the symbol PXP and began trading on December 18, 2002. The number of stockholders of
record of our common stock on February 29, 2004 was 1,352. The following table sets forth the range of high and low sales prices for our common stock as reported on the New York Stock Exchange Composite Tape for the periods indicated below:



|            |  |      |       |     |   |      
|----------- |  | ---- | ----- | --- | - | -----
|            |  | High |       | Low
|2003        |  |      |       |     |   |      
|1st Quarter |  | $    | 10.39 |     | $ | 8.25 
|2nd Quarter |  |      | 11.23 |     |   | 8.08 
|3rd Quarter |  |      | 13.00 |     |   | 10.26
|4th Quarter |  |      | 16.15 |     |   | 12.55
|2002        |  |      |       |     |   |      
|4th Quarter |  | $    | 10.30 |     | $ | 8.70 



Dividend Policy



We do not anticipate declaring or paying any cash dividends in the future. 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. Our credit facility and the indenture relating to our 8.75% senior subordinated notes restrict our ability to pay cash dividends.



33



---

##### Table of Contents

Item 6.Selected Financial Data



The following selected financial information was derived from, and is qualified by reference to, our consolidated financial statements, including the notes thereto,
appearing elsewhere in this report. You should read this information in conjunction with Managements Discussion and Analysis of Financial Condition and Results of Operations and our consolidated financial statements and notes
thereto. This information is not necessarily indicative of our future results.



|                                                                      |  |                         |         |   |      |   |         |      |  |   |         |   |  |      |         |   |  |   |         |  
|--------------------------------------------------------------------- |  | ----------------------- | ------- | - | ---- | - | ------- | ---- |  | - | ------- | - |  | ---- | ------- | - |  | - | ------- | -
|                                                                      |  | Year Ended December 31, |        
|                                                                      |  | 2003(1)                 |         |   | 2002 |   |         | 2001 |  |   | 2000    |   |  | 1999 |        
|Revenues                                                              |  |                         |         |   |      |   |         |      |  |   |         |   |  |      |         |   |  |   |         |  
|Oil sales to Plains All American Pipeline, L.P.                       |  | $                       | 238,663 |   |      | $ | 193,615 |      |  | $ | 174,613 |   |  | $    | 199,233 |   |  | $ | 109,863 |  
|Other oil sales and oil hedging                                       |  |                         | (40,515 | ) |      |   | (15,577 | )    |  |   | 282     |   |  |      | (72,799 | ) |  |   | (7,473  | )
|Gas sales and gas hedging                                             |  |                         | 105,054 |   |      |   | 10,299  |      |  |   | 28,771  |   |  |      | 16,017  |   |  |   | 5,095   |  
|Other operating revenues                                              |  |                         | 888     |   |      |   | 226     |      |  |   | 473     |   |  |      |        |   |  |   |        |  
|                                                                      |  |                         |         |   |      |   |         |      |  |   |         |   |  |      |         |   |  |   |         |  
|                                                                      |  |                         | 304,090 |   |      |   | 188,563 |      |  |   | 204,139 |   |  |      | 142,451 |   |  |   | 107,485 |  
|                                                                      |  |                         |         |   |      |   |         |      |  |   |         |   |  |      |         |   |  |   |         |  
|Costs and Expenses                                                    |  |                         |         |   |      |   |         |      |  |   |         |   |  |      |         |   |  |   |         |  
|Production expenses                                                   |  |                         | 104,819 |   |      |   | 78,451  |      |  |   | 63,795  |   |  |      | 56,228  |   |  |   | 50,527  |  
|General and administrative                                            |  |                         |         |   |      |   |         |      |  |   |         |   |  |      |         |   |  |   |         |  
|G&A excluding items below                                             |  |                         | 19,884  |   |      |   | 10,756  |      |  |   | 10,210  |   |  |      | 6,308   |   |  |   | 4,367   |  
|Stock appreciation rights                                             |  |                         | 18,010  |   |      |   | 3,653   |      |  |   |        |   |  |      |        |   |  |   |        |  
|Merger costs                                                          |  |                         | 5,264   |   |      |   |        |      |  |   |        |   |  |      |        |   |  |   |        |  
|Spin-off costs                                                        |  |                         |        |   |      |   | 777     |      |  |   |        |   |  |      |        |   |  |   |        |  
|Depreciation, depletion, amortization and accretion                   |  |                         | 52,484  |   |      |   | 30,359  |      |  |   | 24,105  |   |  |      | 18,859  |   |  |   | 13,329  |  
|                                                                      |  |                         |         |   |      |   |         |      |  |   |         |   |  |      |         |   |  |   |         |  
|                                                                      |  |                         | 200,461 |   |      |   | 123,996 |      |  |   | 98,110  |   |  |      | 81,395  |   |  |   | 68,223  |  
|                                                                      |  |                         |         |   |      |   |         |      |  |   |         |   |  |      |         |   |  |   |         |  
|Income from Operations                                                |  |                         | 103,629 |   |      |   | 64,567  |      |  |   | 106,029 |   |  |      | 61,056  |   |  |   | 39,262  |  
|Other Income (Expense)                                                |  |                         |         |   |      |   |         |      |  |   |         |   |  |      |         |   |  |   |         |  
|Interest expense                                                      |  |                         | (23,778 | ) |      |   | (19,377 | )    |  |   | (17,411 | ) |  |      | (15,885 | ) |  |   | (14,912 | )
|Derivative gain (loss)                                                |  |                         | 847     |   |      |   |        |      |  |   |        |   |  |      |        |   |  |   |        |  
|Interest and other income (expense)                                   |  |                         | (159    | ) |      |   | 174     |      |  |   | 463     |   |  |      | 343     |   |  |   | 87      |  
|Expenses of terminated public equity offering                         |  |                         |        |   |      |   | (2,395  | )    |  |   |        |   |  |      |        |   |  |   |        |  
|                                                                      |  |                         |         |   |      |   |         |      |  |   |         |   |  |      |         |   |  |   |         |  
|Income Before Income Taxes and Cumulative Effect of Accounting Change |  |                         | 80,539  |   |      |   | 42,969  |      |  |   | 89,081  |   |  |      | 45,514  |   |  |   | 24,437  |  
|Income tax (expense) benefit                                          |  |                         |         |   |      |   |         |      |  |   |         |   |  |      |         |   |  |   |         |  
|Current                                                               |  |                         | (1,224  | ) |      |   | (6,353  | )    |  |   | (6,014  | ) |  |      | (2,431  | ) |  |   | (505    | )
|Deferred                                                              |  |                         | (32,228 | ) |      |   | (10,379 | )    |  |   | (28,374 | ) |  |      | (14,334 | ) |  |   | (4,827  | )
|                                                                      |  |                         |         |   |      |   |         |      |  |   |         |   |  |      |         |   |  |   |         |  
|Income Before Cumulative Effect of Accounting Changes                 |  |                         | 47,087  |   |      |   | 26,237  |      |  |   | 54,693  |   |  |      | 28,749  |   |  |   | 19,105  |  
|Cumulative effect of accounting change, net of tax benefit (2)        |  |                         | 12,324  |   |      |   |        |      |  |   | (1,522  | ) |  |      |        |   |  |   |        |  
|                                                                      |  |                         |         |   |      |   |         |      |  |   |         |   |  |      |         |   |  |   |         |  
|Net Income                                                            |  | $                       | 59,411  |   |      | $ | 26,237  |      |  | $ | 53,171  |   |  | $    | 28,749  |   |  | $ | 19,105  |  
|                                                                      |  |                         |         |   |      |   |         |      |  |   |         |   |  |      |         |   |  |   |         |  
|Earnings Per Share                                                    |  |                         |         |   |      |   |         |      |  |   |         |   |  |      |         |   |  |   |         |  
|Basic and Diluted                                                     |  |                         |         |   |      |   |         |      |  |   |         |   |  |      |         |   |  |   |         |  
|Income before cumulative effect of accounting change                  |  | $                       | 1.41    |   |      | $ | 1.08    |      |  | $ | 2.26    |   |  | $    | 1.19    |   |  | $ | 0.79    |  
|Cumulative effect of accounting change                                |  |                         | 0.37    |   |      |   |        |      |  |   | (0.06   | ) |  |      |        |   |  |   |        |  
|                                                                      |  |                         |         |   |      |   |         |      |  |   |         |   |  |      |         |   |  |   |         |  
|Net income                                                            |  | $                       | 1.78    |   |      | $ | 1.08    |      |  | $ | 2.20    |   |  | $    | 1.19    |   |  | $ | 0.79    |  
|                                                                      |  |                         |         |   |      |   |         |      |  |   |         |   |  |      |         |   |  |   |         |  

---

|(1) |  | Reflects the effect of the 3TEC merger effective June 1, 2003.
|--- |  | --------------------------------------------------------------

|(2) |  | Cumulative effect of adopting Statement of Financial Accounting Standards No. 143Accounting for Asset Retirement Obligations, or SFAS 143 in 2003 and Statement of Financial
Accounting Standards No. 133Accounting for Derivatives, or SFAS 133 in 2001.
|--- |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



Table continued on following page



34



---

##### Table of Contents

|                                                    |  |                         |           |      |   |         |      |  |      |         |  |      |         |   |  |   |        
|--------------------------------------------------- |  | ----------------------- | --------- | ---- | - | ------- | ---- |  | ---- | ------- |  | ---- | ------- | - |  | - | -------
|                                                    |  | Year Ended December 31,
|                                                    |  | 2003(1)                 |           | 2002 |   |         | 2001 |  | 2000 |         |  | 1999
|Weighted Average Common Shares Outstanding          |  |                         |           |      |   |         |      |  |      |         |  |      |         |   |  |   |        
|Basic                                               |  |                         | 33,321    |      |   | 24,193  |      |  |      | 24,200  |  |      | 24,200  |   |  |   | 24,200 
|Diluted                                             |  |                         | 33,469    |      |   | 24,201  |      |  |      | 24,200  |  |      | 24,200  |   |  |   | 24,200 
|                                                    |  |                         |           |      |  
|Cash Flow Data                                      |  |                         |           |      |   |         |      |  |      |         |  |      |         |   |  |   |        
|Net cash provided by operating activities           |  | $                       | 118,278   |      | $ | 78,826  |      |  | $    | 116,808 |  | $    | 79,464  |   |  | $ | 4,609  
|Net cash used in investing activities               |  |                         | 368,710   |      |   | 64,158  |      |  |      | 125,880 |  |      | 70,871  |   |  |   | 59,362 
|Net cash provided by (used in) financing activities |  |                         | 250,781   |      |   | (13,653 | )    |  |      | 8,549   |  |      | (13,132 | ) |  |   | 59,690 
|                                                    | 
|                                                    |  | As of December 31,     
|                                                    |  | 2003(1)                 |           | 2002 |   |         | 2001 |  | 2000 |         |  | 1999
|Balance Sheet Data                                  |  |                         |           |      |   |         |      |  |      |         |  |      |         |   |  |   |        
|Assets                                              |  |                         |           |      |   |         |      |  |      |         |  |      |         |   |  |   |        
|Cash and cash equivalents                           |  | $                       | 1,377     |      | $ | 1,028   |      |  | $    | 13      |  | $    | 536     |   |  | $ | 5,075  
|Other current assets                                |  |                         | 58,948    |      |   | 37,711  |      |  |      | 42,798  |  |      | 36,916  |   |  |   | 45,287 
|Property and equipment, net                         |  |                         | 956,895   |      |   | 493,212 |      |  |      | 455,117 |  |      | 353,344 |   |  |   | 301,332
|Goodwill                                            |  |                         | 147,251   |      |   |        |      |  |      |        |  |      |        |   |  |   |       
|Other assets                                        |  |                         | 19,641    |      |   | 18,929  |      |  |      | 18,827  |  |      | 10,239  |   |  |   | 9,270  
|                                                    |  |                         |           |      |   |         |      |  |      |         |  |      |         |   |  |   |        
|                                                    |  | $                       | 1,184,112 |      | $ | 550,880 |      |  | $    | 516,755 |  | $    | 401,035 |   |  | $ | 360,964
|                                                    |  |                         |           |      |   |         |      |  |      |         |  |      |         |   |  |   |        
|Liabilities and Stockholders Equity                |  |                         |           |      |   |         |      |  |      |         |  |      |         |   |  |   |        
|Current liabilities                                 |  | $                       | 155,086   |      | $ | 86,175  |      |  | $    | 41,879  |  | $    | 44,313  |   |  | $ | 34,193 
|Long-term debt and payable to Plains Resources      |  |                         | 487,906   |      |   | 233,166 |      |  |      | 236,183 |  |      | 226,529 |   |  |   | 239,661
|Other long-term liabilities                         |  |                         | 65,429    |      |   | 6,303   |      |  |      | 1,413   |  |      |        |   |  |   |       
|Deferred income taxes                               |  |                         | 121,435   |      |   | 51,416  |      |  |      | 57,193  |  |      | 19,161  |   |  |   | 4,827  
|Stockholders equity/combined owners equity        |  |                         | 354,256   |      |   | 173,820 |      |  |      | 180,087 |  |      | 111,032 |   |  |   | 82,283 
|                                                    |  |                         |           |      |   |         |      |  |      |         |  |      |         |   |  |   |        
|                                                    |  | $                       | 1,184,112 |      | $ | 550,880 |      |  | $    | 516,755 |  | $    | 401,035 |   |  | $ | 360,964
|                                                    |  |                         |           |      |   |         |      |  |      |         |  |      |         |   |  |   |        

---

|(1) |  | Reflects the effect of the 3TEC merger effective June 1, 2003.
|--- |  | --------------------------------------------------------------





35



---

##### Table of Contents

Item 7.Managements Discussion and Analysis of Financial Condition and Results of Operations



The following information should be read in connection with the information contained in the consolidated financial statements and
notes thereto included elsewhere in this report.



Proposed Acquisition of Nuevo Energy
Inc.



On February 12, 2004 we announced that we had entered into a
definitive agreement to acquire Nuevo Energy Company (Nuevo) in a stock for stock transaction valued at approximately $945 million, based on our February 11, 2004 closing stock price of $15.89 per share. Under the terms of the definitive
agreement, Nuevo stockholders will receive 1.765 shares of our common stock for each share of Nuevo common stock. If completed, we will issue up to 38.8 million shares to Nuevo shareholders and assume $234 million of net debt (as of December 31,
2003) and $115 million of Trust Convertible Preferred Securities.



The
transaction is expected to qualify as a tax free reorganization under Section 368(a) and is expected to be tax free to our stockholders and tax free for the stock consideration received by Nuevo stockholders. The Boards of directors of both
companies have approved the merger agreement and each has recommended it to their respective stockholders for approval. The transaction is subject to stockholder approval from both companies and other customary conditions. Post closing, it is
anticipated that PXP stockholders will own approximately 52% of the combined company and Nuevo stockholders will own approximately 48% of the combined company.



The transaction will be accounted for as a purchase of Nuevo by PXP under purchase accounting rules and PXP will continue to use the full cost method of
accounting for its oil and gas properties.



Acquisition of 3TEC Energy Corporation



On June 4, 2003, we acquired 3TEC Energy Corporation, or 3TEC, the
merger, for approximately $312.9 million in cash and common stock plus $90.0 million to retire 3TECs outstanding debt and $14.7 million to retire outstanding 3TEC preferred stock. Prior to the merger, 3TEC was engaged in the upstream
activities of acquiring, exploiting, developing and producing oil and gas in East Texas and the Gulf Coast region, both onshore and in the shallow waters of the Gulf of Mexico. In the transaction, each 3TEC common share was converted in to 0.85 of a
share of our common stock and $8.50 in cash. In connection with the merger, we paid cash consideration to the common shareholders of approximately $152.4 million and issued 15.3 million shares. In addition, we paid cash consideration of $8.3 million
and issued 0.8 million common shares to redeem outstanding warrants. The cash portion of the purchase price was funded by the issuance of $75.0 million of senior subordinated notes and amounts borrowed under our revolving credit facility. We have
accounted for the acquisition of 3TEC as a purchase effective June 1, 2003.



Corporate
Reorganization and Spin-off



Prior to December 18, 2002 we were a
wholly owned subsidiary of Plains Resources. On December 18, 2002 Plains Resources distributed 100% of the issued and outstanding shares of our common stock to the holders of record of Plains Resources common stock as of December 11, 2002.
Each Plains Resources stockholder received one share of our common stock for each share of Plains Resources common stock held. Prior to the spin-off, Plains Resources made an aggregate of $52.2 million in cash contributions to us and transferred to
us certain assets and we assumed certain liabilities of Plains Resources, primarily related to land, unproved oil and gas properties, office equipment and pension obligations. We used the cash contributions to reduce outstanding debt under our
revolving credit facility.



36



---

##### Table of Contents

In contemplation of the spin-off, under the terms of a Master Separation Agreement between us and Plains Resources,
on July 3, 2002 Plains Resources contributed to us 100% of the capital stock of its wholly owned subsidiaries that own oil and gas properties in offshore California and Illinois. As a result, we indirectly own our offshore California and Illinois
properties and directly own our onshore California properties. Plains Resources also contributed to us $256.0 million of intercompany payables that we or our subsidiaries owed to it. On July 3, 2002 we and Plains E&P Company, our wholly owned
subsidiary that has no material assets and was formed for the sole purpose of being a corporate co-issuer of certain of our indebtedness, issued $200 million of 8.75% Senior Subordinated Notes due 2012, or the 8.75% Notes. On July 3, 2002 we also
entered into a $300 million revolving credit facility. We distributed the net proceeds of $195.3 million from the 8.75% senior subordinated notes and $116.7 million of initial borrowings under our credit facility to Plains Resources.



Plains Resources received a favorable private letter ruling from the Internal Revenue
Service stating that, for United States federal income tax purposes, the distribution of our common stock qualified as a tax-free distribution under Section 355 of the Internal Revenue Code.



General



We are an independent oil and gas company primarily engaged in the activities of acquiring, exploiting, developing and producing oil
and gas in the United States. We own oil and gas properties in ten states with principal operations in:



| |  |  | the Los Angeles and San Joaquin Basins in California;
| | - |  | -----------------------------------------------------



| |  |  | the Santa Maria Basin offshore California;
| | - |  | ------------------------------------------



| |  |  | the Gulf Coast Basin onshore and offshore Louisiana; and
| | - |  | --------------------------------------------------------



| |  |  | the East Texas Basin in east Texas and north Louisiana.
| | - |  | -------------------------------------------------------



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, economic conditions, foreign imports, the actions of OPEC, political conditions in other oil-producing countries, and governmental regulation, legislation and policies. Under the SECs
full cost accounting rules, we review the carrying value of our proved oil and gas properties each quarter. 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, after giving effect to commodity derivative instruments that qualify for hedge accounting, to determine a ceiling value of our properties. The rules require a write-down if our capitalized costs exceed the allowed ceiling. 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 fluctuate in the near term.
If oil and gas prices decline significantly in the future, 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. 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 risk, we use various derivative instruments to hedge our exposure to oil and gas sales price fluctuations. Our hedging
arrangements provide us protection on the hedged volumes if these prices decline below the prices at which these hedges are set. However, if prices increase, ceiling prices in our hedges may cause us to receive less revenues on the



37



---

##### Table of Contents

hedged volumes than we would receive in the absence of hedges. Gains and losses on derivative transactions that qualify for hedge accounting are recognized as revenues
when the associated production is sold. Changes in the fair value of derivative instruments that do not qualify for hedge accounting are recognized in other income (expense).



Our oil and gas production expenses include salaries and benefits of personnel involved in production activities, electric costs,
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.



Results of Operations



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



|                                      |  |                         |        |   |      |   |        |      |  |   |        |  
|------------------------------------- |  | ----------------------- | ------ | - | ---- | - | ------ | ---- |  | - | ------ | -
|                                      |  | Year Ended December 31, |       
|                                      |  | 2003                    |        |   | 2002 |   |        | 2001 | 
|Sales Volumes                         |  |                         |        |   |      |   |        |      |  |   |        |  
|Oil and liquids (MBbls)               |  |                         | 9,267  |   |      |   | 8,783  |      |  |   | 8,219  |  
|Gas (MMcf)                            |  |                         | 18,195 |   |      |   | 3,362  |      |  |   | 3,355  |  
|MBOE                                  |  |                         | 12,300 |   |      |   | 9,343  |      |  |   | 8,778  |  
|                                      |  |                         |       
|Daily Average Sales Volumes           |  |                         |        |   |      |   |        |      |  |   |        |  
|Oil and liquids (Bbls/d)              |  |                         | 25,389 |   |      |   | 24,062 |      |  |   | 22,518 |  
|Gas (Mcfpd)                           |  |                         | 49,849 |   |      |   | 9,211  |      |  |   | 9,192  |  
|BOEPD                                 |  |                         | 33,699 |   |      |   | 25,597 |      |  |   | 24,050 |  
|                                      |  |                         |       
|Unit Economics (in dollars)           |  |                         |        |   |      |   |        |      |  |   |        |  
|Average Oil Sales Price ($/Bbl)       |  |                         |        |   |      |   |        |      |  |   |        |  
|Average NYMEX                         |  | $                       | 30.99  |   |      | $ | 26.15  |      |  | $ | 26.01  |  
|Hedging revenue (expense)             |  |                         | (5.54  | ) |      |   | (1.77  | )    |  |   | 0.03   |  
|Differential                          |  |                         | (4.07  | ) |      |   | (4.11  | )    |  |   | (4.76  | )
|                                      |  |                         |        |   |      |   |        |      |  |   |        |  
|Net realized                          |  | $                       | 21.38  |   |      | $ | 20.27  |      |  | $ | 21.28  |  
|                                      |  |                         |        |   |      |   |        |      |  |   |        |  
|Average Gas Sales Price ($/Mcf)       |  |                         |        |   |      |   |        |      |  |   |        |  
|Average NYMEX                         |  | $                       | 5.24   |   |      | $ | 3.34   |      |  | $ | 4.34   |  
|Hedging revenue (cost)                |  |                         | 0.76   |   |      |   |       |      |  |   |       |  
|Differential                          |  |                         | (0.23  | ) |      |   | (0.28  | )    |  |   | 4.24   |  
|                                      |  |                         |        |   |      |   |        |      |  |   |        |  
|Net realized                          |  | $                       | 5.77   |   |      | $ | 3.06   |      |  | $ | 8.58   |  
|                                      |  |                         |        |   |      |   |        |      |  |   |        |  
|Average Sales Price per BOE           |  | $                       | 24.65  |   |      | $ | 20.16  |      |  | $ | 23.20  |  
|Costs and Expenses per BOE            |  |                         |        |   |      |   |        |      |  |   |        |  
|Production expenses                   |  |                         | 7.49   |   |      |   | 7.94   |      |  |   | 6.86   |  
|Production and ad valorem taxes       |  |                         | 0.82   |   |      |   | 0.46   |      |  |   | 0.41   |  
|Gathering and transportation          |  |                         | 0.21   |   |      |   |       |      |  |   |       |  
|G&A                                   |  |                         |        |   |      |   |        |      |  |   |        |  
|G&A excluding items below             |  |                         | 1.62   |   |      |   | 1.15   |      |  |   | 1.16   |  
|Stock appreciation rights             |  |                         | 1.46   |   |      |   | 0.39   |      |  |   |       |  
|Merger related costs                  |  |                         | 0.43   |   |      |   |       |      |  |   |       |  
|Spinoff related costs                 |  |                         |       |   |      |   | 0.09   |      |  |   |       |  
|DD&A per BOE (oil and gas properties) |  |                         | 3.86   |   |      |   | 3.17   |      |  |   | 2.70   |  



38



---

##### Table of Contents

Comparison of Year Ended December 31, 2003 to Year Ended December 31, 2002



Net income.    We reported net income of $59.4 million, or
$1.78 per diluted share for the year ended December 31, 2003 compared to net income of $26.2 million, or $1.08 per diluted share for the year 2002. Net income in 2003 includes the effect of the 3TEC acquisition as of June 1, 2003 and an after-tax
$12.3 million credit related to the adoption of Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations.



Income before the cumulative effect of accounting change increased to $47.1 million in 2003 from $26.2 million in 2002. The improvement is primarily attributable to
higher oil and gas sales as a result of increased sales volumes due to the 3TEC acquisition and increased oil and gas prices. These increases were partially offset by expenses related to stock appreciation rights and higher production expenses due
to the 3TEC acquisition.



Oil and gas
revenues.    Oil and gas revenues increased 61%, or $114.9 million, to $303.2 million for 2003 from $188.3 million for 2002. The increase is due to increased production volumes attributable to the 3TEC acquisition and higher
realized prices.



Oil revenues increased 11%, or $20.1 million, to $198.1
million for 2003 from $178.0 million for 2002. A 6%, or 0.5 million barrel, increase in 2003 production volumes to 9.3 million barrels increased revenues by $9.8 million and higher realized prices increased revenues by $10.3 million. The 3TEC
acquisition accounted for 0.4 million barrels of increased production.



Our average realized price for oil increased 5%, or $1.11, to $21.38 per Bbl for 2003 from $20.27 per Bbl for 2002. The increase is attributable to an improvement in the NYMEX oil price, which averaged $30.99 per Bbl in 2003 versus $26.15
per Bbl in 2002. Hedging had the effect of decreasing our average price per Bbl by $5.54 in 2003 compared to $1.77 per Bbl in 2002.



Gas revenues increased $94.8 million, to $105.1 million for the 2003 from $10.3 million for 2002. A 441% increase in 2003 production volumes to 18.2 Bcf increased
revenues by $45.4 million and higher realized prices increased revenues by $49.4 million. The 3TEC acquisition accounted for 15.1 Bcf of 2003 production.



Our average realized price for gas increased 89%, or $2.71, to $5.77 per Mcf for 2003 from $3.06 per Mcf for 2002. The increase is primarily attributable to an
improvement in the NYMEX gas price, which averaged $5.24 per Mcf in 2003 versus $3.34 in 2002 and the effects of hedging. Hedging revenues increased our average price per Mcf by $0.76 in 2003. The average location and quality differential for our
gas production improved from $0.28 per Mcf in 2002 to $0.23 in 2003.



Production expenses.    Production expenses increased 24%, or $17.9 million, to $92.1 million for 2003 from $74.2 million for 2002, primarily from an increased ownership percentage in our offshore California
properties and the acquisition of the 3TEC properties. The 3TEC properties accounted for $9.2 million of 2003 production expenses. On a per unit basis, production expenses decreased to $7.49 per BOE in 2003 versus $7.94 per BOE in 2002 due to the
3TEC properties that have lower per unit operating expenses than our other properties.



Production and ad valorem taxes.    Production and ad valorem taxes increased 136%, or $5.8 million, to $10.1 million for 2003 from $4.3 million for 2002 due to the 3TEC acquisition. Production and ad
valorem taxes for 2003 include $5.7 million attributable to the 3TEC properties.



Gathering and transportation expenses.    Gathering and transportation expense, which totaled $2.6 million in 2003, represents costs incurred to deliver oil and gas produced from certain of the 3TEC properties to
the sales point.



39



---

##### Table of Contents

General and administrative expense.    G&A, expense, excluding amounts attributable
to stock appreciation rights and merger-related costs, increased 85%, or $9.1 million, to $19.9 million for 2003 from $10.8 million for 2002. The increase is primarily a result of our reorganization and spin-off, reflecting the incremental costs of
operating as a separate, publicly held company and to increased costs resulting from the 3TEC acquisition.



G&A expense for 2003 includes a charge of $18.0 million related to outstanding SARs. Accounting for SARs requires that we record an expense or credit to the
income statement depending on whether, during the period, our stock price either rose or fell, respectively. Accordingly, since our stock price at December 31, 2003 was $15.39 as compared to $9.75 on December 31, 2002 we recorded an expense.
Included in the 2003 expense amount is $2.1 million of cash payments for SARs exercised during the year. G&A expense for 2002 includes a non-cash charge of $3.7 million related to outstanding SARs.



G&A expense in 2003 includes $5.3 million of merger related expenses consisting
primarily of severance and other compensation costs and accounting system integration and conversion expenses. G&A expense for 2002 includes $0.8 million of expenses related to the spin-off.



G&A expense does not include amounts capitalized as part of our acquisition,
exploration and development activities. We capitalized $11.0 million and $6.0 million of G&A expense in 2003 and 2002, respectively.



Depreciation, depletion, amortization and accretion, or DD&A.    DD&A expense increased 73%, or $22.1 million, to $52.5 million
for 2003 from $30.4 million for 2002. Approximately $17.9 million of the increase was attributable to our oil and gas DD&A due to a higher per unit rate and higher production. Our oil and gas unit of production rate increased to $3.86 per BOE in
2003 compared to $3.17 per BOE in 2002. The increase primarily reflects the effect of the 3TEC acquisition. Other DD&A expense increased approximately $1.6 million, primarily from amortization of debt issue costs related to our senior
subordinated debt and our revolving credit facility. Accretion expense for 2003 was $2.6 million. Accretion expense represents the adjustment of our asset retirement obligation to its present value at the end of the period based.



Interest expense.    Interest expense increased 23%, or $4.4
million, to $23.8 million for 2003 from $19.4 million for 2002 due to higher outstanding debt as a result of the merger. Interest expense does not include interest capitalized on oil and gas properties not subject to amortization. We capitalized
approximately $3.2 million and $2.4 million of interest in 2003 and 2002, respectively.



Expenses of terminated public equity offering.    In conjunction with the termination of our proposed initial public equity offering we expensed costs incurred of $2.4 million in 2002.



Income tax expense.    Income tax expense increased to $33.5
million for 2003 from $16.7 million for 2002. Our overall effective tax rate increased to 42% in 2003 from 39% in 2002. Our currently payable effective tax rate was 2% for 2003 as compared to 14.8% for 2002. The decreased currently payable effective
rate in 2003 primarily reflects the treatment for tax purposes of certain items that are capitalized for financial reporting purposes. Tax expense and effective tax rates for the periods prior to our spin-off on December 18, 2002 were calculated
based on the tax sharing agreement with Plains Resources.



Income tax
expense for 2003 includes a net $1.7 million charge (a $3.8 million charge to deferred tax expense that includes a $1.7 million adjustment to reflect an increase in our effective state income tax rate and a $2.1 million credit (benefit) to current
tax expense) to reflect differences between our provision for income taxes for the year ended December 31, 2002 and the final 2002 tax returns filed by us and Plains Resources. Such adjustment primarily relates to differences in the treatment of
certain items related to our oil and gas operations.



40



---

##### Table of Contents

Cumulative effect.    The cumulative effect of accounting change recognized for the
first quarter of 2003 was for the adoption of Statement of Financial Accounting Standards No. 143 Accounting for Asset Retirement Obligations, as amended.



Comparison of Year Ended December 31, 2002 to Year Ended December 31, 2001



Net income.    We reported net income of $26.2 million, or $1.08 per diluted share for the year
ended December 31, 2002 compared to net income of $53.2 million, or $2.20 per diluted share for 2001. A discussion of the reasons for the decrease follows.



Oil and gas revenues.    Oil and gas revenues decreased 8%, or $15.4 million, to $188.3 million for 2002
from $203.7 million for 2001. The decrease is due to lower realized gas prices that were partially offset by higher production volumes.



Oil revenues increased 2%, or $3.1 million, to $178.0 million for 2002 from $174.9 million for 2001. A 7%, or 0.6 million barrel, increase in 2002 production
volumes to 8.8 million barrels increased revenues by $12.0 million.



Our
average realized price for oil decreased 5%, or $1.01, to $20.27 per Bbl for 2002 from $21.28 per Bbl for 2001. The decrease is attributable to hedging which had the effect of decreasing our average price per Bbl by $1.77 in 2002 compared to an
increase of $0.03 per Bbl in 2001. The effects of hedging were partially offset by a slight increase in the average NYMEX oil price to $26.15 per Bbl in 2002 versus $26.01 per Bbl in 2001 and an improvement in our location and quality differential
to $4.11 per Bbl in 2002 versus $4.76 per Bbl in 2001.



Gas revenues
decreased $18.5 million, to $10.3 million for 2002 from $28.8 million for 2001 primarily due to a $5.52 per Mcf decrease in realized gas prices.



Our average realized price for gas decreased 64%, or $5.52, to $3.06 per Mcf for 2002 from $8.58 per Mcf for 2001. The decrease is primarily attributable to a
premium we received for our California gas production in 2001. In 2001, the differential to NYMEX for our gas production was an increase of $4.24 per Mcf from the NYMEX gas price compared to a negative differential of $0.28 per Mcf in 2002.



Production expenses.    Our production
expenses increased 23%, or $14.0 million, to $74.2 million for the year ended December 31, 2002 from $60.2 million for the year ended December 31, 2001. On a per unit basis, production expenses increased 16%, or $1.08 per BOE, to $7.94 per BOE for
the year ended December 31, 2002 from $6.86 per BOE for the year ended December 31, 2001. Production expenses for 2001 were reduced by approximately $0.25 per BOE as a result of nonrecurring credits (primarily the sale of certain California
emissions credits). Excluding these credits, production expenses increased 12% per BOE in 2002, primarily due to increased workover and maintenance expense, insurance expense and electricity costs in California as well as our increased ownership
percentage in the offshore California properties, which have a higher per unit production cost than our other properties.



Production and ad valorem taxes.    Production and ad valorem taxes increased 19% to $4.3 million in 2002 versus $3.6 million in 2001 due
to higher property valuations as a result of increased prices.



General and administrative expense.    Our general and administrative, or G&A, expense, excluding amounts attributable to stock appreciation rights and costs related to our spin-off from Plains Resources,
increased 6%, or $0.6 million, to $10.8 million in 2002 from $10.2 million in 2001. This



41



---

##### Table of Contents

increase was primarily due to higher personnel cost. G&A expense for 2002 includes approximately $0.8 million of legal and other costs related to our spin-off and
approximately $3.7 million of expense attributable to the in-the-money value of stock appreciation rights issued on the spin-off date. G&A expense does not include amounts capitalized as part of our acquisition, exploration and development
activities. We capitalized $6.3 million and $6.2 million of G&A expense in 2002 and 2001, respectively.



Depreciation, depletion amortization and accretion.    DD&A increased 26%, or $6.3 million, to $30.4 million for the year ended
December 31, 2002 from $24.1 million for the year ended December 31, 2001. Approximately $4.1 million of the increase was attributable to a higher unit rate ($3.17 per BOE in 2002 versus $2.70 in 2001) and $1.8 million was attributable to increased
production in 2002. DD&A is affected by many factors, including production levels, costs incurred in the acquisition, exploitation and development of proved reserves and estimates of proved reserve quantities and future development costs. The
increase in our DD&A rate in 2002 was primarily due to our 2001 capital program resulting in higher costs being subject to DD&A and, to a lesser extent, to higher estimated future development costs.



Expenses of terminated public equity offering.    In
conjunction with the termination of our proposed initial public equity offering we expensed costs incurred of $2.4 million in 2002.



Interest expense.    Our interest expense increased 11%, or $2.0 million, to $19.4 million for the year ended December 31, 2002 from
$17.4 million for the year ended December 31, 2001, reflecting higher debt balances during 2002 and a decrease in the amount of capitalized interest, partially offset by lower interest rates. We capitalized approximately $2.4 million and $3.1
million of interest in 2002 and 2001, respectively.



Income tax
expense.    Our income tax expense decreased $17.7 million to $16.7 million for the year ended December 31, 2002 from $34.4 million for the year ended December 31, 2001. The decrease was primarily due to decreases in pre-tax
income. Our overall effective tax rate increased slightly to 38.9% in 2002 from 38.6% for the year ended December 31, 2001. Our currently payable effective tax rate was 14.8% for the year ended December 31, 2002 as compared to 6.8% for the year
ended December 31, 2001. The increased currently payable effective rate in 2002 primarily reflects lower expenditures that are expensed for tax purposes and capitalized for financial reporting purposes and the $3.7 million in expense related to
stock appreciation rights that is not deductible until paid. Tax expense and effective tax rates for the periods prior to our spin-off on December 18, 2002 were calculated based on the tax sharing agreement with Plains Resources.



Liquidity and Capital Resources



Our primary sources of liquidity are cash generated from our operations and our revolving credit facility. At December 31, 2003 we had
approximately $186.0 million of availability under our revolving credit facility. We believe that we have sufficient liquidity through our cash from operations and borrowing capacity under our revolving credit facility to meet our short-term and
long-term normal recurring operating needs, debt service obligations, contingencies and anticipated capital expenditures.



Our cash flows depend on many factors, including the price of oil and gas and the success of our acquisition and drilling activities. We actively manage our
exposure to commodity price fluctuations by hedging significant portions of our production and thereby mitigate our exposure to price declines. This allows us the flexibility to continue to execute our capital plan even if prices decline during the
period our hedges are in place. In addition, the majority of our capital expenditures are discretionary and could be curtailed if our cash flows declined from expected levels.



Financing Activities



In connection with our acquisition of 3TEC, we replaced our then existing credit facility with a new $500.0 million credit facility with an initial borrowing base
of $425.0 million.



42



---

##### Table of Contents

On May 30, 2003 we and Plains E&P Company, our wholly owned subsidiary that has no material assets and was
formed for the sole purpose of being a corporate co-issuer of certain of our indebtedness, issued, at an issue price of 106.75%, $75.0 million of 8.75% senior subordinated notes due 2012. We used the net proceeds of $80.1 million from the sale of
these notes to fund a portion of the cash portion of the purchase price of the merger with 3TEC. As a result of the issuance, the borrowing base on our credit facility was reduced to $402.5 million.



At December 31, 2003 we had a working capital deficit of approximately $94.8 million.
Approximately $55.1 million of the working capital deficit is attributable to the fair value of our commodity derivative instruments. In accordance with SFAS No. 133 Accounting for Derivative Instruments and Hedging Activities, the fair
value of all derivative instruments is recorded on the balance sheet. Gains and losses on instruments that qualify for hedge accounting are included in oil and gas revenues in the period that the related volumes are delivered. Changes in the fair
value of instruments that do not qualify for hedge accounting are reflected in other income (expense). The hedge agreements provide for monthly settlement based on the differential between the agreement price and actual NYMEX oil price. Cash
received for sale of physical production will be based on actual market prices and will generally offset any gains or losses on the hedge instruments. In addition, $16.0 million of the working capital deficit is attributable to the in-the-money
value of stock appreciation rights that were deemed vested at December 31, 2003. The remaining working capital deficit will be financed through cash flow and borrowings under our credit facility.



As of December 31, 2003 we had $211.0 million in borrowings and $5.5 million in letters
of credit outstanding under our revolving credit facility. The credit facility has a borrowing base of $402.5 million that will be reviewed every six months, with the lenders and us each 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 matures in 2005. The credit facility contains a $50.0 million sub-limit on letters of credit. To secure borrowings, we
pledged 100% of the shares of stock of our domestic subsidiaries and gave mortgages covering 80% of the total present value of our domestic oil and gas properties.



Amounts borrowed under the credit facility bear an annual interest rate, at our election, equal to either: (i) the Eurodollar rate,
plus from 1.375% to 2.000%; or (ii) 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 0.750% for each of
(1)-(3). The amount of interest payable on outstanding borrowings is based on (1) the utilization rate as a percentage of the total amount of funds borrowed under the credit facility to the borrowing base and (2) our long-term debt rating.
Commitment fees and letter of credit fees under the credit facility are based on the utilization rate and long-term debt rating. Commitment fees range from 0.375% to 0.5% of the unused portion of the borrowing base. Letter of credit fees range from
1.375% to 2.000%. The issuer of any letter of credit receives an issuing fee of 0.125% of the undrawn amount. Our domestic subsidiaries unconditionally guarantee payment of borrowings under the credit facility.



The credit facility contains negative covenants that limit our ability, as well as the
ability of our subsidiaries, among other things, to incur additional debt, pay dividends on stock, make distributions of cash or property, change the nature of our business or operations, redeem stock or redeem subordinated debt, make investments,
create liens, enter into leases, sell assets, sell capital stock of subsidiaries, create subsidiaries, guarantee other indebtedness, enter into agreements that restrict dividends from subsidiaries, enter into certain types of swap agreements, enter
into gas imbalance or take-or-pay arrangements, merge or consolidate and enter into transactions with affiliates. In addition, the credit facility requires us to maintain a current ratio, which includes availability, of at least 1.0 to 1.0 and a
minimum tangible net worth (as defined).



The $275 million 8.75% senior
subordinated notes are our unsecured general obligations, are subordinated in right of payment to all of our existing and future senior indebtedness and are jointly



43



---

##### Table of Contents

and severally guaranteed on a full, unconditional basis by all of our existing and future domestic restricted subsidiaries. The indenture governing the notes contains
covenants that limit our ability, as well as the ability of our subsidiaries, among other things, to incur additional indebtedness, make certain investments, make restricted payments, sell assets, enter into agreements containing dividends and other
payment restrictions affecting subsidiaries, enter into transactions with affiliates, create liens, merge, consolidate and transfer assets and enter into different lines of business. In the event of a change of control, as defined in the indenture,
we will be required to make an offer to repurchase the notes at 101% of the principal amount thereof, plus accrued and unpaid interest to the date of the repurchase. The indenture governing the 8.75% senior subordinated notes permitted the spin-off
and the spin-off did not, in itself, constitute a change of control for purposes of the indenture. The merger did not constitute a change of control for purposes of the indenture.



The notes are not redeemable until July 1, 2007. On or after that date they are redeemable, at our option, at 104.375% of the
principal amount for the twelve-month period ending June 30, 2008, at 102.917% of the principal amount for the twelve-month period ending June 30, 2009, at 101.458% of the principal amount for the twelve-month period ending June 30, 2010 and at 100%
of the principal amount thereafter. In each case, accrued interest is payable to the date of redemption.



We have been assigned a Ba3 senior implied rating and the 8.75% senior subordinated notes have been assigned a B2 rating by Moodys Investor Service Inc. We
have also been assigned a BB corporate credit rating by Standard and Poors Corp. All of these ratings are all below investment grade. As a result, at times we may have difficulty accessing capital markets or raising capital on
favorable terms.



Cash Flows



|                            |  |                         |        |   |      |   |       |      |  |   |        |  
|--------------------------- |  | ----------------------- | ------ | - | ---- | - | ----- | ---- |  | - | ------ | -
|                            |  | Year Ended December 31, |       
|                            |  | 2002                    |        |   | 2002 |   |       | 2001 | 
|                            |  | (in millions)           |       
|Cash provided by (used in): |  |                         |        |   |      |   |       |      |  |   |        |  
|Operating activities        |  | $                       | 118.3  |   |      | $ | 78.8  |      |  | $ | 116.8  |  
|Investing activities        |  |                         | (368.7 | ) |      |   | (64.2 | )    |  |   | (125.9 | )
|Financing activities        |  |                         | 250.8  |   |      |   | (13.7 | )    |  |   | 8.5    |  



Net cash provided by operating
activities were $118.3 million, $78.8 million and $116.8 million for 2003, 2002 and 2001, respectively. The increase from 2002 to 2003 is primarily a result of increased sales volumes as a result of the 3TEC acquisition and, to a lesser extent,
increases in oil and gas prices. The change between 2002 and 2001 is primarily due to changes in oil and gas prices in the periods presented.



Net cash used in investing activities were $368.7 million, $64.2 million and $125.9 million, respectively, and consist primarily of costs incurred in connection
with our oil and gas acquisition, development and exploration activities. Our 2003 capital expenditures included $267.6 million for the acquisition of 3TEC. The 2002 capital expenditure level was reduced from the 2001 amount to manage debt levels
and allow flexibility in pursuing acquisition and other opportunities.



Net cash provided by financing activities in 2003 was $250.8 million. Cash receipts in 2003 included net borrowings of $175.2 million under our credit facility and proceeds received from the issuance of our 8.75% senior subordinated notes
($80.1 million). Cash outflows in 2003 included payments for debt issuance costs ($4.3 million); and principal payments on long-term debt ($0.5 million); and repurchases of treasury stock ($0.1 million). Net cash used in financing activities in 2002
was $13.7 million. Cash receipts in 2002 included proceeds received from the issuance of the 8.75% notes ($196.8 million); cash contributions by Plains Resources ($52.2 million); cash advances from



44



---

##### Table of Contents

Plains Resources prior to the reorganization ($20.4 million); and net borrowings under the PXP credit facility ($35.8 million). Cash outflows in 2002 included cash
distributions to Plains Resources ($312.0 million); payments for debt issuance costs ($5.9 million); and principal payments on long-term debt ($0.5 million). Cash provided by financing activities in 2001 of $8.5 million included cash advances from
Plains Resources ($9.0 million) less principal payments on long-term debt ($0.5 million).



Capital Requirements



We have made
and will continue to make substantial capital expenditures for the acquisition, exploitation, development, exploration and production of oil and gas. During 2004, we expect to make aggregate capital expenditures of approximately $163-$177 million on
our existing asset base. Capital expenditures for the Nuevo properties are expected to be $65-$70 million pursuant to Nuevos 2004 capital plan. Based on the foregoing, total pro forma capital expenditures for the combined asset base are
estimated to be $228-$247 million for 2004, assuming the merger closed on January 1, 2004. Subsequent to the closing of the Nuevo acquisition, we may reallocate capital between the two asset bases to optimize 2004 spending. We expect that 2004
capital expenditures will be funded with cash flow from our operations and our revolving credit facility. In addition, we intend to continue to pursue the acquisition of underdeveloped producing properties.



We will incur cash expenditures upon the exercise of stock appreciation rights, or
SARs, but our outstanding share count will not increase. At December 31, 2003 we had approximately 3.9 million SARs outstanding of which 2.0 million were vested. If all of the vested SARs were exercised, based on $15.39, the price of our common
stock as of December 31, 2003, we would pay $13.2 million to holders of the SARs. In 2003 we made cash payments of $2.1 million for SARs that were exercised during the year. See Critical Accounting Policies and Factors that May Affect Future
ResultsStock Appreciation Rights.



Commitments and
Contingencies



Contractual
obligations.    At December 31, 2003, the aggregate amounts of contractually obligated payment commitments for the next five years are as follows (in thousands):



|                               |  |      |       |      |   |       |  |      |         |      |   |            |  |   |       |  |   |        
|------------------------------ |  | ---- | ----- | ---- | - | ----- |  | ---- | ------- | ---- | - | ---------- |  | - | ----- |  | - | -------
|                               |  | 2004 |       | 2005 |   | 2006  |  | 2007 |         | 2008 |   | Thereafter
|Long-term debt                 |  | $    | 511   |      | $ |      |  | $    | 211,000 |      | $ |           |  | $ |      |  | $ | 275,000
|Producing property remediation |  |      | 1,400 |      |   | 1,225 |  |      | 800     |      |   | 700        |  |   | 625   |  |   | 1,900  
|Operating leases               |  |      | 3,608 |      |   | 3,015 |  |      | 2,399   |      |   | 2,258      |  |   | 2,244 |  |   | 10,243 
|                               |  |      |       |      |   |       |  |      |         |      |   |            |  |   |       |  |   |        
|                               |  | $    | 5,519 |      | $ | 4,240 |  | $    | 214,199 |      | $ | 2,958      |  | $ | 2,869 |  | $ | 287,143
|                               |  |      |       |      |   |       |  |      |         |      |   |            |  |   |       |  |   |        



The long-term debt amounts
consist principally of amounts due under our credit facility and our 8.75% notes. The obligation for producing property remediation consists of obligations associated with the purchase of certain of our California properties. Operating leases relate
primarily to obligations associated with our office facilities and certain cogeneration operations in California.



Environmental matters.    As discussed under Business & PropertiesRegulation Environmental, 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. Typically when producing oil and gas assets are
purchased, one assumes the obligation to plug and abandon wells that are part of such assets. However, in some instances, we have received an indemnity in connection with such purchase. There can be no assurance that we will be able to collect on
these indemnities. Often these regulations are more



45



---

##### Table of Contents

burdensome on older properties that were operated before the regulations came into effect such as some of our properties in California that have operated for over 90
years. We have established policies for continuing compliance with environmental laws and regulations. We also maintain insurance coverage for environmental matters, which we believe is customary in the industry, but we are not fully insured against
all environmental risks. 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.



Plugging, Abandonment and Remediation
Obligations.    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. Typically, when producing oil and gas assets are purchased the purchaser assumes the obligation to plug and abandon wells that are part of such assets. However,
in some instances, we received an indemnity with respect to those costs.



In connection with the purchase of certain of our onshore California properties, each year we are required to plug and abandon 20% of the then remaining inactive wells (there were 158 inactive wells at December 31, 2003). If we do not meet
this commitment, and the requirement is not waived, we must escrow funds to cover the cost of the wells that were not abandoned. To date we have not been required to escrow any funds. In addition, until the end of 2006 we are required to spend at
least $600,000 per year (and $300,000 per year from 2007 through 2011) to remediate oil contaminated soil from existing well sites that require remediation



For a discussion of our specific contractual obligations to incur plugging, abandonment and remediation costs, see
BusinessPlugging, Abandonment and Remediation Obligations.



Other commitments and contingencies.    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.



As discussed under Legal
Proceedings, in the ordinary course of business, we are a claimant and/or defendant in various other legal proceedings. In particular, we were required to indemnify Plains Resources for any liabilities it incurred in connection with a lawsuit
it (through a predecessor interest in Stocker Resources, Inc.) had regarding an electric services contract with Commonwealth Energy Corporation. In January 2004 Plains Resources settled the suit. Under the terms of our master separation agreement
with Plains Resources, we indemnified them for damages they might incur as a result of this action.



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, oil spills, 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 all
risks, either because insurance is not available or because of high premium costs. We maintain coverage for earthquake damages in California but this coverage may not provide for the full effect of damages that could occur and we may be subject to
additional liabilities. 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



46



---

##### Table of Contents

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.



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 in California and Illinois. 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. Six of the financial institutions are participating lenders in our credit facility, holding contracts that represent approximately 62% of the fair value of all
of our open positions at December 31, 2003.



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 and trucks 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.



Critical Accounting Policies and
Factors that May Affect Future Results



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 and gas sales 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 Item
7A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
| | - |  | ------------------------------------------------------------------------------------------------------------



47



---

##### Table of Contents

| |  |  | the lower of cost or fair value of unproved properties not 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.    Our proved reserve information is
based on estimates prepared by outside engineering firms. Estimates prepared by others may be higher or lower than these estimates.



Estimates of proved reserves may be different from the actual quantities of oil and gas recovered because such estimates depend on many assumptions and are based on
operating conditions and results at the time the estimate is made. The actual results of drilling and testing, as well as changes in production rates and recovery factors, can vary significantly from those assumed in the preparation of reserve
estimates. As a result, such factors have historically, and can in the future, cause significant upward and downward revisions to proved reserve estimates.



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.



Historically, we have experienced significant upward and downward revisions to our
reserves volumes and values as a result of changes in year-end oil and gas prices and the corresponding adjustment to the projected economic life of such properties. Prices for oil and gas are likely to continue to be volatile, resulting in future
downward and upward revisions to our reserve base.



Our rate of recording
DD&A is dependent upon our estimate of proved reserves including future development and abandonment costs as well as our level of capital spending. 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. The decline in proved reserve estimates may impact the outcome of the ceiling
test discussed above. In addition, increases in costs required to develop our reserves would increase the rate at which we record DD&A expense. We are unable to predict changes in future development costs as such costs are dependent on the
success of our exploitation and development program, as well as future economic conditions.



Stock appreciation rights.    As part of the spin-off, all outstanding options to acquire Plains Resources common stock at the time of the spin-off were split between Plains Resources
stock options and stock appreciation rights (SARs) with respect to our common stock.



SARs are subject to variable accounting treatment under U.S. generally accepted accounting principles. As a result, at the end of each quarter, we compare the closing price of our common stock on the last day of the quarter to
the exercise price of each outstanding or unexercised SAR that is vested or for accounting purposes is deemed vested at the end of the quarter. For example, if a SAR is



48



---

##### Table of Contents

scheduled to vest on December 31, for accounting purposes one-fourth of the shares are deemed to vest at the end of each quarter even though no vesting occurs until
December 31. To the extent the closing price at the end of each quarter exceeds the exercise price of each SAR, we will recognize such excess as an accounting charge for the SARs deemed vested to the extent such excess has not previously been
recognized as expense. If the quarter-end closing price decreases compared to prior periods, we will recognize credits to income, to the extent we have previously recognized expense. These quarterly charges and credits will make our results of
operations depend, in part, on fluctuations in the price of our common stock and could have a material adverse effect on our results of operations. We will incur cash expenditures as SARs are exercised, but our outstanding common shares will not
increase.



We recognized compensation expense of $18.0 million related to
SARs for the year ended December 31, 2003, representing the increase in our stock price and the vesting deemed to have occurred during the year. In 2003 we made cash payments of $2.1 million for SARs that were exercised during the year. As of
December 31, 2003, we have approximately 3.9 million SARs outstanding with an average exercise price of $9.25, of which 3.1 million of the SARs were deemed vested.



Goodwill.    In a purchase transaction, goodwill represents the excess of the purchase price plus the
liabilities assumed, including deferred income taxes recorded in connection with the merger, over the fair value of the net assets acquired. In our acquisition of 3TEC, goodwill totaled $147.3 million and represents 12% of our total assets at
December 31, 2003.



Goodwill is not amortized, but instead must be tested
at least annually for impairment by applying a fair-value based test. Goodwill is deemed impaired to the extent of any excess of its carrying amount over the residual fair value of the reporting unit. Such impairment could significantly reduce
earnings during the period in which the impairment occurs and would result in a corresponding reduction to goodwill and stockholders equity. The most significant factors that could result in the impairment of our goodwill would be significant
declines in oil and gas prices and/or reserve volumes which would result in a decline in the fair value of our oil and gas properties.



Recent Accounting Pronouncements



The Financial Accounting Standards Board (FASB) issued Financial Interpretation No. 46 (FIN 46), Consolidation of Variable Interest Entities in January
2003. FIN 46 addresses the consolidation of variable interest entities (VIEs) by business enterprises that are the primary beneficiaries. A VIE is an entity that does not have sufficient equity investment at risk to permit it to finance its
activities without additional subordinated financial support, or whose equity investors lack the characteristics of a controlling financial interest. The primary beneficiary of a VIE is the enterprise that has the majority of the risks or rewards
associated with the VIE. In December 2003, the FASB issued a revision to FIN 46, Interpretation No. 46R (FIN 46R), to clarify some of the provisions of FIN 46, and to exempt certain entities from its requirements. Application of FIN 46R is required
in financial statements of public entities that have interests in structures that are commonly referred to as special-purpose entities for periods ending after December 15, 2003. Application for all other types of VIEs is required in financial
statements for periods ending after March 15, 2004. We do not believe we participate in any arrangement that would be subject to the provisions of FIN 46R.



Item 7A.    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 production and intend to continue this practice, substantial future oil and gas price declines would adversely affect our overall



49



---

##### Table of Contents

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.



Under SFAS No. 133 Accounting for Derivative Instruments and Hedging Activities, as amended, 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 primarily 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 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 for which hedge
accounting has been discontinued remain unchanged until the related product has been 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.



We utilize various derivative instruments to hedge our exposure to price fluctuations on oil and gas sales. The derivative instruments consist primarily of cash-settled option and swap contracts entered into with financial
institutions. We also use interest rate swaps to manage the interest rate exposure on our credit facility.



We assumed several open derivative positions in connection with the 3TEC merger. Such derivative positions were recorded at fair value in the purchase price
allocation. We determined that one such derivative position did not qualify as a hedge. Changes in fair value of such position subsequent to the merger have been reflected in income. All other open derivative positions at December 31, 2003 qualified
for hedge accounting.



At December 31, 2002, OCI consisted of $20.9
million ($12.6 million, net of tax) of unrealized net losses on our open hedging instruments. As oil prices increased significantly during 2003 and we assumed 3TECs hedge positions as a result of the merger, the fair value of our open hedging
positions that qualified for hedge accounting, net of settlements, decreased $45.8 million ($27.7 million after tax). At December 31, 2003, OCI consisted of $66.7 million ($40.3 million after tax) of unrealized losses on our open hedging
instruments, $0.2 million ($0.1 million, net of tax) loss related to our



50



---

##### Table of Contents

interest rate swap and $0.1 million ($0.1 million, net of tax) loss related to deferred compensation liabilities. At December 31, 2003 the assets and liabilities
related to our open commodity derivative instruments were included in current liabilities ($55.1 million), other long-term liabilities ($23.7 million) and deferred income taxes (a tax benefit of $32.1 million).



During 2003, 2002 and 2001, deferred gains (losses) of ($37.6 million), ($15.6 million)
and $0.3 million, respectively, were reclassified from OCI and charged to income as a reduction of oil and gas revenues. As of December 31, 2003, $43.0 million ($26.0 million, net of tax) of deferred net losses on derivative instruments recorded in
OCI are expected to be reclassified to earnings during the next twelve-month period. During 2003 we recognized $0.8 million of income from the change in the fair value of derivatives that do not qualify for hedge accounting.



Commodity price risk.    As of February 29, 2004, we had the
following open hedge positions with respect to our oil and gas properties:



|                               |  |        |  |        |  |       
|------------------------------ |  | ------ |  | ------ |  | ------
|                               |  | 2004   |  | 2005   |  | 2006  
|Oil Swaps                      |  |        |  |        |  |       
|Average price $23.89 per Bbl   |  | 18,500 |  |       |  |      
|Average price $24.79 per Bbl   |  |       |  | 17,500 |  |      
|Average price $25.28 per Bbl   |  |       |  |       |  | 15,000
|                               |  |        | 
|Natural Gas Swaps              |  |        |  |        |  |       
|Average price $4.45 per MMBtu  |  | 20,000 |  |       |  |      
|                               |  |        | 
|Natural Gas Costless Collars   |  |        |  |        |  |       
|Floor price of $4.00 per MMBtu |  | 20,000 |  |       |  |      
|Cap price of $5.15 per MMBtu   |  |        |  |        |  |       
|Floor price of $4.75 per MMBtu |  | 10,000 |  |       |  |      
|Cap price of $5.67 per MMBtu   |  |        |  |        |  |       



Assuming our fourth quarter 2003
production volumes remain unchanged, these positions result in us hedging approximately 69%, 45% and 39% of production in 2004, 2005 and 2006, respectively. 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 and gas production, these adjustments will reduce our net price.



The fair value of outstanding crude 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):



|                            |  |              |       |      |                             |   |            |  |   |                             |   |  |   |     
|--------------------------- |  | ------------ | ----- | ---- | --------------------------- | - | ---------- |  | - | --------------------------- | - |  | - | ----
|                            |  | December 31,
|                            |  | 2003         |       | 2002
|                            |  | Fair Value   |       |      | Effect of10% Price Decrease |   | Fair Value |  |   | Effect of10% Price Decrease
|Swaps and options contracts |  | $            | (78.8 | )    |                             | $ | 59.0       |  | $ | (20.9                       | ) |  | $ | 29.3



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.



51



---

##### Table of Contents

The contract counterparties for our derivative commodity contracts are all major financial institutions with
Standard & Poors ratings of A or better. Six of the financial institutions are participating lenders in our revolving credit facility, holding contracts that represent approximately 62% of the fair value of all open positions as of
December 31, 2003.



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.



Interest rate risk.    Our credit facility is sensitive to market fluctuations in interest rates. We use
interest rate swaps to hedge underlying debt obligations. These instruments hedge specific debt issuances and qualify for hedge accounting. The interest rate differential is reflected as an adjustment to interest expense over the life of the
instruments. We have entered into an interest rate swap for an aggregate notional principal amount of $7.5 million that fixes the interest rate on that amount of borrowing under our credit facility at 3.9% plus the LIBOR margin set forth in our
credit facility. The swap expires in October 2004.



Item 8.Financial Statements and Supplementary Data



The information required here is included in this report as set forth in the Index to Financial Statements on page F-1.



Item 9.Changes in and Disagreements with Accountants on Accounting and Financial Disclosure



None.



Item 9A.Controls and Procedures



Under the supervision and with the participation of our management, including our Chief Executive Officer (our principal executive officer) and our Chief Financial
Officer (our principal financial officer), we evaluated the effectiveness of our disclosure controls and procedures (as defined under Rule 13a-14(c) of the Securities Exchange Act of 1934, as amended (the Exchange Act)). Based on this
evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that our disclosure controls and procedures as of December 31, 2003 are effective to ensure that information we are required to disclose in the reports that we file or
submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SECs rules and forms.



There were no significant changes in our internal controls or in other factors that could significantly affect these controls subsequent to the date of such
evaluation.



52



---

##### Table of Contents

PART III



Item 10.Directors and Executive Officers of the Registrant



Information regarding our directors and executive officers will be included in an amendment to this Form 10-K or in the proxy statement for the 2004 annual meeting
of stockholders, in either case, to be filed within 120 days after December 31, 2003, and is incorporated by reference to this report.



We have provided summary information with respect to our directors and executive officers following Item 4 in Part I of this report.



Item 11.Executive Compensation



Information regarding executive compensation will be included in an amendment to this Form 10-K or in the proxy statement and is incorporated by reference to this
report.



Item 12.Security Ownership of Certain Beneficial Owners and Management



Information regarding beneficial ownership will be included in an amendment to this Form 10-K or in the proxy statement and is incorporated by reference to this
report.



Item 13.Certain Relationships and Related Transactions



Information regarding certain relationships and related transactions will be included in an amendment to this Form 10-K or in the proxy statement and is
incorporated by reference to this report.



Item 14.Principal Accountant Fees and Services



Information regarding principal accountant fees and services will be included in an amendment to this Form 10-K or in the proxy statement and is incorporated by
reference to this report.



53



---

##### Table of Contents

PART IV



Item 15.Exhibits, Financial Statement Schedules and Reports on Form 8-K



(a) (1) and (2) Financial Statements and Financial Statement Schedules



See Index to Consolidated Financial Statements set forth on Page F-1.



(a) (3) Exhibits



|               |  |                                                                                                                                                                                                                                                                                                                                                                             
|-------------- |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|Exhibit Number |  | Description                                                                                                                                                                                                                                                                                                                                                                 
|               | 
|2.1            |  | Agreement and Plan of Merger dated February 12, 2004, by and among Plains Exploration & Production Company, PXP California Inc. and Nuevo Energy Company (incorporated by reference to Exhibit 2.1 to
the Companys Form 8-K filed on February 12, 2004)                                                                                                                    
|               | 
|3.1            |  | Certificate of Incorporation of Plains Exploration & Production Company (incorporated by reference to Exhibit 3.1 to Amendment No. 2 to the Companys Registration Statement on Form S-1 filed
on October 3, 2002).                                                                                                                                                         
|               | 
|3.2            |  | Bylaws of Plains Exploration & Production Company (incorporated by reference to Exhibit 3.2 to Amendment No. 2 to the Companys Registration Statement on Form S-1 filed on October 3,
2002).                                                                                                                                                                               
|               | 
|4.1            |  | Indenture dated July 3, 2002 among Plains Exploration & Production Company, Plains E&P Company, Arguello Inc., Plains Illinois Inc., Plains Resources International Inc., PMCT Inc., and J.P.
Morgan Chase Bank, as Trustee (incorporated by reference to Exhibit 4.2 to the Companys Amendment No. 1 to Form S-1 filed on August 28, 2002).                               
|               | 
|4.2            |  | Form of 83/4% Senior Subordinated Note (incorporated by reference to
Exhibit 4.3 to the Companys Amendment No. 1 to Form S-1 filed on August 28, 2002).                                                                                                                                                                                                                    
|               | 
|4.3            |  | First Supplemental Indenture, dated as of March 31, 2003, among PXP Gulf Coast Inc., Plains Exploration & Production Company, and Plains E&P Company, each other then existing Subsidiary
Guarantor under the Indenture, and J.P. Morgan Chase Bank, as Trustee (incorporated by reference to Exhibit 10.1 to the Companys Form 10-Q for the period ending March 31, 2003).
|               | 
|10.1           |  | Master Separation Agreement dated July 3, 2002 between Plains Exploration & Production Company and Plains Resources Inc. (incorporated by reference to Exhibit 10.1 to the Companys Amendment
No. 1 to Form S-1 filed on August 28, 2002).                                                                                                                                 
|               | 
|10.2           |  | Amendment No. 1 to Master Separation Agreement, dated as of November 20, 2002, between Plains Resources Inc. and Plains Exploration & Production Company (incorporated by reference to Exhibit 10.24
to the Companys Amendment No. 1 to Form 10 filed on November 21, 2002).                                                                                               
|               | 
|10.3           |  | Plains Exploration and Production Company Transition Services Agreement dated July 3, 2002 between Plains Exploration & Production Company and Plains Resources Inc. (incorporated by reference to
Exhibit 10.2 to the Companys Amendment No. 1 Form S-1 filed on August 28, 2002).                                                                                        
|               | 
|10.4           |  | Extension of Term of Plains Exploration & Production Company Transition Services Agreement, dated as of December 18, 2002, between Plains Exploration & Production Company and Plains Resources
Inc. (incorporated by reference to Exhibit 10.3 to the Companys Registration Statement on Form S-4 filed on February 12, 2003).                                            
|               | 
|10.5           |  | Extension of Term of Plains Exploration & Production Company Transition Services Agreement, effective as of June 16, 2003, between Plains Resources Inc. and Plains Exploration & Production
Company. (incorporated by reference to Exhibit 10.4 to the Companys Registration Statement on Form S-4 filed on August 29, 2003).                                             



54



---

##### Table of Contents

|               |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                     
|-------------- |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|Exhibit Number |  | Description                                                                                                                                                                                                                                                                                                                                                                                                                                         
|               | 
|10.6           |  | Plains Resources Inc. Transition Services Agreement dated July 3, 2002 between Plains Resources Inc. and Plains Exploration & Production Company (incorporated by reference to Exhibit 10.6 to the
Companys Amendment No. 1 to Form S-1 filed on August 28, 2002).                                                                                                                                                                                 
|               | 
|10.7           |  | Extension of Term of Plains Resources Inc. Transition Services Agreement, effective as of June 8, 2003, between Plains Resources Inc. and Plains Exploration & Production Company. (incorporated by
reference to Exhibit 10.6 to the Companys Registration Statement on Form S-4 filed on August 29, 2003).                                                                                                                                        
|               | 
|10.8           |  | Second Amended and Restated Tax Allocation Agreement dated November 20, 2002 between Plains Exploration & Production Company and Plains Resources Inc. (incorporated by reference to Exhibit 10.4 to
the Companys Amendment No. 1 to Form 10 filed on November 21, 2002).                                                                                                                                                                          
|               | 
|10.9           |  | Technical Services Agreement dated July 3, 2002 between Plains Exploration & Production Company and Plains Resources Inc. (incorporated by reference to Exhibit 10.5 to the Companys Amendment
No. 1 to Form S-1 filed on August 28, 2002).                                                                                                                                                                                                        
|               | 
|10.10          |  | Intellectual Property Agreement dated July 3, 2002 between Plains Exploration & Production Company and Plains Resources Inc. (incorporated by reference to Exhibit 10.6 to the Companys
Amendment No. 1 to Form S-1 filed on August 28, 2002).                                                                                                                                                                                                     
|               | 
|10.11          |  | Employee Matters Agreement dated July 3, 2002 between Plains Exploration & Production Company and Plains Resources Inc. (incorporated by reference to Exhibit 10.7 to the Companys Amendment
No. 1 to Form S-1 filed on August 28, 2002).                                                                                                                                                                                                          
|               | 
|10.12          |  | Amendment No. 1 to Employee Matters Agreement, dated as of September 18, 2002, between Plains Resources Inc. and Plains Exploration & Production Company (incorporated by reference to Exhibit 10.22
to the Companys Amendment No. 2 to Form S-1 filed on October 4, 2002).                                                                                                                                                                        
|               | 
|10.13          |  | Amendment No. 2 to Employee Matters Agreement, dated as of November 20, 2002, between Plains Resources Inc. and Plains Exploration & Production Company (incorporated by reference to Exhibit 10.25
to the Companys Amendment No. 1 to Form 10 filed on November 21, 2002).                                                                                                                                                                        
|               | 
|10.14          |  | Amendment No. 3 to Employee Matters Agreement, dated as of December 2, 2002, between Plains Resources Exploration & Production Company and Plains Resources Inc. (incorporated by reference to
Exhibit 10.23 to the Companys Registration Statement on Form S-4 filed on February 12, 2003).                                                                                                                                                       
|               | 
|10.15          |  | Credit Agreement dated as of April 4, 2003 among Plains Exploration & Production Company, as Borrower, JPMorgan Chase Bank, as Administrative Agent, Bank One, NA (Main Office Chicago) and Bank of
Montreal, as Syndication Agents, BNP Paribas and the Bank of Nova Scotia, as Documentation Agents, and the Lenders party thereto (incorporated by reference to Exhibit 10.13 to the Companys Amendment No. 2 to Form S-4 filed on May 1,
2003).
|               | 
|10.16          |  | Employment Agreement, dated as of September 19, 2002, between Plains Exploration & Production Company and James C. Flores (incorporated by reference to Exhibit 10.13 to Companys Amendment No.
2 to Form S-1 filed on October 4, 2002).                                                                                                                                                                                                           
|               | 
|10.17          |  | Amendment No. 1 to Employment Agreement dated as of November 20, 2002, between Plains Exploration & Production Company and James C. Flores (incorporated by reference to Exhibit 10.26 to the
Companys Amendment No. 1 to Form 10 filed on November 21, 2002).                                                                                                                                                                                     
|               | 
|10.18          |  | Employment Agreement, dated as of August 20, 2002, between Plains Exploration & Production Company and Stephen A. Thorington (incorporated by reference to Exhibit 10.15 to the Companys
Amendment No. 2 to Form S-1 filed on October 4, 2002).                                                                                                                                                                                                    



55



---

##### Table of Contents

|               |   |  |                                                                                                                                                                                                                                                                       
|-------------- | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|Exhibit Number |   |  | Description                                                                                                                                                                                                                                                           
|               |  
|10.19          |   |  | Amendment No. 1 to Employment Agreement, dated as of November 20, 2002, between Plains Exploration & Production Company and Stephen A. Thorington (incorporated by reference to Exhibit 10.28 to the
Companys Amendment No. 1 to Form 10 filed on November 21, 2002).
|               |  
|10.20          | * |  | Employment Agreement, dated as of September 4, 2003, between Plains Exploration & Production Company and John F. Wombwell.                                                                                                                                            
|               |  
|10.21          | * |  | Employment Agreement dated as of February 18, 2004, between Plains Exploration & Production Company and Thomas M. Gladney                                                                                                                                             
|               |  
|10.22          |   |  | Form of Plains Restricted Stock Agreement (incorporated by reference to Exhibit 10.19 to the Companys 2002 Form 10-K).                                                                                                                                               
|               |  
|10.23          |   |  | Form of Plains Stock Appreciation Rights Agreement (incorporated by reference to Exhibit 10.18 to the Companys 2002 Form 10-K).                                                                                                                                      
|               |  
|10.24          |   |  | Form of Restricted Stock Unit Agreement (incorporated by reference to Exhibit 10.33 to the Companys 2002 Form 10-K).                                                                                                                                                 
|               |  
|10.25          |   |  | Plains Exploration & Production Company 2002 Transition Stock Incentive Plan (incorporated by reference to Exhibit 10.33 to the Companys Amendment No. 1 to Form 10 filed on November 21,
2002).                                                                     
|               |  
|10.26          |   |  | Plains Exploration & Production Company 2002 Rollover Stock Plan (incorporated by reference to Exhibit 10.34 to the Companys Amendment No. 1 to Form 10 filed on November 21,
2002).                                                                                 
|               |  
|10.27          |   |  | First Amendment to the Plains Exploration & Production Company 2002 Stock Incentive Plan (incorporated by reference to Exhibit 10.32 to the Companys Amendment No. 1 to Form S-4 filed on March
27, 2003).                                                           
|               |  
|21.1*          |   |  | List of Subsidiaries of Plains Exploration & Production Company.                                                                                                                                                                                                      
|               |  
|23.1*          |   |  | Consent of PricewaterhouseCoopers LLP.                                                                                                                                                                                                                                
|               |  
|23.2*          |   |  | Consent of Netherland, Sewell & Associates, Inc.                                                                                                                                                                                                                      
|               |  
|23.3*          |   |  | Consent of Ryder Scott Company.                                                                                                                                                                                                                                       
|               |  
|31.1*          |   |  | Rule 13a-14(a)/15d-14(a) Certificate of the Chief Executive Officer                                                                                                                                                                                                   
|               |  
|31.2*          |   |  | Rule 13a-14(a)/15d-14(a) Certificate of the Chief Financial Officer                                                                                                                                                                                                   
|               |  
|32.1**         |   |  | Section 1350 Certificate of the Chief Executive Officer                                                                                                                                                                                                               
|               |  
|32.2**         |   |  | Section 1350 Certificate of the Chief Financial Officer                                                                                                                                                                                                               

---

|* |  | Filed herewith.
|- |  | ---------------

|** |  | Furnished herewith.
|-- |  | -------------------



56



---

##### Table of Contents

SIGNATURES



Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by
the undersigned, thereunto duly authorized.



|                     |  |                       |  |                                                                                                          
|-------------------- |  | --------------------- |  | ---------------------------------------------------------------------------------------------------------
|                     |  | PLAINS RESOURCES INC.
|                     |  |                      
|Date: March 11, 2004 |  | By:                   |  | /s/    STEPHEN A. THORINGTON                                                                             
|                     |  |                       |  | Stephen A. Thorington, Executive Vice President and Chief Financial Officer (Principal Financial Officer)



Pursuant to the requirements of
the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.



|                      |  |     |  |                                                                                                            
|--------------------- |  | --- |  | -----------------------------------------------------------------------------------------------------------
|Date: March 11, 2004  |  | By: |  | /s/    JAMES C. FLORES                                                                                     
|                      |  |     |  | James C. Flores, Chairman of the Board, President and Chief Executive Officer (Principal Executive Officer)
|                      |  |    
|Date: March 11, 2004  |  | By: |  | /s/    ALAN R. BUCKWALTER, III                                                                             
|                      |  |     |  | Alan R. Buckwalter, III, Director                                                                          
|                      |  |    
|Date: March 11, 2004  |  | By: |  | /s/    JERRY L. DEES                                                                                       
|                      |  |     |  | Jerry L. Dees, Director                                                                                    
|                      |  |    
|Date: March 11, 2004  |  | By: |  | /s/    TOM H. DELIMITROS                                                                                   
|                      |  |     |  | Tom H. Delimitros, Director                                                                                
|                      |  |    
|Date: March 11, 2004  |  | By: |  | /s/    JOHN H. LOLLAR                                                                                      
|                      |  |     |  | John H. Lollar, Director                                                                                   
|                      |  |    
|Date: March 11 , 2004 |  | By: |  | /s/    STEPHEN A. THORINGTON                                                                               
|                      |  |     |  | Stephen A. Thorington, Executive Vice President and Chief Financial Officer (Principal Financial Officer)  
|                      |  |    
|Date: March 11, 2004  |  | By: |  | /s/    CYNTHIA A. FEEBACK                                                                                  
|                      |  |     |  | Cynthia A. Feeback, Senior Vice PresidentAccounting and Treasurer (Principal Accounting Officer)          



57



---

##### Table of Contents

PLAINS EXPLORATION & PRODUCTION COMPANY



INDEX TO CONSOLIDATED FINANCIAL STATEMENTS



|                                                                                                     |  |     
|---------------------------------------------------------------------------------------------------- |  | ----
|                                                                                                     |  | Page
|Financial Statements                                                                                 |  |     
|                                                                                                     | 
|Report of Independent Auditors                                                                       |  | F-2 
|Consolidated Balance SheetsAs of December 31, 2003 and 2002                                          |  | F-3 
|Consolidated Statements of IncomeFor the years ended December 31, 2003, 2002 and 2001                |  | F-4 
|Consolidated Statements of Cash FlowsFor the years ended December 31, 2003, 2002 and 2001            |  | F-5 
|Consolidated Statements of Comprehensive IncomeFor the years ended December 31, 2003, 2002, and 2001 |  | F-6 
|Consolidated Statements of Stockholders EquityFor the years ended December 31, 2003, 2002, and 2001 |  | F-7 
|Notes to Consolidated Financial Statements                                                           |  | F-8 



All other schedules are omitted because they are
not applicable or the required information is shown in the financial statements or notes thereto.



F-1



---

##### Table of Contents

Report of Independent Auditors



To the Board of Directors and Stockholders

of Plains Exploration & Production Company:



In our opinion, the consolidated financial statements listed in the accompanying index present fairly,
in all material respects, the financial position of Plains Exploration and Production Company and its subsidiaries at December 31, 2003 and 2002, and the results of their operations and their cash flows for each of the three years in the
period ended December 31, 2003 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 1 to the consolidated financial statements, the Company changed its method of
accounting for asset retirement obligations effective January 1, 2003. As discussed in Note 3 to the consolidated financial statements, the Company changed its method of accounting for derivative instruments and hedging activities, effective January
1, 2001.



PricewaterhouseCoopers LLP



Houston, Texas

March 10, 2004



F-2



---

##### Table of Contents

PLAINS EXPLORATION & PRODUCTION COMPANY



CONSOLIDATED BALANCE SHEETS

(in thousands of dollars)



|                                                                                                                                                                      |  |              |           |   |      |   |          |  
|--------------------------------------------------------------------------------------------------------------------------------------------------------------------- |  | ------------ | --------- | - | ---- | - | -------- | -
|                                                                                                                                                                      |  | December 31, |          
|                                                                                                                                                                      |  | 2003         |           |   | 2002 |  
|ASSETS                                                                                                                                                                |  |              |           |   |      |   |          |  
|Current Assets                                                                                                                                                        |  |              |           |   |      |   |          |  
|Cash and cash equivalents                                                                                                                                             |  | $            | 1,377     |   |      | $ | 1,028    |  
|Accounts receivablePlains All American Pipeline, L.P.                                                                                                                |  |              | 25,344    |   |      |   | 22,943   |  
|Other accounts receivable                                                                                                                                             |  |              | 25,267    |   |      |   | 5,925    |  
|Commodity hedging contracts                                                                                                                                           |  |              |          |   |      |   | 2,594    |  
|Inventories                                                                                                                                                           |  |              | 5,318     |   |      |   | 5,198    |  
|Other current assets                                                                                                                                                  |  |              | 3,019     |   |      |   | 1,051    |  
|                                                                                                                                                                      |  |              |           |   |      |   |          |  
|                                                                                                                                                                      |  |              | 60,325    |   |      |   | 38,739   |  
|                                                                                                                                                                      |  |              |           |   |      |   |          |  
|Property and Equipment, at cost                                                                                                                                       |  |              |           |   |      |   |          |  
|Oil and natural gas propertiesfull cost method                                                                                                                       |  |              |           |   |      |   |          |  
|Subject to amortization                                                                                                                                               |  |              | 1,074,302 |   |      |   | 629,454  |  
|Not subject to amortization                                                                                                                                           |  |              | 63,658    |   |      |   | 30,045   |  
|Other property and equipment                                                                                                                                          |  |              | 4,939     |   |      |   | 2,207    |  
|                                                                                                                                                                      |  |              |           |   |      |   |          |  
|                                                                                                                                                                      |  |              | 1,142,899 |   |      |   | 661,706  |  
|Less allowance for depreciation, depletion and amortization                                                                                                           |  |              | (186,004  | ) |      |   | (168,494 | )
|                                                                                                                                                                      |  |              |           |   |      |   |          |  
|                                                                                                                                                                      |  |              | 956,895   |   |      |   | 493,212  |  
|                                                                                                                                                                      |  |              |           |   |      |   |          |  
|Goodwill                                                                                                                                                              |  |              | 147,251   |   |      |   |         |  
|                                                                                                                                                                      |  |              |           |   |      |   |          |  
|Other Assets                                                                                                                                                          |  |              | 19,641    |   |      |   | 18,929   |  
|                                                                                                                                                                      |  |              |           |   |      |   |          |  
|                                                                                                                                                                      |  | $            | 1,184,112 |   |      | $ | 550,880  |  
|                                                                                                                                                                      |  |              |           |   |      |   |          |  
|LIABILITIES AND STOCKHOLDERS EQUITY                                                                                                                                  |  |              |           |   |      |   |          |  
|Current Liabilities                                                                                                                                                   |  |              |           |   |      |   |          |  
|Accounts payable                                                                                                                                                      |  | $            | 41,736    |   |      | $ | 24,825   |  
|Commodity hedging contracts                                                                                                                                           |  |              | 55,123    |   |      |   | 24,572   |  
|Royalties payable                                                                                                                                                     |  |              | 19,080    |   |      |   | 11,873   |  
|Stock appreciation rights                                                                                                                                             |  |              | 16,049    |   |      |   | 3,380    |  
|Interest payable                                                                                                                                                      |  |              | 622       |   |      |   | 9,207    |  
|Payable to Plains Resources Inc.                                                                                                                                      |  |              |          |   |      |   | 1,435    |  
|Current maturities of long-term debt                                                                                                                                  |  |              | 511       |   |      |   | 511      |  
|Other current liabilities                                                                                                                                             |  |              | 21,965    |   |      |   | 10,372   |  
|                                                                                                                                                                      |  |              |           |   |      |   |          |  
|                                                                                                                                                                      |  |              | 155,086   |   |      |   | 86,175   |  
|                                                                                                                                                                      |  |              |           |   |      |   |          |  
|Long-Term Debt                                                                                                                                                        |  |              |           |   |      |   |          |  
|8.75% Senior Subordinated Notes                                                                                                                                       |  |              | 276,906   |   |      |   | 196,855  |  
|Revolving credit facility                                                                                                                                             |  |              | 211,000   |   |      |   | 35,800   |  
|Other                                                                                                                                                                 |  |              |          |   |      |   | 511      |  
|                                                                                                                                                                      |  |              |           |   |      |   |          |  
|                                                                                                                                                                      |  |              | 487,906   |   |      |   | 233,166  |  
|                                                                                                                                                                      |  |              |           |   |      |   |          |  
|Asset Retirement Obligation                                                                                                                                           |  |              | 33,235    |   |      |   |         |  
|                                                                                                                                                                      |  |              |           |   |      |   |          |  
|Other Long-Term Liabilities                                                                                                                                           |  |              | 32,194    |   |      |   | 6,303    |  
|                                                                                                                                                                      |  |              |           |   |      |   |          |  
|Deferred Income Taxes                                                                                                                                                 |  |              | 121,435   |   |      |   | 51,416   |  
|                                                                                                                                                                      |  |              |           |   |      |   |          |  
|Commitments and Contingencies (Note 9)                                                                                                                                |  |              |           |   |      |   |          |  
|Stockholders Equity                                                                                                                                                  |  |              |           |   |      |   |          |  
|Common stock, $0.01 par value, 100,000,000 shares authorized, 40.3 million and 24.2 million shares issued and outstanding at December 31, 2003 and 2002,
respectively |  |              | 403       |   |      |   | 244      |  
|Additional paid-in capital                                                                                                                                            |  |              | 322,856   |   |      |   | 174,279  |  
|Retained earnings                                                                                                                                                     |  |              | 71,566    |   |      |   | 12,155   |  
|Accumulated other comprehensive income                                                                                                                                |  |              | (40,439   | ) |      |   | (12,858  | )
|Treasury stock, at cost                                                                                                                                               |  |              | (130      | ) |      |   |         |  
|                                                                                                                                                                      |  |              |           |   |      |   |          |  
|                                                                                                                                                                      |  |              | 354,256   |   |      |   | 173,820  |  
|                                                                                                                                                                      |  |              |           |   |      |   |          |  
|                                                                                                                                                                      |  | $            | 1,184,112 |   |      | $ | 550,880  |  
|                                                                                                                                                                      |  |              |           |   |      |   |          |  



See notes to consolidated
financial statements.



F-3



---

##### Table of Contents

PLAINS EXPLORATION & PRODUCTION COMPANY



CONSOLIDATED STATEMENTS OF INCOME

(in thousands, except per share data)



|                                                                      |  |                         |         |   |      |   |         |      |  |   |         |  
|--------------------------------------------------------------------- |  | ----------------------- | ------- | - | ---- | - | ------- | ---- |  | - | ------- | -
|                                                                      |  | Year Ended December 31, |        
|                                                                      |  | 2003                    |         |   | 2002 |   |         | 2001 | 
|Revenues                                                              |  |                         |         |   |      |   |         |      |  |   |         |  
|Oil sales to Plains All American Pipeline, L.P.                       |  | $                       | 238,663 |   |      | $ | 193,615 |      |  | $ | 174,614 |  
|Other oil sales                                                       |  |                         | 10,837  |   |      |   |        |      |  |   |        |  
|Oil hedging                                                           |  |                         | (51,352 | ) |      |   | (15,577 | )    |  |   | 281     |  
|Gas sales                                                             |  |                         | 91,267  |   |      |   | 10,299  |      |  |   | 28,771  |  
|Gas hedging                                                           |  |                         | 13,787  |   |      |   |        |      |  |   |        |  
|Other operating revenues                                              |  |                         | 888     |   |      |   | 226     |      |  |   | 473     |  
|                                                                      |  |                         |         |   |      |   |         |      |  |   |         |  
|                                                                      |  |                         | 304,090 |   |      |   | 188,563 |      |  |   | 204,139 |  
|                                                                      |  |                         |         |   |      |   |         |      |  |   |         |  
|Costs and Expenses                                                    |  |                         |         |   |      |   |         |      |  |   |         |  
|Production expenses                                                   |  |                         | 92,084  |   |      |   | 74,167  |      |  |   | 60,221  |  
|Production and other taxes                                            |  |                         | 10,125  |   |      |   | 4,284   |      |  |   | 3,574   |  
|Gathering and transportation expenses                                 |  |                         | 2,610   |   |      |   |        |      |  |   |        |  
|General and administrative                                            |  |                         |         |   |      |   |         |      |  |   |         |  
|G&A excluding items below                                             |  |                         | 19,884  |   |      |   | 10,756  |      |  |   | 10,210  |  
|Stock appreciation rights                                             |  |                         | 18,010  |   |      |   | 3,653   |      |  |   |        |  
|Merger related costs                                                  |  |                         | 5,264   |   |      |   |        |      |  |   |        |  
|Spin-off costs                                                        |  |                         |        |   |      |   | 777     |      |  |   |        |  
|Depreciation, depletion, amortization and accretion                   |  |                         | 52,484  |   |      |   | 30,359  |      |  |   | 24,105  |  
|                                                                      |  |                         |         |   |      |   |         |      |  |   |         |  
|                                                                      |  |                         | 200,461 |   |      |   | 123,996 |      |  |   | 98,110  |  
|                                                                      |  |                         |         |   |      |   |         |      |  |   |         |  
|Income from Operations                                                |  |                         | 103,629 |   |      |   | 64,567  |      |  |   | 106,029 |  
|Other Income (Expense)                                                |  |                         |         |   |      |   |         |      |  |   |         |  
|Interest expense                                                      |  |                         | (23,778 | ) |      |   | (19,377 | )    |  |   | (17,411 | )
|Gain on derivatives                                                   |  |                         | 847     |   |      |   |        |      |  |   |        |  
|Expenses of terminated public equity offering                         |  |                         |        |   |      |   | (2,395  | )    |  |   |        |  
|Interest and other income (expense)                                   |  |                         | (159    | ) |      |   | 174     |      |  |   | 463     |  
|                                                                      |  |                         |         |   |      |   |         |      |  |   |         |  
|Income Before Income Taxes and Cumulative Effect of Accounting Change |  |                         | 80,539  |   |      |   | 42,969  |      |  |   | 89,081  |  
|Income tax expense                                                    |  |                         |         |   |      |   |         |      |  |   |         |  
|Current                                                               |  |                         | (1,224  | ) |      |   | (6,353  | )    |  |   | (6,014  | )
|Deferred                                                              |  |                         | (32,228 | ) |      |   | (10,379 | )    |  |   | (28,374 | )
|                                                                      |  |                         |         |   |      |   |         |      |  |   |         |  
|Income Before Cumulative Effect of Accounting Change                  |  |                         | 47,087  |   |      |   | 26,237  |      |  |   | 54,693  |  
|Cumulative effect of accounting change, net of tax benefit            |  |                         | 12,324  |   |      |   |        |      |  |   | (1,522  | )
|                                                                      |  |                         |         |   |      |   |         |      |  |   |         |  
|Net Income                                                            |  | $                       | 59,411  |   |      | $ | 26,237  |      |  | $ | 53,171  |  
|                                                                      |  |                         |         |   |      |   |         |      |  |   |         |  
|Earnings per share, basic and diluted                                 |  |                         |         |   |      |   |         |      |  |   |         |  
|Income before cumulative effect of accounting change                  |  | $                       | 1.41    |   |      | $ | 1.08    |      |  | $ | 2.26    |  
|Cumulative effect of accounting change                                |  |                         | 0.37    |   |      |   |        |      |  |   | (0.06   | )
|                                                                      |  |                         |         |   |      |   |         |      |  |   |         |  
|Net income                                                            |  | $                       | 1.78    |   |      | $ | 1.08    |      |  | $ | 2.20    |  
|                                                                      |  |                         |         |   |      |   |         |      |  |   |         |  
|Weighted Average Shares Outstanding                                   |  |                         |         |   |      |   |         |      |  |   |         |  
|Basic                                                                 |  |                         | 33,321  |   |      |   | 24,193  |      |  |   | 24,200  |  
|                                                                      |  |                         |         |   |      |   |         |      |  |   |         |  
|Diluted                                                               |  |                         | 33,469  |   |      |   | 24,201  |      |  |   | 24,200  |  
|                                                                      |  |                         |         |   |      |   |         |      |  |   |         |  



See notes to consolidated
financial statements.



F-4



---

##### Table of Contents

PLAINS EXPLORATION & PRODUCTION COMPANY



CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands of dollars)



|                                                           |  |                         |          |   |      |   |          |      |  |   |          |  
|---------------------------------------------------------- |  | ----------------------- | -------- | - | ---- | - | -------- | ---- |  | - | -------- | -
|                                                           |  | Year Ended December 31, |         
|                                                           |  | 2003                    |          |   | 2002 |   |          | 2001 | 
|CASH FLOWS FROM OPERATING ACTIVITIES                       |  |                         |          |   |      |   |          |      |  |   |          |  
|Net income                                                 |  | $                       | 59,411   |   |      | $ | 26,237   |      |  | $ | 53,171   |  
|Items not affecting cash flows from operating activities   |  |                         |          |   |      |   |          |      |  |   |          |  
|Depreciation, depletion, amortization and accretion        |  |                         | 52,484   |   |      |   | 30,359   |      |  |   | 24,105   |  
|Deferred income taxes                                      |  |                         | 32,228   |   |      |   | 10,379   |      |  |   | 28,374   |  
|Cumulative effect of adoption of accounting change         |  |                         | (12,324  | ) |      |   |         |      |  |   | 1,522    |  
|Noncash compensation                                       |  |                         | 20,897   |   |      |   | 32       |      |  |   |         |  
|Change in derivative fair value                            |  |                         |         |   |      |   |         |      |  |   | 1,055    |  
|Gain on derivatives                                        |  |                         | (847     | ) |      |   |         |      |  |   |         |  
|Other noncash items                                        |  |                         | 123      |   |      |   | 425      |      |  |   | 996      |  
|Change in assets and liabilities from operating activities |  |                         |          |   |      |   |          |      |  |   |          |  
|Accounts receivable and other assets                       |  |                         | (3,548   | ) |      |   | (11,964  | )    |  |   | 9,197    |  
|Inventories                                                |  |                         | 91       |   |      |   | (576     | )    |  |   | (591     | )
|Payable to Plains Resources Inc.                           |  |                         | (1,435   | ) |      |   | 4,946    |      |  |   |         |  
|Accounts payable and other liabilities                     |  |                         | (28,802  | ) |      |   | 18,988   |      |  |   | (1,021   | )
|                                                           |  |                         |          |   |      |   |          |      |  |   |          |  
|Net cash provided by operating activities                  |  |                         | 118,278  |   |      |   | 78,826   |      |  |   | 116,808  |  
|                                                           |  |                         |          |   |      |   |          |      |  |   |          |  
|CASH FLOWS FROM INVESTING ACTIVITIES                       |  |                         |          |   |      |   |          |      |  |   |          |  
|Acquisition, exploration and development costs             |  |                         | (122,070 | ) |      |   | (64,497  | )    |  |   | (125,753 | )
|Additions to other property and equipment                  |  |                         | (2,514   | ) |      |   | (190     | )    |  |   | (127     | )
|Proceeds from property sales                               |  |                         | 23,420   |   |      |   | 529      |      |  |   |         |  
|Acquisition of 3TEC Energy Corporation                     |  |                         | (267,546 | ) |      |   |         |      |  |   |         |  
|                                                           |  |                         |          |   |      |   |          |      |  |   |          |  
|Net cash used in investing activities                      |  |                         | (368,710 | ) |      |   | (64,158  | )    |  |   | (125,880 | )
|                                                           |  |                         |          |   |      |   |          |      |  |   |          |  
|CASH FLOWS FROM FINANCING ACTIVITIES                       |  |                         |          |   |      |   |          |      |  |   |          |  
|Principal payments of long-term debt                       |  |                         | (511     | ) |      |   | (511     | )    |  |   | (511     | )
|Revolving credit facility                                  |  |                         |          |   |      |   |          |      |  |   |          |  
|Borrowings                                                 |  |                         | 471,600  |   |      |   | 212,300  |      |  |   |         |  
|Repayments                                                 |  |                         | (296,400 | ) |      |   | (176,500 | )    |  |   |         |  
|Proceeds from debt issuance                                |  |                         | 80,061   |   |      |   | 196,752  |      |  |   |         |  
|Debt issuance costs                                        |  |                         | (4,349   | ) |      |   | (5,936   | )    |  |   |         |  
|Contribution from Plains Resources Inc.                    |  |                         | 510      |   |      |   | 52,200   |      |  |   |         |  
|Distribution to Plains Resources Inc.                      |  |                         |         |   |      |   | (311,964 | )    |  |   |         |  
|Receipts from (payments to) Plains Resources Inc.          |  |                         |         |   |      |   | 20,363   |      |  |   | 9,060    |  
|Other                                                      |  |                         | (130     | ) |      |   | (357     | )    |  |   |         |  
|                                                           |  |                         |          |   |      |   |          |      |  |   |          |  
|Net cash provided by (used in) financing activities        |  |                         | 250,781  |   |      |   | (13,653  | )    |  |   | 8,549    |  
|                                                           |  |                         |          |   |      |   |          |      |  |   |          |  
|Net increase (decrease) in cash and cash equivalents       |  |                         | 349      |   |      |   | 1,015    |      |  |   | (523     | )
|Cash and cash equivalents, beginning of period             |  |                         | 1,028    |   |      |   | 13       |      |  |   | 536      |  
|                                                           |  |                         |          |   |      |   |          |      |  |   |          |  
|Cash and cash equivalents, end of period                   |  | $                       | 1,377    |   |      | $ | 1,028    |      |  | $ | 13       |  
|                                                           |  |                         |          |   |      |   |          |      |  |   |          |  



See notes to consolidated
financial statements.



F-5



---

##### Table of Contents

PLAINS EXPLORATION & PRODUCTION COMPANY



CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(in thousands of dollars)



|                                                                                                  |  |                         |         |   |      |   |         |      |  |   |        |  
|------------------------------------------------------------------------------------------------- |  | ----------------------- | ------- | - | ---- | - | ------- | ---- |  | - | ------ | -
|                                                                                                  |  | Year Ended December 31, |        
|                                                                                                  |  | 2003                    |         |   | 2002 |   |         | 2001 | 
|Net Income                                                                                        |  | $                       | 59,411  |   |      | $ | 26,237  |      |  | $ | 53,171 |  
|                                                                                                  |  |                         |         |   |      |   |         |      |  |   |        |  
|Other Comprehensive Income (Loss)                                                                 |  |                         |         |   |      |   |         |      |  |   |        |  
|Commodity hedging contracts:                                                                      |  |                         |         |   |      |   |         |      |  |   |        |  
|Cumulative effect of accounting change, net of taxesof $4,454                                     |  |                         |        |   |      |   |        |      |  |   | 6,967  |  
|Change in fair value, net of taxes of $(32,859), $(24,970)and $7,634                              |  |                         | (50,429 | ) |      |   | (37,298 | )    |  |   | 10,978 |  
|Reclassification adjustment for settled contracts, net of taxes of $(14,860), $(5,897) and $1,388 |  |                         | 22,704  |   |      |   | 8,850   |      |  |   | (2,061 | )
|Interest rate swap, net of taxes of $52 and $(119)                                                |  |                         | 79      |   |      |   | (178    | )    |  |   |       |  
|Other, net of taxes of $43 and $(77)                                                              |  |                         | 65      |   |      |   | (116    | )    |  |   |       |  
|                                                                                                  |  |                         |         |   |      |   |         |      |  |   |        |  
|                                                                                                  |  |                         | (27,581 | ) |      |   | (28,742 | )    |  |   | 15,884 |  
|                                                                                                  |  |                         |         |   |      |   |         |      |  |   |        |  
|Comprehensive Income (Loss)                                                                       |  | $                       | 31,830  |   |      | $ | (2,505  | )    |  | $ | 69,055 |  
|                                                                                                  |  |                         |         |   |      |   |         |      |  |   |        |  







See notes to consolidated financial statements.



F-6



---

##### Table of Contents

PLAINS EXPLORATION AND PRODUCTION COMPANY



STATEMENTS OF STOCKHOLDERS EQUITY

(share and dollar amounts in thousands)



|                                                                            |  |                         |          |   |              |        |                            |  |   |                   |  |                                        |         |   |                |   |        |       |   |         |   |  |     |   |  |   |      |   |  |   |          |  
|--------------------------------------------------------------------------- |  | ----------------------- | -------- | - | ------------ | ------ | -------------------------- |  | - | ----------------- |  | -------------------------------------- | ------- | - | -------------- | - | ------ | ----- | - | ------- | - |  | --- | - |  | - | ---- | - |  | - | -------- | -
|                                                                            |  | Combined Owners Equity |          |   | Common Stock |        | Additional Paid-in Capital |  |   | Retained Earnings |  | Accumulated Other Comprehensive Income |         |   | Treasury Stock |   |        | Total |  
|                                                                            |  | Shares                  |          |   | Amount       |        |                            |  |   | Shares            |  |                                        | Amount  |   |               
|Balance atDecember 31, 2000                                                 |  | $                       | 111,032  |   |              |       |                            |  | $ |                  |  | $                                      |        |   |                | $ |       |       | $ |        |   |  |    |   |  | $ |     |   |  | $ | 111,032  |  
|Net income                                                                  |  |                         | 53,171   |   |              |       |                            |  |   |                  |  |                                        |        |   |                |   |       |       |   |        |   |  |    |   |  |   |     |   |  |   | 53,171   |  
|Other comprehensive income                                                  |  |                         |         |   |              |       |                            |  |   |                  |  |                                        |        |   |                |   |       |       |   | 15,884  |   |  |    |   |  |   |     |   |  |   | 15,884   |  
|                                                                            |  |                         |          |   |              |        |                            |  |   |                   |  |                                        |         |   |                |   |        |       |   |         |   |  |     |   |  |   |      |   |  |   |          |  
|Balance atDecember 31, 2001                                                 |  |                         | 164,203  |   |              |       |                            |  |   |                  |  |                                        |        |   |                |   |       |       |   | 15,884  |   |  |    |   |  |   |     |   |  |   | 180,087  |  
|Net income                                                                  |  |                         | 14,082   |   |              |       |                            |  |   |                  |  |                                        |        |   |                |   | 12,155 |       |   |        |   |  |    |   |  |   |     |   |  |   | 26,237   |  
|Contribution of amounts due to Plains Resources Inc.                        |  |                         | 255,991  |   |              |       |                            |  |   |                  |  |                                        |        |   |                |   |       |       |   |        |   |  |    |   |  |   |     |   |  |   | 255,991  |  
|Distribution to Plains Resources Inc.                                       |  |                         | (311,964 | ) |              |       |                            |  |   |                  |  |                                        |        |   |                |   |       |       |   |        |   |  |    |   |  |   |     |   |  |   | (311,964 | )
|Cash contribution by Plains Resources Inc.                                  |  |                         | 5,000    |   |              |       |                            |  |   |                  |  |                                        |        |   |                |   |       |       |   |        |   |  |    |   |  |   |     |   |  |   | 5,000    |  
|Incorporation and capitalization of Plains Exploration & Production Company |  |                         | (127,312 | ) |              | 24,200 |                            |  |   | 242               |  |                                        | 127,070 |   |                |   |       |       |   |        |   |  |    |   |  |   |     |   |  |   |         |  
|Contributions by Plains Resources Inc.                                      |  |                         |          |   |              |        |                            |  |   |                   |  |                                        |         |   |                |   |        |       |   |         |   |  |     |   |  |   |      |   |  |   |          |  
|Cash                                                                        |  |                         |         |   |              |       |                            |  |   |                  |  |                                        | 47,200  |   |                |   |       |       |   |        |   |  |    |   |  |   |     |   |  |   | 47,200   |  
|Other                                                                       |  |                         |         |   |              |       |                            |  |   |                  |  |                                        | 4,314   |   |                |   |       |       |   |        |   |  |    |   |  |   |     |   |  |   | 4,314    |  
|Spin-off by Plains Resources Inc.                                           |  |                         |         |   |              | (141   | )                          |  |   |                  |  |                                        | (4,335  | ) |                |   |       |       |   |        |   |  |    |   |  |   |     |   |  |   | (4,335   | )
|Restricted stock awards                                                     |  |                         |          |   |              |        |                            |  |   |                   |  |                                        |         |   |                |   |        |       |   |         |   |  |     |   |  |   |      |   |  |   |          |  
|Issuance of restricted stock                                                |  |                         |         |   |              | 165    |                            |  |   | 2                 |  |                                        | 1,500   |   |                |   |       |       |   |        |   |  |    |   |  |   |     |   |  |   | 1,502    |  
|Deferred compensation                                                       |  |                         |         |   |              |       |                            |  |   |                  |  |                                        | (1,470  | ) |                |   |       |       |   |        |   |  |    |   |  |   |     |   |  |   | (1,470   | )
|Other comprehensive income                                                  |  |                         |         |   |              |       |                            |  |   |                  |  |                                        |        |   |                |   |       |       |   | (28,742 | ) |  |    |   |  |   |     |   |  |   | (28,742  | )
|                                                                            |  |                         |          |   |              |        |                            |  |   |                   |  |                                        |         |   |                |   |        |       |   |         |   |  |     |   |  |   |      |   |  |   |          |  
|Balance atDecember 31, 2002                                                 |  |                         |         |   |              | 24,224 |                            |  |   | 244               |  |                                        | 174,279 |   |                |   | 12,155 |       |   | (12,858 | ) |  |    |   |  |   |     |   |  |   | 173,820  |  
|Net income                                                                  |  |                         |         |   |              |       |                            |  |   |                  |  |                                        |        |   |                |   | 59,411 |       |   |        |   |  |    |   |  |   |     |   |  |   | 59,411   |  
|Cash contribution by Plains Resources Inc.                                  |  |                         |         |   |              |       |                            |  |   |                  |  |                                        | 510     |   |                |   |       |       |   |        |   |  |    |   |  |   |     |   |  |   | 510      |  
|Acquisition of 3TEC Energy Corporation                                      |  |                         |         |   |              | 16,071 |                            |  |   | 159               |  |                                        | 152,027 |   |                |   |       |       |   |        |   |  |    |   |  |   |     |   |  |   | 152,186  |  
|Issuance of common stock                                                    |  |                         |          |   |              | 5      |                            |  |   |                  |  |                                        | 62      |   |                |   |       |       |   |        |   |  |    |   |  |   |     |   |  |   | 62       |  
|Restricted stock awards                                                     |  |                         |          |   |              |        |                            |  |   |                   |  |                                        |         |   |                |   |        |       |   |         |   |  |     |   |  |   |      |   |  |   |          |  
|Issuance of restricted stock                                                |  |                         |         |   |              | 16     |                            |  |   |                  |  |                                        |        |   |                |   |       |       |   |        |   |  | (17 | ) |  |   | (130 | ) |  |   | (130     | )
|Deferred compensation                                                       |  |                         |         |   |              |       |                            |  |   |                  |  |                                        | 2,887   |   |                |   |       |       |   |        |   |  |    |   |  |   |     |   |  |   | 2,887    |  
|Spin-off by Plains Resources Inc.                                           |  |                         |         |   |              |       |                            |  |   |                  |  |                                        | (6,909  | ) |                |   |       |       |   |        |   |  |    |   |  |   |     |   |  |   | (6,909   | )
|Other comprehensive income                                                  |  |                         |         |   |              |       |                            |  |   |                  |  |                                        |        |   |                |   |       |       |   | (27,581 | ) |  |    |   |  |   |     |   |  |   | (27,581  | )
|                                                                            |  |                         |          |   |              |        |                            |  |   |                   |  |                                        |         |   |                |   |        |       |   |         |   |  |     |   |  |   |      |   |  |   |          |  
|Balance atDecember 31, 2003                                                 |  |                         |         |   |              | 40,316 |                            |  | $ | 403               |  | $                                      | 322,856 |   |                | $ | 71,566 |       | $ | (40,439 | ) |  | (17 | ) |  | $ | (130 | ) |  | $ | 354,256  |  
|                                                                            |  |                         |          |   |              |        |                            |  |   |                   |  |                                        |         |   |                |   |        |       |   |         |   |  |     |   |  |   |      |   |  |   |          |  



See notes to consolidated
financial statements.



F-7



---

##### Table of Contents

PLAINS EXPLORATION & PRODUCTION COMPANY



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS



Note 1Organization
and Significant Accounting Policies



Organization



The consolidated financial statements of Plains Exploration & Production Company
(PXP, us, our, or we) include the accounts of our wholly-owned subsidiaries Arguello Inc., Plains Illinois, Inc., PXP Gulf Coast Inc. and other immaterial subsidiaries. We are a Delaware corporation
that was converted from a limited partnership in September 2002. All significant intercompany transactions have been eliminated. Certain reclassifications have been made to prior year statements to conform to the current year presentation.



We are an independent energy company that is engaged in the
upstream oil and gas business. The upstream business acquires, exploits, develops, explores for and produces oil and gas. Our upstream activities are all located in the United States.



Under the terms of a Master Separation Agreement between us and Plains Resources, on
July 3, 2002, Plains Resources contributed to us: (i) 100% of the capital stock of its wholly owned subsidiaries that own oil and gas properties offshore California and in Illinois; and (ii) all amounts payable to it by us and our subsidiary
companies (the reorganization). The contribution of the amounts payable to Plains Resources is reflected in Stockholders Equity.



On July 3, 2002, we issued $200.0 million of 8.75% Senior Subordinated Notes due 2012 (the 8.75% Notes) and entered into a $300.0 million revolving
credit facility. The net proceeds from the 8.75% notes, $195.3 million, and $116.7 million borrowed under the credit facility were used to pay a $312.0 million cash distribution to Plains Resources.



Effective at the time of the reorganization we assumed direct ownership and control of
Arguello Inc., Plains Illinois, Inc., and two other subsidiaries. Accordingly, for periods subsequent to the reorganization, the financial information is presented on a consolidated basis. For periods prior to the reorganization, the historical
operations of the businesses owned by PXP, Arguello Inc., Plains Illinois, Inc. and the two other subsidiaries, all previously referred to as the Upstream Subsidiaries of Plains Resources Inc., were presented on a carve-out combined basis since no
direct owner relationship existed among the various operations comprising these businesses. Accordingly, Plains Resources net investment in the businesses (combined owners equity) was shown in lieu of stockholders equity in the
historical financial statements.



In June 2002, we filed a registration
statement on Form S-1 with the Securities and Exchange Commission (the SEC) for the initial public offering (the IPO), of our common stock. We terminated the IPO in October 2002, primarily due to market conditions. As a
result, costs and expenses of $2.4 million incurred in connection with the IPO were charged to expense during 2002.



In September 2002, we were capitalized with 24.2 million shares of common stock, all of which were owned by Plains Resources. As a result of the capitalization,
Combined Owners Equity as of June 30, 2002 was reclassified between Common Stock and Additional Paid-in Capital. Retained Earnings as December 31, 2002 represents our earnings from June 30, 2002 through December 31, 2002.



On December 18, 2002, Plains Resources distributed 24.1 million of the issued and
outstanding shares of our common stock to the holders of Plains Resources common stock on the basis of one



F-8



---

##### Table of Contents

share of our common stock for every one share of Plains Resources common stock held as of the close of business on December 11, 2002 (the spin-off) and
contributed 0.1 million shares of our common stock to us. Prior to the spin-off Plains Resources made a $52.2 million cash capital contribution to us and transferred to us certain assets and liabilities of Plains Resources ($4.3 million, net),
primarily related to land, unproved oil and gas properties, office equipment and compensation obligations. In addition, as a result of the spin-off certain tax attributes previously considered in the deferred income tax liabilities allocated to us
($4.3 million) and recognized in our financial statements remained with Plains Resources. The cash contributions, the transfer of assets and the assumption of certain liabilities by us and the effect of the increase in our deferred tax liabilities
are reflected in Additional Paid-in Capital in Stockholders Equity.



On June 4, 2003, we acquired 3TEC Energy Corporation, or 3TEC. We have accounted for the acquisition as a purchase with effect from June 1, 2003. See Note 2.



These financial statements include allocations of direct and indirect corporate and administrative costs of Plains Resources made
prior to the reorganization. The methods by which such costs were estimated and allocated to us were deemed reasonable by Plains Resources 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 5.



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 estimated asset retirement
obligations recorded in accordance with Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations (SFAS 143), 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.



Asset Retirement Obligations.    Effective January 1, 2003,
we adopted SFAS 143 which requires entities to record the fair value of a liability for a legal obligation to retire an asset in the period in which the liability is incurred. A legal obligation is a liability that a party is required to settle as a
result of an existing or enacted law, statute, ordinance or contract. When the liability is initially recorded, the entity is required to capitalize the retirement cost of the related long-lived asset. Each period the liability is accreted to its
then present value, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized. In prior periods we included estimated
future costs of abandonment and dismantlement in our full cost amortization base and these costs were amortized as a component of our depletion expense.



F-9



---

##### Table of Contents

At January 1, 2003, the present value of our future asset retirement obligation for oil and gas properties and
equipment was $26.5 million. The cumulative effect of our adoption of SFAS 143 and the change in accounting principle resulted in an increase in net income during the first quarter of 2003 of $12.3 million (reflecting a $30.8 million decrease in
accumulated depreciation, depletion and amortization, partially offset by $10.6 million in accretion expense, and $7.9 million in income taxes). We recorded a liability of $26.5 million and an asset of $15.9 million in connection with the adoption
of SFAS 143. Adopting SFAS No. 143 did not impact our cash flows.



The
following table illustrates the changes in our asset retirement obligation during the period (in thousands):



|                                                |  |                         |        |     |           |   |           |  |   |       
|----------------------------------------------- |  | ----------------------- | ------ | --- | --------- | - | --------- |  | - | ------
|                                                |  | Year Ended December 31,
|                                                |  | 2003                    |        |     | 2002      |   | 2001     
|                                                |  |                         |        |     | Pro forma |   | Pro forma
|Asset retirement obligationbeginning of period |  | $                       | 26,540 |     |           | $ | 21,008    |  | $ | 19,262
|Liabilities incurred                            |  |                         | 5,409  |     |           |   | 3,630     |  |   |      
|Accretion expense                               |  |                         | 2,637  |     |           |   | 1,902     |  |   | 1,746 
|Asset retirement cost settlements               |  |                         | (851   | )   |           |   |          |  |   |      
|                                                |  |                         |        |     |           |   |           |  |   |       
|Asset retirement obligationend of period       |  | $                       | 33,735 | (1) |           | $ | 26,540    |  | $ | 21,008
|                                                |  |                         |        |     |           |   |           |  |   |       

---

|(1) |  | $500 included in current liabilities.
|--- |  | -------------------------------------



The following table illustrates on a pro forma basis the effect on our net income and earnings per share as if SFAS 143 had been applied during the years ended
December 31, 2002 and 2001 (thousands of dollars, except per share data):



|                                                                                        |  |                         |        |      |   |       
|--------------------------------------------------------------------------------------- |  | ----------------------- | ------ | ---- | - | ------
|                                                                                        |  | Pro Forma              
|                                                                                        |  | Year Ended December 31,
|                                                                                        |  | 2002                    |        | 2001
|Net incomeas reported                                                                  |  | $                       | 26,237 |      | $ | 53,171
|Adjustment for effect of change in accounting that is retroactively applied, net of tax |  |                         | 1,194  |      |   | 1,210 
|                                                                                        |  |                         |        |      |   |       
|Pro forma net income                                                                    |  | $                       | 27,431 |      | $ | 54,381
|                                                                                        |  |                         |        |      |   |       
|Earnings per share:                                                                     |  |                         |        |      |   |       
|Basicas reported                                                                       |  | $                       | 1.08   |      | $ | 2.20  
|Adjustment for effect of change in accounting that is retroactively applied, net of tax |  |                         | 0.05   |      |   | 0.05  
|                                                                                        |  |                         |        |      |   |       
|Basicpro forma                                                                         |  | $                       | 1.13   |      | $ | 2.25  
|                                                                                        |  |                         |        |      |   |       
|Dilutedas reported                                                                     |  | $                       | 1.08   |      | $ | 2.20  
|Adjustment for effect of change in accounting that is retroactively applied, net of tax |  |                         | 0.05   |      |   | 0.05  
|                                                                                        |  |                         |        |      |   |       
|Dilutedpro forma                                                                       |  | $                       | 1.13   |      | $ | 2.25  
|                                                                                        |  |                         |        |      |   |       



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.



F-10



---

##### Table of Contents

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) oil and natural gas reserves; (2) depreciation, depletion and amortization, including future abandonment costs; (3)
assigning fair value and allocating purchase price in connection with business combinations, including goodwill; (4) income taxes; (5) accrued liabilities; and (6) valuation of derivative instruments. 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, 2003 and 2002, the majority
of cash and cash equivalents is concentrated in two institutions and at times may exceed federally insured limits. We periodically assess the financial condition of the institutions and believe that any possible credit risk is minimal.



Inventory.    Oil inventories are carried at the lower of
the 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,
|                       |  | 2003         |       | 2002
|Oil                    |  | $            | 863   |      | $ | 730  
|Materials and supplies |  |              | 4,455 |      |   | 4,468
|                       |  |              |       |      |   |      
|                       |  | $            | 5,318 |      | $ | 5,198
|                       |  |              |       |      |   |      



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



|                            |  |              |        |      |   |       
|--------------------------- |  | ------------ | ------ | ---- | - | ------
|                            |  | December 31,
|                            |  | 2003         |        | 2002
|Land                        |  | $            | 8,853  |      | $ | 8,853 
|Commodity hedging contracts |  |              |       |      |   | 1,432 
|Debt issue costs, net       |  |              | 8,068  |      |   | 5,485 
|Other                       |  |              | 2,720  |      |   | 3,159 
|                            |  |              |        |      |   |       
|                            |  | $            | 19,641 |      | $ | 18,929
|                            |  |              |        |      |   |       



Costs incurred in connection
with the issuance of long-term debt are capitalized and amortized using the straight-line method over the term of the related debt. Use of the straight-line method does not differ materially from the effective interest method of
amortization.



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 likely than not that the
related tax benefits will not be realized.



Under the terms of a tax
allocation agreement, our taxable income or loss prior to the spin-off was included in the consolidated income tax returns filed by Plains Resources. To the extent Plains



F-11



---

##### Table of Contents

Resources net operating losses were used in the consolidated return to offset our taxable income from operations during the period January 1, 2002 through the
spin-off, we will reimburse Plains Resources for the reduction in our federal income tax liability resulting from the utilization of such net operating losses, but such reimbursement shall not exceed $3.0 million exclusive of any interest accruing
under the agreement. At December 31, 2003 and 2002 other long-term liabilities includes $3.0 million payable to Plains Resources with respect to the utilization of net operating losses. Such amount will be paid to Plains Resources in periods in
which they are in a currently taxable position.



Income tax obligations
reflected in our financial statements in periods prior to the spin-off are calculated assuming we filed a separate consolidated income tax return. To reflect differences between the amounts included in our financial statements at December 31, 2002
and the final 2002 tax returns filed by us and Plains Resources, income tax expense for the year ended December 31, 2003 includes a $1.7 million charge (a $3.8 million deferred tax expense that includes a $1.7 million adjustment to reflect an
increase in our effective state income tax rate, partially offset by a $2.1 million current tax benefit) and our deferred tax liability at December 31, 2002 has been adjusted by $4.8 million. Such adjustments resulted in a $6.9 million decrease in
our Additional Paid-in Capital.



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 oil and gas. The derivative instruments consist primarily of oil and gas swap and option contracts entered into with financial institutions. Gains and losses on derivative instruments that qualify for
hedge accounting are included in oil and gas revenues in the period the related volumes are delivered. Changes in the fair value of derivative instruments that do not qualify for hedge accounting are recognized in other income (expense). See Note 3.



Stock Based Compensation.    We account for
stock based compensation using the intrinsic value method. See Note 6.



Earnings Per Share.    In September 2002, we were capitalized with 24,200,000 shares of common stock, all of which were owned by Plains Resources. In accordance with SEC Staff Accounting Bulletin No. 98, this
capitalization has been retroactively reflected for purposes for calculating earnings per share for the year ended December 31, 2001. The weighted average shares outstanding for computing both basic and diluted earnings per share was 24,200,000
shares for the year ended December 31, 2001. Weighted average shares outstanding for computing basic and diluted earnings per share were 33,321,000 and 33,460,000, respectively, for the year ended December 31, 2003 and 24,193,000 and 24,201,000,
respectively, for the year ended December 31, 2002. In computing EPS, no adjustments were made to reported net income. In 2003 and 2002, the difference between basic and diluted shares relates to non-vested restricted stock and in 2001 there was no
potential common stock.



Goodwill.    In a
purchase transaction, goodwill represents the excess of the purchase price plus the liabilities assumed, including deferred income taxes recorded in connection with the transaction, over the fair value of the net assets acquired. Goodwill is not
amortized, but instead must be tested at least annually for impairment by applying a fair-value based test. Goodwill is deemed impaired to the extent of any excess of its carrying amount over the residual fair value of the reporting unit. Such
impairment could significantly reduce earnings during the period in which the impairment occurs and would result in a corresponding reduction to goodwill and stockholders equity. The most significant factors that could result in the impairment
of our goodwill would be significant declines in oil and gas prices and/or reserve volumes which would result in a decline in the fair value of our oil and gas properties.



F-12



---

##### Table of Contents

Recent Accounting Pronouncements.    The Financial Accounting Standards Board (FASB)
issued Financial Interpretation No. 46 (FIN 46), Consolidation of Variable Interest Entities in January 2003. FIN 46 addresses the consolidation of variable interest entities (VIEs) by business enterprises that are the primary
beneficiaries. A VIE is an entity that does not have sufficient equity investment at risk to permit it to finance its activities without additional subordinated financial support, or whose equity investors lack the characteristics of a controlling
financial interest. The primary beneficiary of a VIE is the enterprise that has the majority of the risks or rewards associated with the VIE. In December 2003, the FASB issued a revision to FIN 46, Interpretation No. 46R (FIN 46R), to clarify some
of the provisions of FIN 46, and to exempt certain entities from its requirements. Application of FIN 46R is required in financial statements of public entities that have interests in structures that are commonly referred to as special-purpose
entities for periods ending after December 15, 2003. Application for all other types of VIEs is required in financial statements for periods ending after March 15, 2004. We do not believe we participate in any arrangement that would be subject to
the provisions of FIN 46R.



In 2003, the SEC inquired of the FASB
regarding the application of certain provisions of SFAS No. 141, Business Combinations,(SFAS No. 141) and SFAS No. 142, Goodwill and Other Intangible Assets,(SFAS No. 142) to oil and gas companies. SFAS Nos.
141 and 142 became effective for transactions subsequent to June 30, 2001. SFAS No. 141 requires that all business combinations initiated after June 30, 2001 be accounted for using the purchase method and that acquired intangible assets be
disaggregated and reported separately from goodwill. Specifically, the SECs inquiry is based on whether costs of contract-based drilling and mineral use rights (mineral rights) should be recorded and disclosed as intangible assets
under the guidance in SFAS Nos. 141 and 142. The current practice for us and the industry is to present oil and gas related assets, including mineral rights, as property and equipment (tangible assets) on the balance sheet. Subsequent to June 30,
2001, we entered into a business combination with 3TEC and the majority of the purchase price was allocated to oil and gas properties.



An Emerging Issues Task Force Working Group (EITF) has been created to research the accounting and disclosure treatment of mineral rights for oil and
gas companies. As a result, the EITF has added Issue No. 04-2, Whether Mineral Rights are Tangible or Intangible Assets and Related Issues, and Issue No. 03-S, Application of FASB Statement No. 142, Goodwill and Other Intangible
Assets, to Oil and Gas Companies. Currently, we do not believe that generally accepted accounting principles require the classification of mineral rights as intangible assets and continues to classify these assets as oil and gas properties.
However, the decisions of the EITF may affect how we classify these assets in the future. If the EITF ultimately determines that SFAS Nos. 141 and 142 require oil and gas companies to classify mineral rights as separate intangible assets, at
December 31, 2003, we had undeveloped leaseholds of approximately $32.0 million that would be reclassified as intangible undeveloped leasehold and developed leaseholds of approximately $278.0 million that would be reclassified as
intangible developed leasehold. The amounts that would be subject to this reclassification included in our historical balance sheet prior to the acquisition of 3TEC is not material



Amounts to be reclassified would be impacted by the provisions of the EITF consensus.
The ultimate reclassification amount could be materially different than the above amounts as numerous decisions that could be included in the consensus would impact the composition and amortization of the intangible assets, if any.



We believe that cash flows and results of operations would not be affected since such
intangible assets would likely continue to be depleted and assessed for impairment in accordance with our accounting policies as prescribed under the full cost method of accounting for oil and gas properties. Further, we do not believe the
classification of the mineral rights as intangible assets would affect compliance with covenants under our debt agreements.



F-13



---

##### Table of Contents

We will continue to classify our oil and gas mineral rights held under lease and other contractual rights
representing the right to extract such reserves as tangible oil and gas properties until further guidance is provided.



Note 2Acquisition of 3TEC Energy Corporation



On June 4, 2003, we acquired 3TEC (the merger), for approximately $312.9 million in cash and common stock plus $90.0 million to retire 3TECs
outstanding debt. In the transaction, each 3TEC common share was converted in to 0.85 of a share of our common stock and $8.50 in cash. In connection with the merger, we paid cash consideration to the common shareholders of approximately $152.4
million and issued 15.3 million shares. In addition, we paid cash consideration of $8.3 million and issued 0.8 million common shares to redeem outstanding warrants. The cash portion of the purchase price was funded by the issuance of $75.0 million
of senior subordinated notes and amounts borrowed under our revolving credit facility. We have accounted for the acquisition of 3TEC as a purchase effective June 1, 2003.



The calculation of the purchase price and the allocation to assets and liabilities as of June 4, 2003 are shown below. The average PXP
common stock price is based on the average closing price of PXP common stock during the five business days commencing two days before the merger was announced.



|                                                             |  |                                    |         |  
|------------------------------------------------------------ |  | ---------------------------------- | ------- | -
|                                                             |  | (in thousands, except share price) |        
|Calculation and allocation of purchase price:                |  |                                    |         |  
|Shares of PXP common stock issued to 3TEC stockholders       |  |                                    | 16,071  |  
|Average PXP stock price                                      |  | $                                  | 9.47    |  
|                                                             |  |                                    |         |  
|Fair value of common stock issued                            |  |                                    | 152,186 |  
|Cash to 3TEC stockholders and warrantholders                 |  |                                    | 160,720 |  
|3TEC debt retired in the merger (including accrued interest) |  |                                    | 90,065  |  
|Merger costs incurred by PXP                                 |  |                                    | 5,041   |  
|                                                             |  |                                    |         |  
|Total purchase price                                         |  | $                                  | 408,012 |  
|                                                             |  |                                    |         |  
|Fair value of assets acquired and liabilities assumed:       |  |                                    |         |  
|Current assets                                               |  | $                                  | 23,525  |  
|Oil and gas properties and equipment                         |  |                                    |         |  
|Subject to amortization                                      |  |                                    | 294,356 |  
|Not subject to amortization                                  |  |                                    | 61,116  |  
|Other properties and equipment                               |  |                                    | 218     |  
|Goodwill                                                     |  |                                    | 147,251 |  
|Current liabilities                                          |  |                                    | (73,779 | )
|Deferred tax liability related to the merger                 |  |                                    | (40,281 | )
|Other long-term liabilities                                  |  |                                    | (4,394  | )
|                                                             |  |                                    |         |  
|Total purchase price                                         |  | $                                  | 408,012 |  
|                                                             |  |                                    |         |  



Prior to the merger, 3TEC
redeemed all outstanding shares of its Series D preferred stock for $14.7 million and incurred $11.1 million of merger related costs. Current liabilities assumed in the merger include $14.7 million related to the preferred stock redemption which was
paid shortly after the merger and $1.7 million of merger related costs.



The significant factors contributing to the recognition of goodwill include, but are not limited to, providing a presence in East Texas and the Gulf Coast regions that can be used to pursue other opportunities in these areas, improving
financial flexibility with more efficient access to lower cost capital and higher returns from synergies in having a broader and more diversified reserve base and the ability to acquire an established business with an assembled workforce. In
addition, additional goodwill has been recorded due to the application of purchase accounting rules that require that deferred taxes be recorded at undiscounted amounts. The goodwill is not deductible for income tax purposes.



F-14



---

##### Table of Contents

Pro Forma Information



The following unaudited pro forma information for the years ended December 31, 2003 and 2002 have been prepared based on our
historical consolidated statements of income and the historical consolidated statements of income of 3TEC. Such pro forma information for 2003 and 2002 assumes the merger and the issuance of $75.0 million of 8.75% senior subordinated notes on May
31, 2003 occurred on January 1, 2003 and January 1, 2002, respectively. Such pro forma information for 2002 also assumes the following 2002 transactions occurred on January 1, 2002: (i) the reorganization and spin-off, discussed in Note 1; and (ii)
the July 3, 2002 issuance of $200.0 million of 8.75% senior subordinated notes, discussed in Note 4.



We believe the assumptions used provide a reasonable basis for presenting the significant effects directly attributable to the pro forma transactions. This pro
forma financial information does not purport to represent what our results of operations would have been if such transactions had occurred on such dates.



|                                                                   |  |                        |         |      |   |        
|------------------------------------------------------------------ |  | ---------------------- | ------- | ---- | - | -------
|                                                                   |  | Year Ended December31,
|(in thousands, except per share data)                              |  | 2003                   |         | 2002
|Revenues                                                           |  | $                      | 377,685 |      | $ | 291,461
|Income from operations                                             |  |                        | 147,047 |      |   | 104,211
|Net income (excluding the cumulative effect of accounting changes) |  |                        | 48,446  |      |   | 38,299 
|Earnings per share                                                 |  |                        |         |      |   |        
|Basic                                                              |  |                        | 1.20    |      |   | 0.95   
|Diluted                                                            |  |                        | 1.20    |      |   | 0.95   
|Weighted average shares outstanding                                |  |                        |         |      |   |        
|Basic                                                              |  |                        | 40,190  |      |   | 40,263 
|Diluted                                                            |  |                        | 40,256  |      |   | 40,271 



Note 3Derivative Instruments and
Hedging Activities



Derivative instruments are accounted for in
accordance with SFAS No. 133 Accounting for Derivative Instruments and Hedging Activities as amended. Under SFAS 133, all derivative instruments are recorded on the balance sheet at fair value. If a 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 a derivative qualifies for hedge accounting, the unrealized gain or loss on the derivative is deferred in accumulated Other Comprehensive
Income (OCI), a component of Stockholders Equity. 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.



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 for which hedge accounting has been discontinued remain unchanged until the related product has been 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.



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



F-15



---

##### Table of Contents

Cash Flow Hedge, or DIG Issue G20, which provides guidance for basing the assessment of hedge 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. No ineffectiveness was recognized in 2003 or 2002.



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.



We assumed several
open derivative positions in connection with the 3TEC merger. Such derivative positions were recorded at fair value in the purchase price allocation. Changes in fair value of such position subsequent to the merger have been reflected in income. All
other open derivative positions at December 31, 2003 related to production from our oil and gas properties qualified for hedge accounting.



At December 31, 2002, OCI consisted of $20.9 million ($12.6 million, net of tax) of unrealized net losses on our open hedging instruments. As oil prices increased
significantly during 2003 and we assumed 3TECs hedge positions as a result of the merger, the fair value of our open hedging positions that qualified for hedge accounting, net of settlements, decreased $45.8 million ($27.7 million after tax).
At December 31, 2003, OCI consisted of $66.7 million ($40.3 million after tax) of unrealized losses on our open hedging instruments, $0.2 million ($0.1 million, net of tax) loss related to our interest rate swap and $0.1 million ($0.1 million, net
of tax) loss related to deferred compensation liabilities. At December 31, 2003 the assets and liabilities related to our open hedging instruments were included in current liabilities ($55.1 million), other long-term liabilities ($23.7 million) and
deferred income taxes (a tax benefit of $32.1 million). At December 31, 2002, the assets and liabilities related to our open oil hedging instruments were included in current assets ($2.6 million), other assets ($1.4 million), current liabilities
($24.4 million), other long-term liabilities ($0.6 million) and deferred income taxes (a tax benefit of $8.4 million).



During 2003, 2002 and 2001, deferred gains (losses) of ($37.6 million), ($15.6 million) and $0.3 million, respectively, were reclassified from OCI and charged to
income as a reduction of oil and gas revenues. As of December 31, 2003, $43.0 million ($26.0 million, net of tax) of deferred net losses on derivative instruments recorded in OCI are expected to be reclassified to earnings during the next
twelve-month period. During 2003 we recognized $0.8 million of income from the change in the fair value of derivatives that do not qualify for hedge accounting.



F-16



---

##### Table of Contents

Commodity price risk.    At December 31, 2003 we had the following open hedge positions
with respect to our oil and gas properties:



|                               |  |        |  |        |  |       
|------------------------------ |  | ------ |  | ------ |  | ------
|                               |  | 2004   |  | 2005   |  | 2006  
|Oil Swaps                      |  |        |  |        |  |       
|Average price $23.89 per Bbl   |  | 18,500 |  |       |  |      
|Average price $24.79 per Bbl   |  |       |  | 17,500 |  |      
|Average price $25.28 per Bbl   |  |       |  |       |  | 15,000
|                               |  |        | 
|Natural Gas Swaps              |  |        |  |        |  |       
|Average price $4.45 per MMBtu  |  | 20,000 |  |       |  |      
|                               |  |        | 
|Natural Gas Costless Collars   |  |        |  |        |  |       
|Floor price of $4.00 per MMBtu |  | 20,000 |  |       |  |      
|Cap price of $5.15 per MMBtu   |  |        |  |        |  |       
|Floor price of $4.75 per MMBtu |  | 10,000 |  |       |  |      
|Cap price of $5.67 per MMBtu   |  |        |  |        |  |       



Location and quality
differentials attributable to our properties 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 barrel.



We utilize interest rate swaps to manage the interest rate exposure on our long-term
debt. We currently have an interest rate swap agreement that expires in October 2004, under which we receive LIBOR and pay 3.9% on a notional amount of $7.5 million. The interest rate swap fixes the interest rate on $7.5 million of borrowings under
our credit facility at 3.9% plus the LIBOR margin set forth in the credit facility (5.3% at December 31, 2003).



Note 4Long-Term Debt



At December 31, 2003, long-term debt consisted of (in thousands):



|                                                                                                                                     |  |                   |     |                   |   |         |  |           |     |  |   |        
|------------------------------------------------------------------------------------------------------------------------------------ |  | ----------------- | --- | ----------------- | - | ------- |  | --------- | --- |  | - | -------
|                                                                                                                                     |  | December 31, 2003 |     | December 31, 2002
|                                                                                                                                     |  | Current           |     | Long-Term         |   | Current |  | Long-Term
|Revolving credit facility                                                                                                            |  | $                 |    |                   | $ | 211,000 |  | $         |    |  | $ | 35,800 
|8.75% senior subordinated notes, net of unamortized premium of $1.9 million in 2003 and unamortized discount of $3.1 million in 2002 |  |                   |    |                   |   | 276,906 |  |           |    |  |   | 196,855
|Other                                                                                                                                |  |                   | 511 |                   |   |        |  |           | 511 |  |   | 511    
|                                                                                                                                     |  |                   |     |                   |   |         |  |           |     |  |   |        
|                                                                                                                                     |  | $                 | 511 |                   | $ | 487,906 |  | $         | 511 |  | $ | 233,166
|                                                                                                                                     |  |                   |     |                   |   |         |  |           |     |  |   |        



Revolving credit facility



On April 4, 2003, we entered into a three-year, $500.0 million
senior revolving credit facility with a group of lenders and with JP Morgan Chase Bank serving as administrative agent. The credit facility provides for a borrowing base of $402.5 million that will be redetermined on a semi-annual basis, with us and
the lenders each having the right to one annual interim unscheduled redetermination, and adjusted based on the Companys oil and gas properties, reserves, other indebtedness and other relevant factors. Additionally, the credit facility contains
a $50.0 million sub-limit on letters of credit. To secure borrowings, we pledged 100% of the shares of stock of our domestic subsidiaries and gave mortgages covering 80% of the total present value of our domestic oil and gas properties. The
effective interest rate on our borrowings under the revolving credit facility was 2.9% at December 31, 2003.



Amounts borrowed under the credit facility bear an annual interest rate, at our election, equal to either: (i) the Eurodollar rate, which is based on LIBOR, plus
from 1.375% to 2.0%; or (ii) the greatest



F-17



---

##### Table of Contents

of (1) the prime rate, as determined by JP Morgan 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 0.75% for each of (1)-(3). The amount of interest payable on outstanding borrowings is based on (1) the utilization rate as a percentage of the total amount of funds borrowed under the credit facility to the borrowing base and
(2) our long-term debt rating. Commitment fees and letter of credit fees under the credit facility are based on the utilization rate and our long-term debt rating. Commitment fees range from 0.375% to 0.5% of the unused portion of the borrowing
base. Letter of credit fees range from 1.375% to 2.0%. The issuer of any letter of credit receives an issuing fee of 0.125% of the undrawn amount.



The credit facility contains negative covenants that limit our ability, as well as the ability of our subsidiaries, among other things, to incur additional debt,
pay dividends on stock, make distributions of cash or property, change the nature of our business or operations, redeem stock or redeem subordinated debt, make investments, create liens, enter into leases, sell assets, sell capital stock of
subsidiaries, create subsidiaries, guarantee other indebtedness, enter into agreements that restrict dividends from subsidiaries, enter into certain types of swap agreements, enter into gas imbalance or take-or-pay arrangements, merge or consolidate
and enter into transactions with affiliates. In addition, the credit facility requires us to maintain a current ratio, which includes availability, of at least 1.0 to 1.0 and a minimum tangible net worth (as defined). At December 31, 2003, we were
in compliance with the covenants contained in our credit facility and could have borrowed the full amount available under the credit facility.



8.75% senior subordinated notes



On May 30, 2003, we issued $75.0 million principal amount of 8.75% senior subordinated notes due 2012 (the8.75% notes) at an issue price of 106.75%. The
proceeds were used to fund a portion of the cost of the merger.



At
December 31, 2003, we had $275.0 million principal amount of 8.75% notes outstanding. The 8.75% notes are our unsecured general obligations, are subordinated in right of payment to all of our existing and future senior indebtedness and are jointly
and severally guaranteed on a full, unconditional basis by all of our existing and future domestic restricted subsidiaries. The indenture governing the 8.75% notes contains covenants that limit our ability, as well as the ability of our
subsidiaries, among other things, to incur additional indebtedness, make certain investments, make restricted payments, sell assets, enter into agreements containing dividends and other payment restrictions affecting subsidiaries, enter into
transactions with affiliates, create liens, merge, consolidate and transfer assets and enter into different lines of business. In the event of a change of control, as defined in the indenture, we will be required to make an offer to repurchase the
notes at 101% of the principal amount thereof, plus accrued and unpaid interest to the date of the repurchase. The indenture governing the 8.75% notes permitted the spin-off and the spin-off did not, in itself, constitute a change of control for
purposes of the indenture. The merger did not constitute a change of control for purposes of the indenture.



The 8.75% notes are not redeemable until July 1, 2007. On or after that date they are redeemable, at our option, at 104.375% of the principal amount for the
twelve-month period ending June 30, 2008, at 102.917% of the principal amount for the twelve-month period ending June 30, 2009, at 101.458% of the principal amount for the twelve-month period ending June 30, 2010 and at 100% of the principal amount
thereafter. In each case, accrued interest is payable to the date of redemption.



Other



We also have a note with an outstanding
principal balance of $0.5 million at December 31, 2003 that was 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 the final annual principal
payment of $0.5 million is due in 2004.



F-18



---

##### Table of Contents

Aggregate total maturities of long-term debt in the next five years are as follows: 2004$0.5 million;
2005$0.0 million; 2006$211.0 million; 2007$0.0 million; and 2008$0.0 million.



Note 5Related Party Transactions



Prior to the reorganization, we used a centralized cash management system under which our cash receipts were remitted to Plains Resources and our cash disbursements were funded by Plains Resources. We were charged interest on any amounts,
other than income taxes payable, due to Plains Resources at the average effective interest rate of Plains Resources long-term debt. For the years ended December 31, 2002 and 2001 we were charged $10.7 million and $20.4 million, respectively, of
interest on amounts payable to Plains Resources. Of such amounts, $9.3 million and $17.3 million was included in interest expense in 2002 and 2001, respectively, and $1.4 million and $3.1 million was capitalized in oil and gas properties in 2002 and
2001, respectively.



To compensate Plains Resources for services rendered
under the Services Agreement, we were allocated direct and indirect corporate and administrative costs of Plains Resources. Such costs for the years ended December 31, 2002 and 2001 totaled $4.4 million and $8.2 million, respectively. Of such
amounts, $3.1 million and $6.1 million was included in general and administrative expense in 2002 and 2001, respectively, and $1.3 million and $2.1 million was capitalized in oil and gas properties in 2002 and 2001, respectively.



In addition, prior to the reorganization Plains Resources entered into various
derivative instruments to reduce our exposure to decreases in the market price of crude oil. At the time of the reorganization, all open derivative instruments held by Plains Resources on our behalf were assigned to us.



In connection with the reorganization and the spin-off we entered into certain
agreements with Plains Resources, including a master separation agreement; an intellectual property agreement; the Plains Exploration & Production transition services agreement; the Plains Resources transition services agreement; and a technical
services agreement. For the year ended December 31, 2003 we billed Plains Resources $0.5 million for services provided by us under these agreements and Plains Resources billed us $0.1 million for services they provided to us under these agreements.



Plains All American Pipeline, L.P. (PAA), a publicly-traded
master limited partnership, is an affiliate of Plains Resources. Certain of our officers and directors are officers and directors of Plains Resources. PAA is the exclusive marketer/purchaser for all of our oil production, including the royalty share
of production, from properties owned prior to the merger. PAA purchases for resale at market prices certain of our equity oil production. We pay PAA a marketing and administrative fee and reimburse PAA for its reasonable expenses incurred in
transporting or exchanging our oil. During the years ended December 31, 2003, 2002 and 2001, the following amounts were recorded with respect to such transactions (in thousands of dollars).



|                               |  |                         |         |      |   |         |  |   |        
|------------------------------ |  | ----------------------- | ------- | ---- | - | ------- |  | - | -------
|                               |  | Year Ended December 31,
|                               |  | 2003                    |         | 2002 |   | 2001   
|Sales of oil to PAA            |  |                         |         |      |   |         |  |   |        
|PXPs share                    |  | $                       | 238,663 |      | $ | 193,615 |  | $ | 174,614
|Royalty owners share          |  |                         | 45,703  |      |   | 35,969  |  |   | 27,468 
|                               |  |                         |         |      |   |         |  |   |        
|                               |  | $                       | 284,366 |      | $ | 229,584 |  | $ | 202,082
|                               |  |                         |         |      |   |         |  |   |        
|Charges for PAA marketing fees |  | $                       | 1,728   |      | $ | 1,633   |  | $ | 1,600  
|                               |  |                         |         |      |   |         |  |   |        



During 2003, 2002 and 2001 no
other purchaser accounted for more than 10% of our total revenues.



F-19



---

##### Table of Contents

We charter private aircraft from Gulf Coast Aviation Inc., a corporation which from time-to-time leases aircraft
owned by our Chief Executive Officer. In 2003 and 2002, we paid Gulf Coast $0.8 million and $0.2 million, respectively, in connection with charter services in which our Chief Executive Officers aircraft were used. The charter services
were arranged through arms-length dealings and the rates were market-based.



Note
6Stock and Other Compensation Plans



At the time of the
spin-off all individuals holding outstanding options to acquire Plains Resources common stock were granted an equal number of stock appreciation rights (SARs) with respect to our common stock. The exercise price of the SARs was based on
the exercise price of the Plains Resources options adjusted for the relationship of the closing price (with dividend) of Plains Resources common stock on the spin-off date ($23.05 per share) less the closing price (on a when-issued
basis) of our common stock on the spin-off date ($9.10 per share), both as reported on the NYSE, and such closing price of our common stock ($9.10 per share). All recipients of our SARs received the benefit of prior service credit at Plains
Resources and have the same amount of vesting as they had under their related Plains Resources stock options and vesting terms remain unchanged. Generally, the SARs have a pro rata vesting period of two to five years and an exercise period of five
to ten years. We issued additional SARs in 2003.



SARs are subject to
variable accounting treatment. Accordingly, at the end of each quarter, we compare the closing price of our common stock on the last day of the quarter to the exercise price of each SAR. To the extent the closing price exceeds the exercise price of
each SAR, we recognize such excess as an accounting charge for the SARs deemed vested at the end of the quarter to the extent such excess had not been recognized in previous quarters. If such excess were to be less than the extent to which
accounting charges had been recognized in previous quarters, we would recognize the difference as income in the quarter. In 2003 and 2002 we recognized charges of $18.0 million and $3.7 million, respectively, as compensation expense with respect to
SARs vested or deemed vested during the periods. In 2003 we made cash payments with respect to SARs exercised in 2003 of $2.1 million.



A summary of the status of our SARs as of December 31, 2003 and 2002 and changes during the years ending on those dates are presented below (shares in thousands):



|                                 |  |       |   |      |                                 |       |      |       |                                 |   |     
|-------------------------------- |  | ----- | - | ---- | ------------------------------- | ----- | ---- | ----- | ------------------------------- | - | ----
|                                 |  | 2003  |   | 2002
|                                 |  | SARs  |   |      | Weighted Average Exercise Price |       | SARs |       | Weighted Average Exercise Price
|Outstanding at beginning of year |  | 4,047 |   |      | $                               | 8.68  |      |      |                                 | $ |    
|Granted                          |  | 489   |   |      |                                 | 11.27 |      | 4,047 |                                 |   | 8.68
|Exercised                        |  | (404  | ) |      |                                 | 6.05  |      |      |                                 |   |    
|Forfeited                        |  | (199  | ) |      |                                 | 9.13  |      |       |                                 |   |     
|                                 |  |       |   |      |                                 |       |      |       |                                 |   |     
|Outstanding at end of year       |  | 3,933 |   |      | $                               | 9.25  |      | 4,047 |                                 | $ | 8.68
|                                 |  |       |   |      |                                 |       |      |       |                                 |   |     
|SARs exercisable at year-end     |  | 1,992 |   |      | $                               | 8.76  |      | 1,491 |                                 | $ | 7.86
|                                 |  |       |   |      |                                 |       |      |       |                                 |   |     



The following table reflects the
SARs outstanding at December 31, 2003 (share amounts in thousands):



|                        |  |                                |  |                                             |  |                                 |       |                                |       |                                 |   |      
|----------------------- |  | ------------------------------ |  | ------------------------------------------- |  | ------------------------------- | ----- | ------------------------------ | ----- | ------------------------------- | - | -----
|Range of Exercise
Price |  | Number Outstanding at 12/31/03 |  | Weighted Average Remaining Contractual Life |  | Weighted Average Exercise Price |       | Number Exercisable at 12/31/03 |       | Weighted Average Exercise Price
|$      $  2.46         |  | 82                             |  | 1.1 years                                   |  | $                               | 2.46  |                                | 82    |                                 | $ | 2.46 
|4.17 -    6.21          |  | 226                            |  | 1.5 years                                   |  |                                 | 5.66  |                                | 226   |                                 |   | 5.66 
|6.71 -    8.33          |  | 62                             |  | 0.8 years                                   |  |                                 | 6.87  |                                | 36    |                                 |   | 7.58 
|9.08 -    9.08          |  | 1,000                          |  | 6.4 years                                   |  |                                 | 9.08  |                                | 500   |                                 |   | 9.08 
|9.10 -    9.36          |  | 860                            |  | 3.4 years                                   |  |                                 | 9.27  |                                | 286   |                                 |   | 9.27 
|9.37 -    9.97          |  | 1,122                          |  | 2.8 years                                   |  |                                 | 9.77  |                                | 777   |                                 |   | 9.82 
|9.98 -  13.64           |  | 581                            |  | 4.3 years                                   |  |                                 | 11.13 |                                | 85    |                                 |   | 10.42
|                        |  |                                |  |                                             |  |                                 |       |                                |       |                                 |   |      
|2.46 -  13.64           |  | 3,933                          |  | 3.9 years                                   |  |                                 | 9.25  |                                | 1,992 |                                 |   | 8.76 
|                        |  |                                |  |                                             |  |                                 |       |                                |       |                                 |   |      



F-20



---

##### Table of Contents

Our stock compensation plans also allow grants of restricted stock and restricted stock units. Restricted stock is
issued on the grant date but restricted as to transferability. Restricted stock unit awards represent the right to receive common stock when vesting occurs.



At the time of the spin-off we granted awards of 165,000 restricted shares of common stock that vest in three equal annual installments beginning on the first
anniversary of the date of grant. During 2003 we granted awards of 420,000 restricted stock units with vesting terms up to three years. We will recognize total compensation expense of $6.1 million ratably over the life of these grants. During 2003
we recognized compensation expense of $2.9 million related to these grants. At December 31, 2003 and 2002 there were 0.5 million and 0.2 million, respectively, outstanding restricted stock shares and units.



As a result of the separation of employment of an executive of the Company in March
2004, in accordance with the terms of the employment agreement between the Company and the executive, the former executive received a cash payment and his SARs and restricted shares of the Companys common stock vested. In the first quarter of
2004, the Company will recognize a pre-tax $2.9 million charge to earnings in connection with the former executives termination of employment.



We also have a 401(k) defined contribution plan whereby we match 100% of an employees contribution (subject to certain limitations in the plan). Matching
contributions are made 100% in cash. The initial contribution under the plan, $0.1 million, was made for the pay period ended December 31, 2002. In 2003 we made contributions totaling $2.0 million to the 401(k) plan.



Note 7Income Taxes



Until the date of the spin-off, our taxable income or loss was included in the consolidated income tax returns filed by Plains
Resources. Income tax obligations reflected in these financial statements with respect to such returns are based on the tax sharing agreement that provides that income taxes are calculated assuming we filed a separate combined income tax return.



Our deferred income tax assets and liabilities at December 31, 2003 and
2002 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, |         
|                                                             |  | 2003         |          |   | 2002 |  
|U.S. Federal                                                 |  |              |          |   |      |   |         |  
|Deferred tax assets:                                         |  |              |          |   |      |   |         |  
|Net operating losses                                         |  | $            | 2,952    |   |      | $ | 846     |  
|Tax credits                                                  |  |              | 6,038    |   |      |   | 106     |  
|Commodity hedging contracts and other                        |  |              | 21,879   |   |      |   | 8,572   |  
|                                                             |  |              |          |   |      |   |         |  
|                                                             |  |              | 30,869   |   |      |   | 9,524   |  
|                                                             |  |              |          |   |      |   |         |  
|Deferred tax liabilities:                                    |  |              |          |   |      |   |         |  
|Net oil & gas acquisition, exploration and development costs |  |              | (124,269 | ) |      |   | (48,715 | )
|Commodity hedging contracts and other                        |  |              |         |   |      |   |        |  
|                                                             |  |              |          |   |      |   |         |  
|                                                             |  |              | (124,269 | ) |      |   | (48,715 | )
|                                                             |  |              |          |   |      |   |         |  
|Net U.S. Federal deferred tax asset (liability)              |  |              | (93,400  | ) |      |   | (39,191 | )
|                                                             |  |             
|States                                                       |  |              |          |   |      |   |         |  
|Deferred tax liability                                       |  |              | (28,035  | ) |      |   | (12,225 | )
|                                                             |  |              |          |   |      |   |         |  
|Net deferred tax assets (liability)                          |  | $            | (121,435 | ) |      | $ | (51,416 | )
|                                                             |  |              |          |   |      |   |         |  



F-21



---

##### Table of Contents

At December 31, 2003, for federal income tax purposes, we had carryforwards of approximately $8.4 million of
regular tax net operating losses, $4.8 million of alternative minimum tax credits and $1.2 million of enhanced oil recovery credits. The NOL carryforwards expire in 2019.



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



|                                                                                            |  |                         |        |   |      |   |        |      |  |   |        |  
|------------------------------------------------------------------------------------------- |  | ----------------------- | ------ | - | ---- | - | ------ | ---- |  | - | ------ | -
|                                                                                            |  | Year Ended December 31, |       
|                                                                                            |  | 2003                    |        |   | 2002 |   |        | 2001 | 
|U.S. federal income tax provision at statutory rate                                         |  | $                       | 35,253 |   |      | $ | 15,039 |      |  | $ | 31,101 |  
|State income taxes, net of federal benefit                                                  |  |                         | 5,512  |   |      |   | 2,409  |      |  |   | 4,758  |  
|Other                                                                                       |  |                         | 547    |   |      |   | (716   | )    |  |   | (1,471 | )
|                                                                                            |  |                         |        |   |      |   |        |      |  |   |        |  
|Income tax expense on income before income taxes and cumulative effect of accounting change |  |                         | 41,312 |   |      |   | 16,732 |      |  |   | 34,388 |  
|Income tax benefit allocated to cumulative effect of accounting change                      |  |                         | (7,860 | ) |      |   |       |      |  |   | (1,042 | )
|                                                                                            |  |                         |        |   |      |   |        |      |  |   |        |  
|Income tax provision                                                                        |  | $                       | 33,452 |   |      | $ | 16,732 |      |  | $ | 33,346 |  
|                                                                                            |  |                         |        |   |      |   |        |      |  |   |        |  



Under the terms of a tax
allocation agreement, we have agreed to indemnify Plains Resources if the spin-off is not tax-free to Plains Resources as a result of various actions taken by us or with respect to our failure to take various actions. In addition, we agreed 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 the events that could trigger this indemnification obligation.



Note 8Property Divestments



We periodically evaluate and from time to time elect to sell certain of our producing properties that we consider to be nonstrategic
or fully valued. In 2003, we sold our interest in 36 predominantly non-operated and noncore fields in the Permian Basin, the Texas Panhandle, east Texas, the Mid-continent Area, Alabama, Arkansas, Mississippi, North Dakota and New Mexico for
aggregate proceeds of approximately $23.2 million. No gains or losses were reflected in net income with respect to these sales.



Note 9Commitments, Contingencies and Industry Concentration



Commitments and Contingencies



Operating leases.    We lease certain real property, equipment and operating facilities under various operating leases. Future
noncancellable commitments related to these leases are as follows (in thousands):



|           |  |   |       
|---------- |  | - | ------
|2004       |  | $ | 3,608 
|2005       |  |   | 3,015 
|2006       |  |   | 2,399 
|2007       |  |   | 2,258 
|2008       |  |   | 2,244 
|Thereafter |  |   | 10,243



F-22



---

##### Table of Contents

Total expenses related to operating leases obligations were $2.2 million in 2003 and less than $0.1 million in each
of 2002 and 2001.



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.
Typically when producing oil and gas assets are purchased, one assumes the obligation to plug and abandon wells that are part of such assets. However, in some instances, we have received an indemnity in connection with such purchase. There can be no
assurance that we will be able to collect on these indemnities. Often these regulations are more burdensome on older properties that were operated before the regulations came into effect such as some of our properties in California that have
operated for over 90 years. We have established policies for continuing compliance with environmental laws and regulations. We also maintain insurance coverage for environmental matters, which we believe is customary in the industry, but we are not
fully insured against all environmental risks. 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.



Plugging, Abandonment and Remediation
Obligations.    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. Typically, when producing oil and gas assets are purchased the purchaser assumes the obligation to plug and abandon wells that are part of such assets. However,
in some instances, we receive an indemnity with respect to those costs.



In connection with the purchase of certain of our onshore California properties, each year we are required to plug and abandon 20% of the then remaining inactive wells (there were 158 inactive wells at December 31, 2003). If we do not meet
this commitment, and the requirement is not waived, we must escrow funds to cover the cost of the wells that were not abandoned. To date we have not been required to escrow any funds. In addition, until the end of 2006, we are required to spend at
least $600,000 per year (and $300,000 per year from 2007 through 2011) to remediate oil contaminated soil from existing well sites that require remediation.



Other commitments and contingencies.    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 oil and gas properties and the marketing, transportation, terminalling and storage of 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 are a defendant in various lawsuits arising in the ordinary course of our business. While the outcome of these lawsuits cannot be predicted with certainty and
could have a material adverse effect on our financial position, 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.



In September 2002, Stocker Resources Inc., or Stocker, our
general partner before we converted from a limited partnership to a corporation, filed a declaratory judgment action against Commonwealth Energy Corporation, or Commonwealth, in the Superior Court of Orange County, California relating to the
termination of an electric service contract. Stocker was seeking a declaratory judgment that it was entitled to terminate the contract and that Commonwealth had no basis for proceeding against Stockers related $1.5 million performance bond.
Also in September 2002, Stocker was named a defendant in an action brought by Commonwealth in the Superior Court of Orange County, California for breach of the electric service contract. In January 2004 Plains Resources signed a settlement agreement
with Commonwealth. Under the terms of our master separation agreement with Plains



F-23



---

##### Table of Contents

Resources, we indemnified them for damages they might incur as a result of this action. As such, we reimbursed Plains Resources settlement amount.



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, oil spills, 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 all risks, either because insurance is not available or because of high premium costs. We maintain coverage for earthquake damages in California but this coverage may not
provide for the full effect of damages that could occur and we may be subject to additional liabilities. 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.



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. Plains All American Pipeline, L.P. (PAA), in which Plains Resources held an approximate 22% interest at December 31, 2003, is the exclusive marketer/purchaser for
all of our equity oil production in California and Illinois. 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 in California and Illinois 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. During 2003, 2002 and 2001 no other purchaser accounted for more than 10% of our total revenues.



The contract counterparties for our derivative commodity contracts are all major financial institutions with Standard & Poors ratings of A or better. Six
of the financial institutions are participating lenders in our credit facility, holding contracts that represent approximately 62% of the fair value of all of our open positions at December 31, 2003.



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 and trucks 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.



Note 10Financial instruments



The following 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 (SFAS 107). The estimated fair value amounts have been determined using available market
information and valuation methodologies described below. Considerable judgment is required in interpreting market data to develop the estimates of fair value. The use of



F-24



---

##### Table of Contents

different market assumptions or valuation methodologies may have a material effect on the 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 in other assets are stated at fair value. The carrying amounts and fair values of our other financial instruments are as follows
(in thousands):



|                         |  |                   |         |            |   |        
|------------------------ |  | ----------------- | ------- | ---------- | - | -------
|                         |  | December 31, 2003
|                         |  | Carrying Amount   |         | Fair Value
|Long-Term Debt           |  |                   |         |            |   |        
|Bank debt                |  | $                 | 211,000 |            | $ | 211,000
|Senior subordinated debt |  |                   | 276,906 |            |   | 294,828
|Other long-term debt     |  |                   | 511     |            |   | 511    



The carrying value of bank debt
approximates its fair value, as interest rates are variable, based on prevailing market rates. The fair value of subordinated debt is based on quoted market prices based on trades of subordinated debt.



Note 11Supplemental Cash Flow Information



Cash payments for interest and taxes were (in thousands of dollars):



|                           |  |                         |        |      |   |       |  |   |  
|-------------------------- |  | ----------------------- | ------ | ---- | - | ----- |  | - | -
|                           |  | Year Ended December 31,
|                           |  | 2003                    |        | 2002 |   | 2001 
|Cash payments for interest |  | $                       | 32,364 |      | $ | 280   |  | $ | 
|                           |  |                         |        |      |   |       |  |   |  
|Cash payments for taxes    |  | $                       | 6,489  |      | $ | 2,180 |  | $ | 
|                           |  |                         |        |      |   |       |  |   |  



Cash payments for interest are
net of capitalized interest of $3,232 and $1,006 in 2003 and 2002, respectively.



The merger involved non-cash consideration as follows (in thousands of dollars);



|                                    |  |   |        
|----------------------------------- |  | - | -------
|Fair value of common stock issued   |  | $ | 152,186
|Current liabilities assumed         |  |   | 73,779 
|Other long-term liabilities assumed |  |   | 4,394  
|Deferred income tax liability       |  |   | 40,281 
|                                    |  |   |        
|                                    |  | $ | 270,640
|                                    |  |   |        



Note 12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,
|                                       |  | 2003                    |         | 2002 |   |        | 2001
|Property acquisitions costs            |  |                         |         |      |   |        |      |  |   |        
|Unproved properties                    |  |                         |         |      |   |        |      |  |   |        
|3TEC Acquisition                       |  | $                       | 61,116  |      | $ |       |      |  | $ |       
|Other                                  |  |                         | 19,025  |      |   | 65     |      |  |   | 44     
|Proved properties (1)                  |  |                         |         |      |   |        |      |  |   |        
|3TEC Acquisition                       |  |                         |         |      |   |        |      |  |   |        
|Asset retirement cost                  |  |                         | 4,577   |      |   |       |      |  |   |       
|Other                                  |  |                         | 289,779 |      |   |       |      |  |   |       
|Other                                  |  |                         | 1,197   |      |   | (4,516 | )    |  |   | 1,645  
|Exploration costs                      |  |                         | 8,947   |      |   | 602    |      |  |   | 286    
|Exploitation and development costs (2) |  |                         | 101,334 |      |   | 68,346 |      |  |   | 123,778
|                                       |  |                         |         |      |   |        |      |  |   |        
|                                       |  | $                       | 485,975 |      | $ | 64,497 |      |  | $ | 125,753
|                                       |  |                         |         |      |   |        |      |  |   |        



F-25



---

##### Table of Contents

---

|(1) |  | In connection with the acquisition of an additional interest in the Point Arguello field, offshore California, in 2002 we assumed certain obligations of the seller. As consideration for
receiving the transferred properties and assuming such obligations, we received $2.4 million. In addition, we received $2.7 million as our share of revenues less costs for the period April 1 to July 31, 2002, the period prior to ownership.
|--- |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|(2) |  | Amounts presented for 2003 do not include the cumulative effect adjustment for the January 1, 2003 adoption of SFAS 143 of $15.9 million.
|--- |  | -----------------------------------------------------------------------------------------------------------------------------------------



Amounts presented include capitalized general and administrative expense of $11.0
million, $6.0 million and $6.2 million in 2003, 2002 and 2001, respectively, and capitalized interest expense of $3.2 million, $2.4 million and $3.1 million in 2003, 2002 and 2001, respectively.



Capitalized costs



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



|                  |  |              |           |   |      |   |          |  
|----------------- |  | ------------ | --------- | - | ---- | - | -------- | -
|                  |  | December 31, |          
|                  |  | 2003         |           |   | 2002 |  
|Proved properties |  | $            | 1,074,302 |   |      | $ | 629,454  |  
|Accumulated DD&A  |  |              | (183,988  | ) |      |   | (167,278 | )
|                  |  |              |           |   |      |   |          |  
|                  |  | $            | 890,314   |   |      | $ | 462,176  |  
|                  |  |              |           |   |      |   |          |  



The average DD&A rate per
equivalent unit of production was $3.86, $3.17 and $2.70 in 2003, 2002 and 2001, 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,
|                     |  | 2003         |        | 2002 |   | 2001  
|Acquisition costs    |  | $            | 44,135 |      | $ | 24,612 |  | $ | 27,523
|Exploration costs    |  |              | 12,489 |      |   |       |  |   |      
|Capitalized interest |  |              | 7,034  |      |   | 5,433  |  |   | 5,848 
|                     |  |              |        |      |   |        |  |   |       
|                     |  | $            | 63,658 |      | $ | 30,045 |  | $ | 33,371
|                     |  |              |        |      |   |        |  |   |       



Unproved property costs not
subject to amortization consist of acquisition costs related to unproved areas, exploration costs and capitalized interest. Costs are transferred into the amortization base on an ongoing basis as the properties are evaluated and proved reserves
established or impairment determined. We will continue to evaluate these properties and costs will be transferred into the amortization base as the undeveloped areas are tested. Our onshore properties and one offshore property consist of mature but
underdeveloped crude oil properties that were acquired from major or large independent oil and gas companies. Certain of these fields were discovered from 1906 to 1981, have produced significant volumes since initial discovery, and exhibit complex
reservoir and geologic conditions. Due to the nature of the reserves, the ultimate evaluation of the properties will occur over a



F-26



---

##### Table of Contents

period of several years. We expect that 70% of the costs not subject to amortization at December 31, 2003 will be transferred to the amortization base over the next
three years and the remainder within the next seven years. The majority of the leases covering the properties are held by production and will not limit the time period for evaluation. Approximately 73%, 2% and 2% of the balance in unproved
properties at December 31, 2003, related to additions made in 2003, 2002 and 2001, respectively.



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 was determined by applying the statutory rates to pretax operating results (in thousands).



|                                                                                                  |  |                         |          |   |      |   |         |      |  |   |         |  
|------------------------------------------------------------------------------------------------- |  | ----------------------- | -------- | - | ---- | - | ------- | ---- |  | - | ------- | -
|                                                                                                  |  | Year Ended December 31, |         
|                                                                                                  |  | 2003                    |          |   | 2002 |   |         | 2001 | 
|Revenues from oil and gas producing activities                                                    |  | $                       | 304,090  |   |      | $ | 188,563 |      |  | $ | 204,139 |  
|Production costs and other                                                                        |  |                         | (104,819 | ) |      |   | (78,451 | )    |  |   | (63,795 | )
|Depreciation, depletion, amortization and accretion                                               |  |                         | (50,142  | ) |      |   | (29,632 | )    |  |   | (23,707 | )
|Income tax expense                                                                                |  |                         | (58,996  | ) |      |   | (31,307 | )    |  |   | (45,022 | )
|                                                                                                  |  |                         |          |   |      |   |         |      |  |   |         |  
|Results of operations from producing activities (excluding corporate overhead and interest costs) |  | $                       | 90,133   |   |      | $ | 49,173  |      |  | $ | 71,615  |  
|                                                                                                  |  |                         |          |   |      |   |         |      |  |   |         |  



Supplemental reserve
information (unaudited)



The following information summarizes
our net proved reserves of oil (including condensate and natural gas liquids) and gas and the present values thereof for the three years ended December 31, 2003. The following reserve information is based upon reports of the independent petroleum
consulting firms of Netherland, Sewell & Associates, Inc., and Ryder Scott Company. The estimates are in accordance with SEC regulations.



Management believes the reserve estimates presented herein, in accordance with generally accepted engineering and evaluation principles consistently applied, are
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 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
and of 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 Standardized Measure shown below 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 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.



F-27



---

##### Table of Contents

Decreases in the prices of 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. A significant portion of our reserve base (approximately 81% of year-end 2003 reserve volumes) is comprised of oil properties that are sensitive to crude oil price
volatility.



Estimated quantities of 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, 2003 (in thousands).



|                                                               |  |                                          |   |  |           |   |  |           |   |  |           |   |  |           |   |  |           |  
|-------------------------------------------------------------- |  | ---------------------------------------- | - |  | --------- | - |  | --------- | - |  | --------- | - |  | --------- | - |  | --------- | -
|                                                               |  | As of or for the Year Ended December 31, |  
|                                                               |  | 2003                                     |   |  | 2002      |   |  | 2001      |  
|                                                               |  | Oil(MBbl)                                |   |  | Gas(MMcf) |   |  | Oil(MBbl) |   |  | Gas(MMcf) |   |  | Oil(MBbl) |   |  | Gas(MMcf) |  
|Proved Reserves                                                |  |                                          |   |  |           |   |  |           |   |  |           |   |  |           |   |  |           |  
|Beginning balance                                              |  | 240,161                                  |   |  | 77,154    |   |  | 223,293   |   |  | 96,217    |   |  | 204,387   |   |  | 93,486    |  
|Revision of previous estimates                                 |  | (9,009                                   | ) |  | (12,844   | ) |  | 8,897     |   |  | (19,827   | ) |  | (13,093   | ) |  | (5,485    | )
|Extensions, discoveries, improved recovery and other additions |  | 2,749                                    |   |  | 31,529    |   |  | 15,049    |   |  | 6,661     |   |  | 40,218    |   |  | 11,571    |  
|Purchase of reserves in-place                                  |  | 5,421                                    |   |  | 249,301   |   |  | 2,635     |   |  |          |   |  |          |   |  |          |  
|Sale of reserves in-place                                      |  | (2,327                                   | ) |  | (7,768    | ) |  | (930      | ) |  | (2,535    | ) |  |          |   |  |          |  
|Production                                                     |  | (9,267                                   | ) |  | (18,195   | ) |  | (8,783    | ) |  | (3,362    | ) |  | (8,219    | ) |  | (3,355    | )
|                                                               |  |                                          |   |  |           |   |  |           |   |  |           |   |  |           |   |  |           |  
|Ending balance                                                 |  | 227,728                                  |   |  | 319,177   |   |  | 240,161   |   |  | 77,154    |   |  | 223,293   |   |  | 96,217    |  
|                                                               |  |                                          |   |  |           |   |  |           |   |  |           |   |  |           |   |  |           |  
|Proved Developed Reserves                                      |  |                                          |   |  |           |   |  |           |   |  |           |   |  |           |   |  |           |  
|Beginning balance                                              |  | 127,415                                  |   |  | 53,317    |   |  | 119,248   |   |  | 59,101    |   |  | 105,679   |   |  | 52,184    |  
|                                                               |  |                                          |   |  |           |   |  |           |   |  |           |   |  |           |   |  |           |  
|Ending balance                                                 |  | 124,822                                  |   |  | 235,070   |   |  | 127,415   |   |  | 53,317    |   |  | 119,248   |   |  | 59,101    |  
|                                                               |  |                                          |   |  |           |   |  |           |   |  |           |   |  |           |   |  |           |  



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, |           
|                                                         |  | 2003         |            |   | 2002 |   |            | 2001 | 
|Future cash inflows                                      |  | $            | 8,190,872  |   |      | $ | 6,819,645  |      |  | $ | 3,662,137  |  
|Future development costs                                 |  |              | (529,920   | ) |      |   | (431,841   | )    |  |   | (305,261   | )
|Future production expense                                |  |              | (3,041,607 | ) |      |   | (2,528,065 | )    |  |   | (1,714,132 | )
|Future income tax expense                                |  |              | (1,579,078 | ) |      |   | (1,446,528 | )    |  |   | (537,252   | )
|                                                         |  |              |            |   |      |   |            |      |  |   |            |  
|Future net cash flows                                    |  |              | 3,040,267  |   |      |   | 2,413,211  |      |  |   | 1,105,492  |  
|Discounted at 10% per year                               |  |              | (1,783,464 | ) |      |   | (1,529,704 | )    |  |   | (721,025   | )
|                                                         |  |              |            |   |      |   |            |      |  |   |            |  
|Standardized measure of discounted future net cash flows |  | $            | 1,256,803  |   |      | $ | 883,507    |      |  | $ | 384,467    |  
|                                                         |  |              |            |   |      |   |            |      |  |   |            |  



F-28



---

##### Table of Contents

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 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 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 prices for a significant portion of our oil and gas production. Arrangements in effect at December 31, 2003 are discussed in Note 3. Such arrangements are
not reflected in the reserve reports. The overall average year-end prices used in the reserve reports as of December 31, 2003, 2002 and 2001 were $28.22, $26.91, and $15.31 per barrel of oil, respectively, and $5.53, $4.63, and $2.56 per Mcf of gas,
respectively.



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 $2.0 billion, $1.5 billion, and $0.6 billion
at December 31, 2003, 2002 and 2001, 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, 2003, are as follows (in thousands):



|                                                                    |  |                         |           |   |      |   |          |      |  |   |          |  
|------------------------------------------------------------------- |  | ----------------------- | --------- | - | ---- | - | -------- | ---- |  | - | -------- | -
|                                                                    |  | Year Ended December 31, |          
|                                                                    |  | 2003                    |           |   | 2002 |   |          | 2001 | 
|Balance, beginning of year                                          |  | $                       | 883,507   |   |      | $ | 384,467  |      |  | $ | 789,438  |  
|Sales, net of production expenses                                   |  |                         | (235,948  | ) |      |   | (125,463 | )    |  |   | (139,545 | )
|Net change in sales and transfer prices, net of production expenses |  |                         | (1,657    | ) |      |   | 979,042  |      |  |   | (665,006 | )
|Changes in estimated future development costs                       |  |                         | (2,172    | ) |      |   | (62,801  | )    |  |   | (17,535  | )
|Extensions, discoveries and improved recovery, net of costs         |  |                         | 107,922   |   |      |   | 98,969   |      |  |   | 89,010   |  
|Previously estimated development costs incurred during the year     |  |                         | 46,957    |   |      |   | 39,692   |      |  |   | 86,881   |  
|Purchase of reserves in-place                                       |  |                         | 635,604   |   |      |   | 16,583   |      |  |   |         |  
|Sale of reserves in-place                                           |  |                         | (42,022   | ) |      |   | (2,959   | )    |  |   |         |  
|Revision of quantity estimates and timing of estimated production   |  |                         | (205,829  | ) |      |   | (133,618 | )    |  |   | (156,362 | )
|Accretion of discount                                               |  |                         | 151,403   |   |      |   | 62,376   |      |  |   | 141,598  |  
|Net change in income taxes                                          |  |                         | (80,962   | ) |      |   | (372,781 | )    |  |   | 255,988  |  
|                                                                    |  |                         |           |   |      |   |          |      |  |   |          |  
|Balance, end of year                                                |  | $                       | 1,256,803 |   |      | $ | 883,507  |      |  | $ | 384,467  |  
|                                                                    |  |                         |           |   |      |   |          |      |  |   |          |  



F-29



---

##### Table of Contents

Note 13Quarterly Financial Data (Unaudited)



The following table shows summary financial data for 2003 and 2002 (in thousands, except per share data):



|                                                     |  |               |        |                |   |               |  |                |        |      |   |        |  |   |        
|---------------------------------------------------- |  | ------------- | ------ | -------------- | - | ------------- |  | -------------- | ------ | ---- | - | ------ |  | - | -------
|                                                     |  | First Quarter |        | Second Quarter |   | Third Quarter |  | Fourth Quarter |        | Year
|2003                                                 |  |               |        |                |   |               |  |                |        |      |   |        |  |   |        
|Revenues                                             |  | $             | 51,738 |                | $ | 63,858        |  | $              | 95,382 |      | $ | 93,112 |  | $ | 304,090
|Operating profit                                     |  |               | 22,420 |                |   | 28,516        |  |                | 49,720 |      |   | 46,131 |  |   | 146,787
|Income before cumulative effect of accounting change |  |               | 8,603  |                |   | 8,900         |  |                | 17,544 |      |   | 12,040 |  |   | 47,087 
|Cumulative effect of accounting change               |  |               | 12,324 |                |   |              |  |                |       |      |   |       |  |   | 12,324 
|Net income                                           |  |               | 20,927 |                |   | 8,900         |  |                | 17,544 |      |   | 12,040 |  |   | 59,411 
|Earnings per sharebasic                             |  |               |        |                |   |               |  |                |        |      |   |        |  |   |        
|Income before cumulative effect of accounting change |  | $             | 0.36   |                | $ | 0.31          |  | $              | 0.44   |      | $ | 0.30   |  | $ | 1.41   
|Cumulative effect of accounting change               |  |               | 0.51   |                |   |              |  |                |       |      |   |       |  |   | 0.37   
|Net income                                           |  |               | 0.87   |                |   | 0.31          |  |                | 0.44   |      |   | 0.30   |  |   | 1.78   
|Earnings per sharediluted                           |  |               |        |                |   |               |  |                |        |      |   |        |  |   |        
|Income before cumulative effect of accounting change |  | $             | 0.35   |                | $ | 0.31          |  | $              | 0.43   |      | $ | 0.30   |  | $ | 1.41   
|Cumulative effect of accounting change               |  |               | 0.51   |                |   |              |  |                |       |      |   |       |  |   | 0.37   
|Net income                                           |  |               | 0.86   |                |   | 0.31          |  |                | 0.43   |      |   | 0.30   |  |   | 1.78   
|2002                                                 |  |               |        |                |   |               |  |                |        |      |   |        |  |   |        
|Revenues                                             |  | $             | 40,673 |                | $ | 45,140        |  | $              | 50,907 |      | $ | 51,843 |  | $ | 188,563
|Operating profit                                     |  |               | 16,753 |                |   | 20,471        |  |                | 21,408 |      |   | 21,121 |  |   | 79,753 
|Net income                                           |  |               | 5,864  |                |   | 8,218         |  |                | 7,418  |      |   | 4,737  |  |   | 26,237 
|Basic and diluted earnings per share                 |  | $             | 0.24   |                | $ | 0.34          |  | $              | 0.30   |      | $ | 0.20   |  | $ | 1.08   



Note 14Consolidating Financial
Statements



We and Plains E&P Company are the co-issuers of the
8.75% notes discussed in Note 4. The 8.75% notes are jointly and severally guaranteed on a full and unconditional basis by Arguello Inc., Plains Illinois Inc. and certain immaterial subsidiaries (referred to as Guarantor Subsidiaries).



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



| |  |  | PXP (the Issuer);
| | - |  | -------------------



| |  |  | the guarantor subsidiaries on a combined basis (Guarantor Subsidiaries);
| | - |  | --------------------------------------------------------------------------



| |  |  | elimination entries necessary to consolidate the Issuer and Guarantor Subsidiaries; and
| | - |  | ---------------------------------------------------------------------------------------



| |  |  | the company on a consolidated basis.
| | - |  | ------------------------------------



Plains E&P Company has no material assets or operations; accordingly, Plains E&P Company has been omitted from the Issuer financial information.



F-30



---

##### Table of Contents

PLAINS EXPLORATION & PRODUCTION COMPANY



CONDENSED CONSOLIDATING BALANCE SHEET

DECEMBER 31, 2003

(in thousands)



|                                                            |  |        |           |   |                        |   |          |                           |  |   |              |   |  |   |           |  
|----------------------------------------------------------- |  | ------ | --------- | - | ---------------------- | - | -------- | ------------------------- |  | - | ------------ | - |  | - | --------- | -
|                                                            |  | Issuer |           |   | Guarantor Subsidiaries |   |          | Intercompany Eliminations |  |   | Consolidated |  
|ASSETS                                                      |  |        |           |   |                        |   |          |                           |  |   |              |   |  |   |           |  
|Current Assets                                              |  |        |           |   |                        |   |          |                           |  |   |              |   |  |   |           |  
|Cash and cash equivalents                                   |  | $      | 403       |   |                        | $ | 974      |                           |  | $ |             |   |  | $ | 1,377     |  
|Accounts receivable and other current assets                |  |        | 32,018    |   |                        |   | 21,612   |                           |  |   |             |   |  |   | 53,630    |  
|Inventories                                                 |  |        | 3,800     |   |                        |   | 1,518    |                           |  |   |             |   |  |   | 5,318     |  
|                                                            |  |        |           |   |                        |   |          |                           |  |   |              |   |  |   |           |  
|                                                            |  |        | 36,221    |   |                        |   | 24,104   |                           |  |   |             |   |  |   | 60,325    |  
|                                                            |  |        |           |   |                        |   |          |                           |  |   |              |   |  |   |           |  
|Property and Equipment, at cost                             |  |        |           |   |                        |   |          |                           |  |   |              |   |  |   |           |  
|Oil and natural gas propertiesfull cost method             |  |        |           |   |                        |   |          |                           |  |   |              |   |  |   |           |  
|Subject to amortization                                     |  |        | 570,639   |   |                        |   | 503,663  |                           |  |   |             |   |  |   | 1,074,302 |  
|Not subject to amortization                                 |  |        | 21,370    |   |                        |   | 42,288   |                           |  |   |             |   |  |   | 63,658    |  
|Other property and equipment                                |  |        | 4,330     |   |                        |   | 609      |                           |  |   |             |   |  |   | 4,939     |  
|                                                            |  |        |           |   |                        |   |          |                           |  |   |              |   |  |   |           |  
|                                                            |  |        | 596,339   |   |                        |   | 546,560  |                           |  |   |             |   |  |   | 1,142,899 |  
|Less allowance for depreciation, depletion and amortization |  |        | (64,470   | ) |                        |   | (121,534 | )                         |  |   |             |   |  |   | (186,004  | )
|                                                            |  |        |           |   |                        |   |          |                           |  |   |              |   |  |   |           |  
|                                                            |  |        | 531,869   |   |                        |   | 425,026  |                           |  |   |             |   |  |   | 956,895   |  
|                                                            |  |        |           |   |                        |   |          |                           |  |   |              |   |  |   |           |  
|Investment in and Advances to Subsidiaries                  |  |        | 531,142   |   |                        |   |          |                           |  |   | (531,142     | ) |  |   |          |  
|                                                            |  |        |           |   |                        |   |          |                           |  |   |              |   |  |   |           |  
|Other Assets                                                |  |        | 20,292    |   |                        |   | 146,600  |                           |  |   |             |   |  |   | 166,892   |  
|                                                            |  |        |           |   |                        |   |          |                           |  |   |              |   |  |   |           |  
|                                                            |  | $      | 1,119,524 |   |                        | $ | 595,730  |                           |  | $ | (531,142     | ) |  | $ | 1,184,112 |  
|                                                            |  |        |           |   |                        |   |          |                           |  |   |              |   |  |   |           |  
|LIABILITIES AND STOCKHOLDERS EQUITY                        |  |        |           |   |                        |   |          |                           |  |   |              |   |  |   |           |  
|Current Liabilities                                         |  |        |           |   |                        |   |          |                           |  |   |              |   |  |   |           |  
|Accounts payable and other current liabilities              |  | $      | 76,540    |   |                        | $ | 22,912   |                           |  | $ |             |   |  | $ | 99,452    |  
|Commodity hedging contracts                                 |  |        | 29,782    |   |                        |   | 25,341   |                           |  |   |             |   |  |   | 55,123    |  
|Current maturities on long-term debt                        |  |        | 511       |   |                        |   |         |                           |  |   |             |   |  |   | 511       |  
|                                                            |  |        |           |   |                        |   |          |                           |  |   |              |   |  |   |           |  
|                                                            |  |        | 106,833   |   |                        |   | 48,253   |                           |  |   |             |   |  |   | 155,086   |  
|                                                            |  |        |           |   |                        |   |          |                           |  |   |              |   |  |   |           |  
|Long-Term Debt                                              |  |        | 487,906   |   |                        |   |         |                           |  |   |             |   |  |   | 487,906   |  
|                                                            |  |        |           |   |                        |   |          |                           |  |   |              |   |  |   |           |  
|Other Long-Term Liabilities                                 |  |        | 43,317    |   |                        |   | 22,112   |                           |  |   |             |   |  |   | 65,429    |  
|                                                            |  |        |           |   |                        |   |          |                           |  |   |              |   |  |   |           |  
|Payable to Parent                                           |  |        |          |   |                        |   | 511,783  |                           |  |   | (511,783     | ) |  |   |          |  
|                                                            |  |        |           |   |                        |   |          |                           |  |   |              |   |  |   |           |  
|Deferred Income Taxes                                       |  |        | 127,212   |   |                        |   | (5,777   | )                         |  |   |             |   |  |   | 121,435   |  
|                                                            |  |        |           |   |                        |   |          |                           |  |   |              |   |  |   |           |  
|Stockholders Equity                                        |  |        |           |   |                        |   |          |                           |  |   |              |   |  |   |           |  
|Stockholders equity                                        |  |        | 394,695   |   |                        |   | 30,292   |                           |  |   | (30,292      | ) |  |   | 394,695   |  
|Accumulated other comprehensive income                      |  |        | (40,439   | ) |                        |   | (10,933  | )                         |  |   | 10,933       |   |  |   | (40,439   | )
|                                                            |  |        |           |   |                        |   |          |                           |  |   |              |   |  |   |           |  
|                                                            |  |        | 354,256   |   |                        |   | 19,359   |                           |  |   | (19,359      | ) |  |   | 354,256   |  
|                                                            |  |        |           |   |                        |   |          |                           |  |   |              |   |  |   |           |  
|                                                            |  | $      | 1,119,524 |   |                        | $ | 595,730  |                           |  | $ | (531,142     | ) |  | $ | 1,184,112 |  
|                                                            |  |        |           |   |                        |   |          |                           |  |   |              |   |  |   |           |  



F-31



---

##### Table of Contents

PLAINS EXPLORATION & PRODUCTION COMPANY



CONDENSED CONSOLIDATING BALANCE SHEET

DECEMBER 31, 2002

(in thousands)



|                                                            |  |        |         |   |                        |   |         |                           |  |   |              |   |  |   |          |  
|----------------------------------------------------------- |  | ------ | ------- | - | ---------------------- | - | ------- | ------------------------- |  | - | ------------ | - |  | - | -------- | -
|                                                            |  | Issuer |         |   | Guarantor Subsidiaries |   |         | Intercompany Eliminations |  |   | Consolidated |  
|ASSETS                                                      |  |        |         |   |                        |   |         |                           |  |   |              |   |  |   |          |  
|Current Assets                                              |  |        |         |   |                        |   |         |                           |  |   |              |   |  |   |          |  
|Cash and cash equivalents                                   |  | $      | 1,004   |   |                        | $ | 24      |                           |  | $ |             |   |  | $ | 1,028    |  
|Accounts receivable and other current assets                |  |        | 21,273  |   |                        |   | 8,646   |                           |  |   |             |   |  |   | 29,919   |  
|Commodity hedging contracts                                 |  |        | 2,594   |   |                        |   |        |                           |  |   |             |   |  |   | 2,594    |  
|Inventories                                                 |  |        | 4,009   |   |                        |   | 1,189   |                           |  |   |             |   |  |   | 5,198    |  
|                                                            |  |        |         |   |                        |   |         |                           |  |   |              |   |  |   |          |  
|                                                            |  |        | 28,880  |   |                        |   | 9,859   |                           |  |   |             |   |  |   | 38,739   |  
|                                                            |  |        |         |   |                        |   |         |                           |  |   |              |   |  |   |          |  
|Property and Equipment, at cost                             |  |        |         |   |                        |   |         |                           |  |   |              |   |  |   |          |  
|Oil and natural gas propertiesfull cost method             |  |        |         |   |                        |   |         |                           |  |   |              |   |  |   |          |  
|Subject to amortization                                     |  |        | 507,501 |   |                        |   | 121,953 |                           |  |   |             |   |  |   | 629,454  |  
|Not subject to amortization                                 |  |        | 17,621  |   |                        |   | 12,424  |                           |  |   |             |   |  |   | 30,045   |  
|Other property and equipment                                |  |        | 2,008   |   |                        |   | 199     |                           |  |   |             |   |  |   | 2,207    |  
|                                                            |  |        |         |   |                        |   |         |                           |  |   |              |   |  |   |          |  
|                                                            |  |        | 527,130 |   |                        |   | 134,576 |                           |  |   |             |   |  |   | 661,706  |  
|Less allowance for depreciation, depletion and amortization |  |        | (75,007 | ) |                        |   | (93,487 | )                         |  |   |             |   |  |   | (168,494 | )
|                                                            |  |        |         |   |                        |   |         |                           |  |   |              |   |  |   |          |  
|                                                            |  |        | 452,123 |   |                        |   | 41,089  |                           |  |   |             |   |  |   | 493,212  |  
|                                                            |  |        |         |   |                        |   |         |                           |  |   |              |   |  |   |          |  
|Investment in and Advances to Subsidiaries                  |  |        | 33,243  |   |                        |   |         |                           |  |   | (33,243      | ) |  |   |         |  
|                                                            |  |        |         |   |                        |   |         |                           |  |   |              |   |  |   |          |  
|Other Assets                                                |  |        | 19,221  |   |                        |   | (292    | )                         |  |   |             |   |  |   | 18,929   |  
|                                                            |  |        |         |   |                        |   |         |                           |  |   |              |   |  |   |          |  
|                                                            |  | $      | 533,467 |   |                        | $ | 50,656  |                           |  | $ | (33,243      | ) |  | $ | 550,880  |  
|                                                            |  |        |         |   |                        |   |         |                           |  |   |              |   |  |   |          |  
|LIABILITIES AND STOCKHOLDERS EQUITY                        |  |        |         |   |                        |   |         |                           |  |   |              |   |  |   |          |  
|Current Liabilities                                         |  |        |         |   |                        |   |         |                           |  |   |              |   |  |   |          |  
|Accounts payable and other current liabilities              |  | $      | 50,996  |   |                        | $ | 10,096  |                           |  | $ |             |   |  | $ | 61,092   |  
|Commodity hedging contracts                                 |  |        | 15,188  |   |                        |   | 9,384   |                           |  |   |             |   |  |   | 24,572   |  
|Current maturities on long-term debt                        |  |        | 511     |   |                        |   |        |                           |  |   |             |   |  |   | 511      |  
|                                                            |  |        |         |   |                        |   |         |                           |  |   |              |   |  |   |          |  
|                                                            |  |        | 66,695  |   |                        |   | 19,480  |                           |  |   |             |   |  |   | 86,175   |  
|                                                            |  |        |         |   |                        |   |         |                           |  |   |              |   |  |   |          |  
|Long-Term Debt                                              |  |        | 233,166 |   |                        |   |        |                           |  |   |             |   |  |   | 233,166  |  
|                                                            |  |        |         |   |                        |   |         |                           |  |   |              |   |  |   |          |  
|Other Long-Term Liabilities                                 |  |        | 4,101   |   |                        |   | 2,202   |                           |  |   |             |   |  |   | 6,303    |  
|                                                            |  |        |         |   |                        |   |         |                           |  |   |              |   |  |   |          |  
|Payable to Parent                                           |  |        |        |   |                        |   | 58,948  |                           |  |   | (58,948      | ) |  |   |         |  
|                                                            |  |        |         |   |                        |   |         |                           |  |   |              |   |  |   |          |  
|Deferred Income Taxes                                       |  |        | 55,685  |   |                        |   | (4,269  | )                         |  |   |             |   |  |   | 51,416   |  
|                                                            |  |        |         |   |                        |   |         |                           |  |   |              |   |  |   |          |  
|Stockholders Equity                                        |  |        |         |   |                        |   |         |                           |  |   |              |   |  |   |          |  
|Stockholders equity                                        |  |        | 186,678 |   |                        |   | (20,009 | )                         |  |   | 20,009       |   |  |   | 186,678  |  
|Accumulated other comprehensive income                      |  |        | (12,858 | ) |                        |   | (5,696  | )                         |  |   | 5,696        |   |  |   | (12,858  | )
|                                                            |  |        |         |   |                        |   |         |                           |  |   |              |   |  |   |          |  
|                                                            |  |        | 173,820 |   |                        |   | (25,705 | )                         |  |   | 25,705       |   |  |   | 173,820  |  
|                                                            |  |        |         |   |                        |   |         |                           |  |   |              |   |  |   |          |  
|                                                            |  | $      | 533,467 |   |                        | $ | 50,656  |                           |  | $ | (33,243      | ) |  | $ | 550,880  |  
|                                                            |  |        |         |   |                        |   |         |                           |  |   |              |   |  |   |          |  



F-32



---

##### Table of Contents

PLAINS EXPLORATION & PRODUCTION COMPANY



CONDENSED CONSOLIDATING STATEMENT OF INCOME

YEAR ENDED DECEMBER 31, 2003

(in thousands)



|                                                                      |  |        |         |   |                        |   |         |                           |  |   |              |   |  |   |         |  
|--------------------------------------------------------------------- |  | ------ | ------- | - | ---------------------- | - | ------- | ------------------------- |  | - | ------------ | - |  | - | ------- | -
|                                                                      |  | Parent |         |   | Guarantor Subsidiaries |   |         | Intercompany Eliminations |  |   | Consolidated |  
|Revenues                                                              |  |        |         |   |                        |   |         |                           |  |   |              |   |  |   |         |  
|Oil and liquids                                                       |  | $      | 129,359 |   |                        | $ | 68,789  |                           |  | $ |             |   |  | $ | 198,148 |  
|Natural gas                                                           |  |        | 15,798  |   |                        |   | 89,256  |                           |  |   |             |   |  |   | 105,054 |  
|Other operating revenues                                              |  |        |        |   |                        |   | 888     |                           |  |   |             |   |  |   | 888     |  
|                                                                      |  |        |         |   |                        |   |         |                           |  |   |              |   |  |   |         |  
|                                                                      |  |        | 145,157 |   |                        |   | 158,933 |                           |  |   |             |   |  |   | 304,090 |  
|                                                                      |  |        |         |   |                        |   |         |                           |  |   |              |   |  |   |         |  
|Costs and Expenses                                                    |  |        |         |   |                        |   |         |                           |  |   |              |   |  |   |         |  
|Production expenses                                                   |  |        | 52,677  |   |                        |   | 52,142  |                           |  |   |             |   |  |   | 104,819 |  
|General and administrative                                            |  |        | 38,628  |   |                        |   | 4,530   |                           |  |   |             |   |  |   | 43,158  |  
|Depreciation, depletion and amortization and accretion                |  |        | 19,960  |   |                        |   | 32,524  |                           |  |   |             |   |  |   | 52,484  |  
|                                                                      |  |        |         |   |                        |   |         |                           |  |   |              |   |  |   |         |  
|                                                                      |  |        | 111,265 |   |                        |   | 89,196  |                           |  |   |             |   |  |   | 200,461 |  
|                                                                      |  |        |         |   |                        |   |         |                           |  |   |              |   |  |   |         |  
|Income from Operations                                                |  |        | 33,892  |   |                        |   | 69,737  |                           |  |   |             |   |  |   | 103,629 |  
|Other Income (Expense)                                                |  |        |         |   |                        |   |         |                           |  |   |              |   |  |   |         |  
|Equity in earnings of subsidiaries                                    |  |        | 51,886  |   |                        |   |        |                           |  |   | (51,886      | ) |  |   |        |  
|Interest expense                                                      |  |        | (20,618 | ) |                        |   | (3,160  | )                         |  |   |             |   |  |   | (23,778 | )
|Interest and other income (expense)                                   |  |        | (168    | ) |                        |   | 856     |                           |  |   |             |   |  |   | 688     |  
|                                                                      |  |        |         |   |                        |   |         |                           |  |   |              |   |  |   |         |  
|Income Before Income Taxes and Cumulative Effect of Accounting Change |  |        | 64,992  |   |                        |   | 67,433  |                           |  |   | (51,886      | ) |  |   | 80,539  |  
|Income tax expense                                                    |  |        |         |   |                        |   |         |                           |  |   |              |   |  |   |         |  
|Current                                                               |  |        | 9,111   |   |                        |   | (10,335 | )                         |  |   |             |   |  |   | (1,224  | )
|Deferred                                                              |  |        | (27,016 | ) |                        |   | (5,212  | )                         |  |   |             |   |  |   | (32,228 | )
|                                                                      |  |        |         |   |                        |   |         |                           |  |   |              |   |  |   |         |  
|Income Before Cumulative Effect of Accounting Change                  |  |        | 47,087  |   |                        |   | 51,886  |                           |  |   | (51,886      | ) |  |   | 47,087  |  
|Cumulative effect of accounting change, net of tax                    |  |        | 12,324  |   |                        |   | 645     |                           |  |   | (645         | ) |  |   | 12,324  |  
|                                                                      |  |        |         |   |                        |   |         |                           |  |   |              |   |  |   |         |  
|Net Income                                                            |  | $      | 59,411  |   |                        | $ | 52,531  |                           |  | $ | (52,531      | ) |  | $ | 59,411  |  
|                                                                      |  |        |         |   |                        |   |         |                           |  |   |              |   |  |   |         |  



F-33



---

##### Table of Contents

PLAINS EXPLORATION & PRODUCTION COMPANY



CONDENSED CONSOLIDATING STATEMENT OF INCOME

YEAR ENDED DECEMBER 31, 2002

(in thousands)



|                                                                      |  |        |         |   |                        |   |        |                           |  |   |              |   |  |   |         |  
|--------------------------------------------------------------------- |  | ------ | ------- | - | ---------------------- | - | ------ | ------------------------- |  | - | ------------ | - |  | - | ------- | -
|                                                                      |  | Parent |         |   | Guarantor Subsidiaries |   |        | Intercompany Eliminations |  |   | Consolidated |  
|Revenues                                                              |  |        |         |   |                        |   |        |                           |  |   |              |   |  |   |         |  
|Oil and liquids                                                       |  | $      | 123,795 |   |                        | $ | 54,243 |                           |  | $ |             |   |  | $ | 178,038 |  
|Natural gas                                                           |  |        | 10,299  |   |                        |   |       |                           |  |   |             |   |  |   | 10,299  |  
|Other operating revenues                                              |  |        |        |   |                        |   | 226    |                           |  |   |             |   |  |   | 226     |  
|                                                                      |  |        |         |   |                        |   |        |                           |  |   |              |   |  |   |         |  
|                                                                      |  |        | 134,094 |   |                        |   | 54,469 |                           |  |   |             |   |  |   | 188,563 |  
|                                                                      |  |        |         |   |                        |   |        |                           |  |   |              |   |  |   |         |  
|Costs and Expenses                                                    |  |        |         |   |                        |   |        |                           |  |   |              |   |  |   |         |  
|Production expenses                                                   |  |        | 50,510  |   |                        |   | 27,941 |                           |  |   |             |   |  |   | 78,451  |  
|General and administrative                                            |  |        | 13,479  |   |                        |   | 1,707  |                           |  |   |             |   |  |   | 15,186  |  
|Depreciation, depletion and amortization                              |  |        | 21,532  |   |                        |   | 8,827  |                           |  |   |             |   |  |   | 30,359  |  
|                                                                      |  |        |         |   |                        |   |        |                           |  |   |              |   |  |   |         |  
|                                                                      |  |        | 85,521  |   |                        |   | 38,475 |                           |  |   |             |   |  |   | 123,996 |  
|                                                                      |  |        |         |   |                        |   |        |                           |  |   |              |   |  |   |         |  
|Income from Operations                                                |  |        | 48,573  |   |                        |   | 15,994 |                           |  |   |             |   |  |   | 64,567  |  
|Other Income (Expense)                                                |  |        |         |   |                        |   |        |                           |  |   |              |   |  |   |         |  
|Equity in earnings of subsidiaries                                    |  |        | 5,988   |   |                        |   |       |                           |  |   | (5,988       | ) |  |   |        |  
|Expenses of terminated public equity offering                         |  |        | (2,395  | ) |                        |   |       |                           |  |   |              |   |  |   | (2,395  | )
|Interest expense                                                      |  |        | (12,942 | ) |                        |   | (6,435 | )                         |  |   |             |   |  |   | (19,377 | )
|Interest and other income (expense)                                   |  |        | (140    | ) |                        |   | 314    |                           |  |   |             |   |  |   | 174     |  
|                                                                      |  |        |         |   |                        |   |        |                           |  |   |              |   |  |   |         |  
|Income Before Income Taxes and Cumulative Effect of Accounting Change |  |        | 39,084  |   |                        |   | 9,873  |                           |  |   | (5,988       | ) |  |   | 42,969  |  
|Income tax expense                                                    |  |        |         |   |                        |   |        |                           |  |   |              |   |  |   |         |  
|Current                                                               |  |        | (1,232  | ) |                        |   | (5,121 | )                         |  |   |             |   |  |   | (6,353  | )
|Deferred                                                              |  |        | (11,615 | ) |                        |   | 1,236  |                           |  |   |             |   |  |   | (10,379 | )
|                                                                      |  |        |         |   |                        |   |        |                           |  |   |              |   |  |   |         |  
|Net Income                                                            |  | $      | 26,237  |   |                        | $ | 5,988  |                           |  | $ | (5,988       | ) |  | $ | 26,237  |  
|                                                                      |  |        |         |   |                        |   |        |                           |  |   |              |   |  |   |         |  



F-34



---

##### Table of Contents

PLAINS EXPLORATION & PRODUCTION COMPANY



CONDENSED CONSOLIDATING STATEMENT OF INCOME

YEAR ENDED DECEMBER 31, 2001

(in thousands)



|                                                                      |  |        |         |   |                        |   |        |                           |  |   |              |   |  |   |         |  
|--------------------------------------------------------------------- |  | ------ | ------- | - | ---------------------- | - | ------ | ------------------------- |  | - | ------------ | - |  | - | ------- | -
|                                                                      |  | Parent |         |   | Guarantor Subsidiaries |   |        | Intercompany Eliminations |  |   | Consolidated |  
|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                                    |  |        | 11,288  |   |                        |   |       |                           |  |   | (11,288      | ) |  |   |        |  
|Interest expense                                                      |  |        | (10,679 | ) |                        |   | (6,732 | )                         |  |   |             |   |  |   | (17,411 | )
|Interest and other income (expense)                                   |  |        | 94      |   |                        |   | 369    |                           |  |   |             |   |  |   | 463     |  
|                                                                      |  |        |         |   |                        |   |        |                           |  |   |              |   |  |   |         |  
|Income Before Income Taxes and Cumulative Effect of Accounting Change |  |        | 85,145  |   |                        |   | 15,224 |                           |  |   | (11,288      | ) |  |   | 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                  |  |        | 54,693  |   |                        |   | 11,288 |                           |  |   | (11,288      | ) |  |   | 54,693  |  
|Cumulative effect of accounting change, net of tax benefit            |  |        | (1,522  | ) |                        |   | 240    |                           |  |   | (240         | ) |  |   | (1,522  | )
|                                                                      |  |        |         |   |                        |   |        |                           |  |   |              |   |  |   |         |  
|Net Income                                                            |  | $      | 53,171  |   |                        | $ | 11,528 |                           |  | $ | (11,528      | ) |  | $ | 53,171  |  
|                                                                      |  |        |         |   |                        |   |        |                           |  |   |              |   |  |   |         |  



F-35



---

##### Table of Contents

PLAINS EXPLORATION & PRODUCTION COMPANY



CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

YEAR ENDED DECEMBER 31, 2003

(in thousands)



|                                                            |  |        |          |   |                       |   |          |                          |  |   |              |   |  |   |          |  
|----------------------------------------------------------- |  | ------ | -------- | - | --------------------- | - | -------- | ------------------------ |  | - | ------------ | - |  | - | -------- | -
|                                                            |  | Parent |          |   | GuarantorSubsidiaries |   |          | IntercompanyEliminations |  |   | Consolidated |  
|CASH FLOWS FROM OPERATING ACTIVITIES                        |  |        |          |   |                       |   |          |                          |  |   |              |   |  |   |          |  
|Net income                                                  |  | $      | 59,411   |   |                       | $ | 52,531   |                          |  | $ | (52,531      | ) |  | $ | 59,411   |  
|Items not affecting cash flows from operating activities:   |  |        |          |   |                       |   |          |                          |  |   |              |   |  |   |          |  
|Depreciation, depletion, amortization and accretion         |  |        | 19,960   |   |                       |   | 32,524   |                          |  |   |             |   |  |   | 52,484   |  
|Equity in earnings of subsidiaries                          |  |        | (51,886  | ) |                       |   |         |                          |  |   | 51,886       |   |  |   |         |  
|Deferred income taxes                                       |  |        | 27,016   |   |                       |   | 5,212    |                          |  |   |             |   |  |   | 32,228   |  
|Gain on derivatives                                         |  |        |         |   |                       |   | (847     | )                        |  |   |             |   |  |   | (847     | )
|Cumulative effect of adoption of accounting change          |  |        | (12,324  | ) |                       |   | (645     | )                        |  |   | 645          |   |  |   | (12,324  | )
|Non-cash compensation                                       |  |        | 20,897   |   |                       |   |         |                          |  |   |             |   |  |   | 20,897   |  
|Other noncash items                                         |  |        | 123      |   |                       |   |         |                          |  |   |             |   |  |   | 123      |  
|Change in assets and liabilities from operating activities: |  |        |          |   |                       |   |          |                          |  |   |              |   |  |   |          |  
|Accounts receivable and other assets                        |  |        | (10,745  | ) |                       |   | 7,197    |                          |  |   |             |   |  |   | (3,548   | )
|Inventories                                                 |  |        | 236      |   |                       |   | (145     | )                        |  |   |             |   |  |   | 91       |  
|Accounts payable to Plains Resources Inc.                   |  |        | (1,435   | ) |                       |   |         |                          |  |   |             |   |  |   | (1,435   | )
|Accounts payable and other liabilities                      |  |        | 9,111    |   |                       |   | (37,913  | )                        |  |   |             |   |  |   | (28,802  | )
|                                                            |  |        |          |   |                       |   |          |                          |  |   |              |   |  |   |          |  
|Net cash provided by operating activities                   |  |        | 60,364   |   |                       |   | 57,914   |                          |  |   |             |   |  |   | 118,278  |  
|                                                            |  |        |          |   |                       |   |          |                          |  |   |              |   |  |   |          |  
|                                                            |  |        |          |  
|CASH FLOWS FROM INVESTING ACTIVITIES                        |  |        |          |   |                       |   |          |                          |  |   |              |   |  |   |          |  
|Acquisition, exploration and developments costs             |  |        | (49,057  | ) |                       |   | (73,013  | )                        |  |   |             |   |  |   | (122,070 | )
|Additions to other property and equipment                   |  |        | (2,322   | ) |                       |   | (192     | )                        |  |   |             |   |  |   | (2,514   | )
|Proceeds from property sales                                |  |        |         |   |                       |   | 23,420   |                          |  |   |             |   |  |   | 23,420   |  
|Acquisition of 3TEC                                         |  |        |         |   |                       |   | (267,546 | )                        |  |   |             |   |  |   | (267,546 | )
|                                                            |  |        |          |   |                       |   |          |                          |  |   |              |   |  |   |          |  
|Net cash used in investing activities                       |  |        | (51,379  | ) |                       |   | (317,331 | )                        |  |   |             |   |  |   | (368,710 | )
|                                                            |  |        |          |   |                       |   |          |                          |  |   |              |   |  |   |          |  
|                                                            |  |        |          |  
|CASH FLOWS FROM FINANCING ACTIVITIES                        |  |        |          |   |                       |   |          |                          |  |   |              |   |  |   |          |  
|Principal payments of long-term debt                        |  |        | (511     | ) |                       |   |         |                          |  |   |             |   |  |   | (511     | )
|Change in revolving credit facility                         |  |        | 175,200  |   |                       |   |         |                          |  |   |             |   |  |   | 175,200  |  
|Proceeds from debt issuance                                 |  |        | 80,061   |   |                       |   |         |                          |  |   |             |   |  |   | 80,061   |  
|Debt issuance costs                                         |  |        | (4,349   | ) |                       |   |         |                          |  |   |             |   |  |   | (4,349   | )
|Contribution from Plains Resources Inc.                     |  |        | 510      |   |                       |   |         |                          |  |   |             |   |  |   | 510      |  
|Purchase treasury stock                                     |  |        | (130     | ) |                       |   |         |                          |  |   |             |   |  |   | (130     | )
|Investment in and advances to affiliates                    |  |        | (260,367 | ) |                       |   | 260,367  |                          |  |   |              |   |  |   |         |  
|                                                            |  |        |          |   |                       |   |          |                          |  |   |              |   |  |   |          |  
|Net cash provided by (used in) financing activities         |  |        | (9,586   | ) |                       |   | 260,367  |                          |  |   |             |   |  |   | 250,781  |  
|                                                            |  |        |          |   |                       |   |          |                          |  |   |              |   |  |   |          |  
|Net increase (decrease) in cash and cash equivalents        |  |        | (601     | ) |                       |   | 950      |                          |  |   |             |   |  |   | 349      |  
|Cash and cash equivalents, beginning of year                |  |        | 1,004    |   |                       |   | 24       |                          |  |   |             |   |  |   | 1,028    |  
|                                                            |  |        |          |   |                       |   |          |                          |  |   |              |   |  |   |          |  
|Cash and cash equivalents, end of year                      |  | $      | 403      |   |                       | $ | 974      |                          |  | $ |             |   |  | $ | 1,377    |  
|                                                            |  |        |          |   |                       |   |          |                          |  |   |              |   |  |   |          |  



F-36



---

##### Table of Contents

PLAINS EXPLORATION & PRODUCTION COMPANY



CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

YEAR ENDED DECEMBER 31, 2002

(in thousands)



|                                                            |  |        |          |   |                        |   |        |                           |  |   |              |   |  |   |          |  
|----------------------------------------------------------- |  | ------ | -------- | - | ---------------------- | - | ------ | ------------------------- |  | - | ------------ | - |  | - | -------- | -
|                                                            |  | Parent |          |   | Guarantor Subsidiaries |   |        | Intercompany Eliminations |  |   | Consolidated |  
|CASH FLOWS FROM OPERATING ACTIVITIES                        |  |        |          |   |                        |   |        |                           |  |   |              |   |  |   |          |  
|Net income                                                  |  | $      | 26,237   |   |                        | $ | 5,988  |                           |  | $ | (5,988       | ) |  | $ | 26,237   |  
|Items not affecting cash flows from operating activities:   |  |        |          |   |                        |   |        |                           |  |   |              |   |  |   |          |  
|Depreciation, depletion and amortization                    |  |        | 21,532   |   |                        |   | 8,827  |                           |  |   |             |   |  |   | 30,359   |  
|Equity in earnings of subsidiaries                          |  |        | (5,988   | ) |                        |   |       |                           |  |   | 5,988        |   |  |   |         |  
|Deferred income taxes                                       |  |        | 11,615   |   |                        |   | (1,236 | )                         |  |   |             |   |  |   | 10,379   |  
|Other noncash items                                         |  |        | 457      |   |                        |   |       |                           |  |   |             |   |  |   | 457      |  
|Change in assets and liabilities from operating activities: |  |        |          |   |                        |   |        |                           |  |   |              |   |  |   |          |  
|Accounts receivable and other assets                        |  |        | (12,301  | ) |                        |   | 337    |                           |  |   |             |   |  |   | (11,964  | )
|Inventories                                                 |  |        | (757     | ) |                        |   | 181    |                           |  |   |             |   |  |   | (576     | )
|Accounts payable to Plains Resources Inc.                   |  |        | 4,946    |   |                        |   |       |                           |  |   |             |   |  |   | 4,946    |  
|Accounts payable and other liabilities                      |  |        | 20,217   |   |                        |   | (1,229 | )                         |  |   |             |   |  |   | 18,988   |  
|                                                            |  |        |          |   |                        |   |        |                           |  |   |              |   |  |   |          |  
|Net cash provided by operating activities                   |  |        | 65,958   |   |                        |   | 12,868 |                           |  |   |             |   |  |   | 78,826   |  
|                                                            |  |        |          |   |                        |   |        |                           |  |   |              |   |  |   |          |  
|CASH FLOWS FROM INVESTING ACTIVITIES                        |  |        |          |   |                        |   |        |                           |  |   |              |   |  |   |          |  
|Acquisition, exploration and developments costs             |  |        | (54,811  | ) |                        |   | (9,686 | )                         |  |   |             |   |  |   | (64,497  | )
|Additions to other property and equipment                   |  |        | (185     | ) |                        |   | (5     | )                         |  |   |             |   |  |   | (190     | )
|Proceeds from property sales                                |  |        | 529      |   |                        |   |       |                           |  |   |             |   |  |   | 529      |  
|                                                            |  |        |          |   |                        |   |        |                           |  |   |              |   |  |   |          |  
|Net cash used in investing activities                       |  |        | (54,467  | ) |                        |   | (9,691 | )                         |  |   |             |   |  |   | (64,158  | )
|                                                            |  |        |          |   |                        |   |        |                           |  |   |              |   |  |   |          |  
|CASH FLOWS FROM FINANCING ACTIVITIES                        |  |        |          |   |                        |   |        |                           |  |   |              |   |  |   |          |  
|Principal payments of long-term debt                        |  |        | (511     | ) |                        |   |       |                           |  |   |             |   |  |   | (511     | )
|Change in revolving credit facility                         |  |        | 35,800   |   |                        |   |       |                           |  |   |             |   |  |   | 35,800   |  
|Proceeds from debt issuance                                 |  |        | 196,752  |   |                        |   |       |                           |  |   |             |   |  |   | 196,752  |  
|Debt issuance costs                                         |  |        | (5,936   | ) |                        |   |       |                           |  |   |             |   |  |   | (5,936   | )
|Contribution from Plains Resources Inc.                     |  |        | 52,200   |   |                        |   |       |                           |  |   |             |   |  |   | 52,200   |  
|Distribution to Plains Resources Inc.                       |  |        | (311,964 | ) |                        |   |       |                           |  |   |             |   |  |   | (311,964 | )
|Receipts from (payments to) Plains Resources Inc.           |  |        | 23,518   |   |                        |   | (3,155 | )                         |  |   |             |   |  |   | 20,363   |  
|Other                                                       |  |        | (357     | ) |                        |   |       |                           |  |   |             |   |  |   | (357     | )
|                                                            |  |        |          |   |                        |   |        |                           |  |   |              |   |  |   |          |  
|Net cash provided by (used in) financing activities         |  |        | (10,498  | ) |                        |   | (3,155 | )                         |  |   |             |   |  |   | (13,653  | )
|                                                            |  |        |          |   |                        |   |        |                           |  |   |              |   |  |   |          |  
|Net increase (decrease) in cash and cash equivalents        |  |        | 993      |   |                        |   | 22     |                           |  |   |             |   |  |   | 1,015    |  
|Cash and cash equivalents, beginning of year                |  |        | 11       |   |                        |   | 2      |                           |  |   |             |   |  |   | 13       |  
|                                                            |  |        |          |   |                        |   |        |                           |  |   |              |   |  |   |          |  
|Cash and cash equivalents, end of year                      |  | $      | 1,004    |   |                        | $ | 24     |                           |  | $ |             |   |  | $ | 1,028    |  
|                                                            |  |        |          |   |                        |   |        |                           |  |   |              |   |  |   |          |  



F-37



---

##### Table of Contents

PLAINS EXPLORATION & PRODUCTION COMPANY



CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

YEAR ENDED DECEMBER 31, 2001

(in thousands)



|                                                            |  |        |          |   |                        |   |         |                           |  |   |              |   |  |   |          |  
|----------------------------------------------------------- |  | ------ | -------- | - | ---------------------- | - | ------- | ------------------------- |  | - | ------------ | - |  | - | -------- | -
|                                                            |  | Parent |          |   | Guarantor Subsidiaries |   |         | Intercompany Eliminations |  |   | Consolidated |  
|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                          |  |        | (11,288  | ) |                        |   |         |                           |  |   | 11,288       |   |  |   |          |  
|Deferred income taxes                                       |  |        | 27,620   |   |                        |   | 754     |                           |  |   |             |   |  |   | 28,374   |  
|Cumulative effect of adoption of accounting change          |  |        | 1,522    |   |                        |   | (240    | )                         |  |   | 240          |   |  |   | 1,522    |  
|Change in derivative fair value                             |  |        | (7       | ) |                        |   | 1,062   |                           |  |   |             |   |  |   | 1,055    |  
|Other noncash items                                         |  |        | 263      |   |                        |   | 733     |                           |  |   |             |   |  |   | 996      |  
|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                   |  |        | 98,714   |   |                        |   | 18,094  |                           |  |   |             |   |  |   | 116,808  |  
|                                                            |  |        |          |   |                        |   |         |                           |  |   |              |   |  |   |          |  
|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.           |  |        | 10,272   |   |                        |   | (1,212  | )                         |  |   |             |   |  |   | 9,060    |  
|                                                            |  |        |          |   |                        |   |         |                           |  |   |              |   |  |   |          |  
|Net cash provided by (used in) financing activities         |  |        | 9,761    |   |                        |   | (1,212  | )                         |  |   |             |   |  |   | 8,549    |  
|                                                            |  |        |          |   |                        |   |         |                           |  |   |              |   |  |   |          |  
|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-38



---

##### Table of Contents

Note 15Subsequent Event (unaudited)



On February 12, 2004 we announced that we had entered into a definitive agreement to acquire Nuevo Energy Company, or Nuevo, in a
stock for stock transaction valued at approximately $945 million, based on our February 11, 2004 closing stock price of $15.89 per share. Under the terms of the definitive agreement, Nuevo stockholders will receive 1.765 shares of our common stock
for each share of Nuevo common stock. If completed, we will issue up to 38.8 million shares to Nuevo shareholders and assume $234 million of net debt (as of December 31, 2003) and $115 million of Trust Convertible Preferred Securities.



The transaction is expected to qualify as a tax free reorganization under Section
368(a) and is expected to be tax free to our stockholders and tax free for the stock consideration received by Nuevo stockholders. The Boards of directors of both companies have approved the merger agreement and each has recommended it to their
respective stockholders for approval. The transaction will remain subject to stockholder approval from both companies and other customary conditions. Post closing, it is anticipated that our stockholders will own approximately 52% of the combined
company and Nuevo stockholders will own approximately 48% of the combined company.



We will account for the transaction as a purchase of Nuevo under purchase accounting rules and we will continue to use the full cost method of accounting for our oil and gas properties.



F-39