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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, 2004



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 |  | (I.R.S. Employer   
|incorporation or organization)  |  | Identification No.)



700 Milam Street, Suite 3100

Houston, Texas 77002

(Address of
principal executive offices)

(Zip Code)



(713) 579-6000

(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.  Yes x    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.  x



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



On February 28, 2005, there were 77.4 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 $1.36 billion on June 30, 2004 (based on $18.35 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 2005 Annual Meeting of Stockholders.



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PLAINS EXPLORATION & PRODUCTION COMPANY.

2004 ANNUAL REPORT ON FORM 10-K



Table of Contents



|             |  |                                                                                                             |  |   
|------------ |  | ----------------------------------------------------------------------------------------------------------- |  | --
|             |  | Part I                                                                                                      |  |   
|Items 1 & 2. |  | Business and Properties                                                                                     |  | 5 
|Item 3.      |  | Legal Proceedings                                                                                           |  | 29
|Item 4.      |  | Submission of Matters to a Vote of Security Holders                                                         |  | 29
|             |  |                                                                                                            
|             |  | Part II                                                                                                     |  |   
|Item 5.      |  | Market for Registrants Common Stock, Related Stockholder Matters and Issuer Purchases of Equity Securities |  | 31
|Item 6.      |  | Selected Financial Data                                                                                     |  | 32
|Item 7.      |  | Managements Discussion and Analysis of Financial Condition and Results of Operations                       |  | 34
|Item 7A.     |  | Quantitative and Qualitative Disclosures About Market Risks                                                 |  | 54
|Item 8.      |  | Financial Statements and Supplementary Data                                                                 |  | 57
|Item 9.      |  | Changes in and Disagreements with Accountants on Accounting and Financial Disclosure                        |  | 57
|Item 9A.     |  | Controls and Procedures                                                                                     |  | 57
|Item 9B.     |  | Other Information                                                                                           |  | 58
|             |  |                                                                                                            
|             |  | Part III                                                                                                    |  |   
|Item 10.     |  | Directors and Executive Officers of the Registrant                                                          |  | 58
|Item 11.     |  | Executive Compensation                                                                                      |  | 58
|Item 12.     |  | Security Ownership of Certain Beneficial Owners and Management                                              |  | 58
|Item 13.     |  | Certain Relationships and Related Transactions                                                              |  | 58
|Item 14.     |  | Principal Accounting Fees and Services                                                                      |  | 58
|             |  |                                                                                                            
|             |  | Part IV                                                                                                     |  |   
|Item 15.     |  | Exhibits, Financial Statement Schedules                                                                     |  | 59





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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 as a result of any significant acquisitions, including the recent acquisition of Nuevo;
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | 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 website at www.sec.gov. No information from the SECs website is incorporated by reference herein. Our
website 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



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thereto, free of charge from our website. These documents are posted to our website 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 document:



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.



Bcfe.    One billion cubic
feet of gas equivalent.



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.



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 or gas.



Gas.    Natural gas.



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



MBOE.    One thousand BOE.



Mcf.    One thousand cubic feet of gas.



Mcfe.    One thousand cubic feet of gas equivalent.



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



MMBOE.    One million BOE.



MMBtu.    One million British Thermal
units. One British thermal unit is the amount of heat required to raise the temperature of one pound of water by one degree Fahrenheit.



MMcf.    One million cubic feet of gas.



MMcfe.    One million cubic feet of gas equivalent.



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



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),



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



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) oil, 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) oil, gas, and natural gas liquids, that may occur in undrilled prospects; and (iv) oil, 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 additions.    Changes in proved reserves due to revisions of previous estimates, extensions, discoveries,
improved recovery and other additions and purchases of reserves in-place.



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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.



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.



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



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.



The terms terms development well, proved developed
reserves, proved reserved and proved undeveloped reserves are defined by the SEC. 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, exploring and producing oil and gas properties in the United States. We own oil and gas properties in five
states with principal operations in:



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



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



| |  |  | the Gulf Coast Basin onshore and offshore Louisiana, including the Gulf of Mexico;
| | - |  | ----------------------------------------------------------------------------------



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



| |  |  | the Val Verde portion of the greater Permian Basin in Texas.
| | - |  | ------------------------------------------------------------



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 have historically hedged portions of our oil and gas production to manage our exposure to commodity price risk.



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Acquisition of Nuevo Energy Company



On May 14, 2004 we acquired Nuevo Energy Company (Nuevo) in a stock-for-stock transaction. In the acquisition, each
outstanding share of Nuevo common stock was converted into 1.765 shares of PXP common stock and Nuevo became our wholly owned subsidiary. At the closing of this transaction we issued 36.5 million additional PXP common shares and assumed $254 million
in net debt and $115 million of $2.875 Term Convertible Securities, Series A, or TECONS. The transaction is expected to qualify as a tax free reorganization under Section 368(a) of the Internal Revenue Code and to be tax free to our stockholders and
to be tax free for the stock portion of the consideration received by Nuevo stockholders. We have accounted for the transaction as a purchase of Nuevo under purchase accounting rules and we continue to use the full cost method of accounting for our
oil and gas properties.



In connection with our acquisition of Nuevo we
completed a series of transactions to refinance a portion of our and all of Nuevos outstanding debt (the Recapitalization Transactions). The Recapitalization Transactions included amendments to our credit facility and the indenture
governing our 8.75% senior subordinated notes, our issuance of $250 million of 7.125% senior notes due 2014, a cash tender offer for Nuevos outstanding $150 million of 9.375% senior subordinated notes, the redemption of the TECONS and the
termination of Nuevos credit facility. All of these transactions were successfully completed on or before June 30, 2004. SeeItem 7. Managements Discussion and Analysis of Financial Condition and Results of OperationsFinancing
Activities.



Acquisition of 3TEC Energy Corporation



On June 4, 2003, we acquired 3TEC Energy Corporation (3TEC) for
approximately $312.9 million in cash and common stock plus $90.0 million to retire 3TECs outstanding debt. Prior to the acquisition, 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 into 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 3TEC 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 under purchase accounting rules
effective June 1, 2003.



Acquisition of Oil and Gas Properties



We have entered into an agreement to acquire certain California producing oil and gas
properties from a private company for $119 million. The properties, which currently produce approximately 2,000 BOE per day, are primarily located in the Los Angeles Basin of onshore California with some smaller properties located in adjacent
Ventura County. The transaction is expected to close in the second quarter of 2005, subject to customary closing conditions. The acquisition will be financed under our existing credit facility.



Oil and Gas Reserves



We had estimated proved reserves of 419.3 MMBOE as of December 31, 2004, of which 84% was comprised of oil and 68% was proved
developed. We have a total proved reserve life of over 16 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, 2004 and based on year-end 2004 spot market prices of $43.45 per Bbl of oil and $6.15 per MMBtu of gas, as adjusted for area and quality differentials, our reserves had a PV-10 of $3.3
billion and a standardized measure of $2.2 billion.



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The following table sets forth information with respect to our oil and gas properties as of and for the year ended
December 31, 2004 (dollars in millions):



|                                |  |                   |         |   |                    |   |       |       |  |   |       |   |  |   |         |  
|------------------------------- |  | ----------------- | ------- | - | ------------------ | - | ----- | ----- |  | - | ----- | - |  | - | ------- | -
|                                |  | OnshoreCalifornia |         |   | OffshoreCalifornia |   |       | Other |  |   | Total |  
|Proved reserves                 |  |                   |         |   |                    |   |       |       |  |   |       |   |  |   |         |  
|MMBOE                           |  |                   | 345.0   |   |                    |   | 30.1  |       |  |   | 44.2  |   |  |   | 419.3   |  
|Percent oil                     |  |                   | 92      | % |                    |   | 96    | %     |  |   | 13    | % |  |   | 84      | %
|Proved Developed ReservesMMBOE |  |                   | 221.3   |   |                    |   | 28.2  |       |  |   | 35.1  |   |  |   | 284.6   |  
|2004 ProductionMMBOE           |  |                   | 12.6    |   |                    |   | 4.2   |       |  |   | 6.1   |   |  |   | 22.9    |  
|PV-10 (1)                       |  | $                 | 2,603.7 |   |                    | $ | 229.2 |       |  | $ | 509.0 |   |  | $ | 3,341.9 |  
|Standardized measure (2)        |  |                   |         |   |                    |   |       |       |  |   |       |   |  | $ | 2,236.7 |  

---

|(1) | Based on year-end 2004 spot market prices of $43.45 per Bbl of oil and $6.15 per MMBtu of gas as adjusted for area and quality differentials. PV-10 represents the standardized measure before
deducting estimated future income taxes.
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|(2) | 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.
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------



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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. in 2004 and Netherland, Sewell & Associates, Inc. and Ryder Scott Company in 2003 and 2002. 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 December 31,    
|                                     |  | 2004                   |           | 2003 |   | 2002     
|                                     |  | (dollars in thousands)
|Oil and Gas Reserves                 |  |                        |           |      |   |           |  |   |          
|Oil (MBbls)                          |  |                        |           |      |   |           |  |   |          
|Proved developed                     |  |                        | 233,707   |      |   | 124,822   |  |   | 127,415  
|Proved undeveloped                   |  |                        | 117,696   |      |   | 102,906   |  |   | 112,746  
|                                     |  |                        |           |      |   |           |  |   |          
|                                     |  |                        | 351,403   |      |   | 227,728   |  |   | 240,161  
|                                     |  |                        |           |      |   |           |  |   |          
|Gas (MMcf)                           |  |                        |           |      |   |           |  |   |          
|Proved developed                     |  |                        | 305,009   |      |   | 235,070   |  |   | 53,317   
|Proved undeveloped                   |  |                        | 102,391   |      |   | 84,107    |  |   | 23,837   
|                                     |  |                        |           |      |   |           |  |   |          
|                                     |  |                        | 407,400   |      |   | 319,177   |  |   | 77,154   
|                                     |  |                        |           |      |   |           |  |   |          
|MBOE                                 |  |                        | 419,303   |      |   | 280,924   |  |   | 253,020  
|                                     |  |                        |           |      |   |           |  |   |          
|PV-10 (1):                           |  |                        |           |      |   |           |  |   |          
|Proved developed                     |  | $                      | 2,639,190 |      | $ | 1,390,995 |  | $ | 916,373  
|Proved undeveloped                   |  |                        | 702,759   |      |   | 578,300   |  |   | 598,671  
|                                     |  |                        |           |      |   |           |  |   |          
|                                     |  | $                      | 3,341,949 |      | $ | 1,969,295 |  | $ | 1,515,044
|                                     |  |                        |           |      |   |           |  |   |          
|Standardized Measure                 |  | $                      | 2,236,719 |      | $ | 1,256,803 |  | $ | 883,507  
|                                     |  |                        |           |      |   |           |  |   |          
|Average year-end realized prices (2) |  |                        |           |      |   |           |  |   |          
|Oil (per Bbl)                        |  | $                      | 30.91     |      | $ | 28.22     |  | $ | 26.91    
|Gas (per Mcf)                        |  | $                      | 5.40      |      | $ | 5.53      |  | $ | 4.63     
|Year-end spot market prices          |  |                        |           |      |   |           |  |   |          
|Oil (per Bbl)                        |  | $                      | 43.45     |      | $ | 32.52     |  | $ | 31.20    
|Gas (per Mcf)                        |  | $                      | 6.15      |      | $ | 5.97      |  | $ | 4.79     
|Reserve life (years) (3)             |  |                        | 16.3      |      |   | 19.6      |  |   | 27.1     

---

|(1) | PV-10 represents the standardized measure before deducting estimated future income taxes. Our year-end 2004 PV-10 and standardized measure include future development costs related to proved
undeveloped reserves of $142.0 million in 2005, $108.1 million in 2006 and $77.4 million in 2007.
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|(2) | Based on price in effect at year-end with adjustments based on location and quality. The market price for California crude oil differs from the established market indices due primarily to the
higher transportation and refining costs associated with heavy oil. At the end of 2004 the basis differentials for California crude oil had widened significantly from prior years end. As a result, the difference between the year-end spot market
price and our average year-end realized price for 2004 is significantly greater than in 2003 and 2002.
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|(3) | 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. 2004 and 2003 are based on annualized fourth quarter production to reflect the effect of the Nuevo and 3TEC acquisitions and the sale of certain producing properties.
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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During the three-year period ended December 31, 2004 we participated in 38 exploratory wells, of which 25 were
successful, and 352 development wells, 349 of which were successful. During this period, we incurred aggregate oil and gas acquisition, exploitation, development and exploration costs of $2.1 billion, approximately 97% of which was for acquisition,
exploitation and development activities. During this period proved reserve additions totaled 291.2 MMBOE.



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



In accordance with SEC
guidelines, the reserve engineers estimates of future net revenues from our properties, and the present value of the properties, are made using oil and gas sales prices in effect as of the dates of such estimates and are held constant
throughout the life of the properties, except where the guidelines permit alternate treatment, including the use of fixed and determinable contractual price escalations but excluding the effect of any hedges we have in place. Historically, the
prices for oil and gas have been volatile and are likely to continue to be volatile in the future.



Since December 31, 2003 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



We expect to continue our reserve and production growth through the exploitation and
development of our existing inventory of projects in each of our primary operating areas. To complement the exploitation and development activities, we expect to continue to expand on our success in exploratory drilling by taking advantage of our
exploratory projects in south Louisiana, Texas and the Gulf of Mexico. To implement the plans, we will focus on:



| |  |  | allocating investment capital prudently after rigorous evaluation;
| | - |  | ------------------------------------------------------------------



| |  |  | optimizing production practices;
| | - |  | --------------------------------



| |  |  | realigning and expanding injection processes;
| | - |  | ---------------------------------------------



| |  |  | performing stimulations, recompletions, artificial lift upgrades and other operating margin and reserve enhancements;
| | - |  | ---------------------------------------------------------------------------------------------------------------------



| |  |  | 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.
| | - |  | -----------------------------------------------------------------------



By implementing our exploitation, development and exploration plan, we seek to increase cash flows and enhance the value of our asset base. In doing so, we add to
and enhance our proved



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reserves. During the three-year period ended December 31, 2004 our additions to proved reserves, excluding reserves added as a result of acquisition activities,
totaled 53.4 MMBOE. During this period we incurred aggregate oil and gas exploitation, development and exploration costs of $378.0 million.



The Company has a $375 million capital budget for 2005. Approximately 40-45% of the budget is expected to be spent on California onshore projects and 10-15% is
expected to be spent offshore California. Approximately 20-25% is expected to be spent in the Gulf Coast Basin onshore and offshore Louisiana and includes expected participation in new prospect areas in the Gulf of Mexico. The remainder of the
budget is expected to be spent in the East Texas Basin and north Louisiana and the Permian Basin in west Texas. Approximately 85% of the budget is allocated toward reserve exploitation, development drilling and maintenance while 15% is allocated for
exploration activities. The capital budget includes estimated capitalized general and administrative and interest expense of $25 million.



Description of Properties



Los Angeles and San Joaquin Basins in California



LA Basin



We essentially hold a 100% working interest in our LA Basin properties, including interests in the Montebello, Inglewood and Inglewood satellite fields, and operate
approximately 543 production and 223 waterflood injection wells in the fields. The LA Basin properties are characterized by lighter crude (23 to 29 degree API), wells from 2,000 feet to over 10,000 feet at our Deep Inglewood project and include both
primary production and waterfloods.



Seismic technology is being utilized
to further evaluate the unproved reserves in our LA Basin properties and enhance development of proved undeveloped reserves: conventional 3-D seismic 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 completed in January 2004 and drilling in the Deep Inglewood project started in February 2004. At the end of February 2005, 20 wells had been drilled and 17 are on line producing
approximately 2,500 BOE per day. Three wells are being completed and two additional wells are drilling. This is the first application of 3-D seismic technology for exploitation of an onshore LA Basin oil field.



We also own approximately 480 acres of surface fee land in the Montebello field. We are
currently in the process of seeking entitlements from the relevant regulatory agencies to enable residential and commercial real estate development on our fee lands as the Montebello field continues to mature.



In 2004, we spent $61.3 million on capital projects in the LA Basin. The Inglewood
field accounted for $50.3 million or 82% of the capital associated with LA Basin projects. Our net average daily production from our LA Basin properties in the fourth quarter of 2004 was 16.2 MBOE per day.



San Joaquin Basin



We hold interests in the Cymric, Midway Sunset, South Belridge, Buena
Vista Hills and various other fields in the San Joaquin Basin. Our San Joaquin properties are generally characterized by heavier oil (12 to 16 degree API) and shallow wells (generally less than 2,000 feet) that require cyclic and continuous thermal
stimulation. These properties also produce lesser amounts of lighter oil and natural gas under primary recovery.



In 2004, we spent $28.2 million on capital projects in the San Joaquin Basin and drilled 58 wells. In the South Belridge field we spent $12.2 million and drilled 26
wells, in the Cymric field we spent $7.7 million and drilled 16 wells, in the Midway Sunset field we spent $5.4 million and drilled 14 wells and in the other fields we spent $2.9 million and drilled two wells. Our net average daily production from
our San Joaquin Basin properties in the fourth quarter of 2004 was 28.7 MBOE per day.



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##### Table of Contents

Other Onshore California



We hold a 100% working interest (94% net revenue interest) in the Arroyo Grande field located in San Luis Obispo County,
California. We also have 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. We have drilled 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.



Total proved reserves in Arroyo Grande Field were 54.8 MMBOE at December 31, 2004 with
49.2 MMBOE proved undeveloped which represents approximately 37% of our total proved undeveloped reserves. In 2004 we began final planning, engineering, and permitting for the installation of a reverse osmosis water treatment plant and water
out-take pipeline needed to remove water from the producing reservoir and increase operating efficiency. We expect to install those facilities during 2005 and 2006 with completion anticipated in mid to late 2006. During 2005 we will continue with an
active program of side-track drilling existing wells, converting existing wells to steam injection, and recompleting wells to open additional pay intervals. Accelerated drilling of new wells is anticipated in 2006. In the fourth quarter of 2004 our
net production from the field averaged 1.7 MBOE per day.



Santa
Maria Basin Offshore California



Point Arguello
Unit.    We hold a 52.6% working interests in the Point Arguello unit and the various partnerships owning the related transportation, processing and marketing infrastructure. 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 are responsible for our 52.6% share of all other abandonment costs, primarily well-bore abandonments and conductor removals.



We are the operator for the Point Arguello unit, which consists of three offshore platforms. In 2004, we spent $4.1 million on capital projects and our net average
daily oil production for the unit in the fourth quarter of 2004 was 3.8 MBOE per day.



P-0451 E/2 Development.    We are the operator of federal offshore lease 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 east half of the P-0451 lease. We 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. The west half of lease P-0451 has already been developed as part of the Point Arguello unit.



In October 2004, we successfully completed the initial development well into the P-0451 E/2 field also known as the Rocky Point structure. A second well was placed
on production in January 2005 and at the end of February the two wells were producing at a combined rate of approximately 4,500 barrels per day (gross). A third well was drilling in late February and we estimate up to five additional wells may be
drilled to complete P-0451 E/2 exploitation. In 2004 we spent $15.5 million on capital projects on P-0451 E/2.



Point Pedernales.    As a result of the Nuevo acquisition,we acquired a 100% working interest in the Pt. Pedernales field which
includes the onshore Lompoc facilities and one platform, which is utilized to exploit the Federal OCS Monterey Reservoir. In 2004 we spent $1.1 million on capital projects. Our net average daily production from our Pt. Pedernales field in the fourth
quarter of 2004 was 5.7 MBOE per day. Efforts are also underway to obtain the necessary permits and leasehold rights to exploit the offsetting Tranquillon Ridge Monterey structure, utilizing directional wells drilled from the existing platform to a
reservoir within the three mile state water limit.



11



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##### Table of Contents

Gulf Coast Basin Onshore and Offshore Louisiana



In 2004, we spent $30.3 million on exploration and development projects in this area.
We drilled a total of 16 wells, six of which were successful (38% success rate). Our successful wells included one non-operated onshore well, four operated wells in state waters and one operated well in federal waters of the Gulf of Mexico. Planned
2005 activity includes two to three onshore wells, six to eight wells in state waters and five to seven wells in federal waters. Our net average daily oil and gas production for this area was 6.7 MBOE in the fourth quarter of 2004.



In 2003 we acquired an interest in the Breton Sound Extension area which is located
east-southeast of New Orleans. We operate portions of the area (where we have a 56.25% working interest) and portions are operated by others (where we have a 37.5% working interest). The wells are in water depths of ten to twenty-five feet. In 2004
we drilled and completed our first operated well in federal waters, in Chandeleur Area 30, as an expansion of our Breton Sound Extension joint venture.



In 2004 we entered into a new joint venture covering six blocks in Main Pass area where two to three wells are planned for 2005. We have a 50% working interest in
the joint venture which is operated by an industry partner.



We are
pursuing additional opportunities and to date have acquired the right to participate in six deep water drilling opportunities in the Gulf of Mexico.



East Texas Basin 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 potential additional pay in the shallower Travis Peak and Pettit formations. There are many proved 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 2004 we had 81 identified proved undeveloped locations in this area.



In 2004, we spent $25.6 million on exploitation and development projects on these
properties and participated in the drilling of 45 development wells, all of which were successful. Our net average daily oil and gas production for this area was 6.3 MBOE in the fourth quarter of 2004.



Permian Basin in West Texas



As a result of the Nuevo acquisition we acquired an interest in the Pakenham field in
west Texas which currently has 164 producing gas wells. The field is located in Terrell County, Texas within the overall Permian Basin complex of West Texas on the southern margin of the Val Verde Basin. We are the operator with working interests
ranging from 81% to 100%. In 2004 we spent $14.9 million on capital projects that included the drilling of seven development wells, one of which was dry. Production from the field averaged 3.1 MBOE per day in the fourth quarter of 2004.



Property Divestments



We periodically evaluate and from time to time elect to sell certain of our mature
producing properties that we consider to be nonstrategic. Such sales enable us to focus on our core properties, maintain financial flexibility and redeploy the proceeds therefrom to activities that we believe potentially have a higher financial
return.



12



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##### Table of Contents

In December 2004, we completed the sale of certain properties located offshore California and onshore South Texas,
New Mexico, and South Louisiana. These transactions included the divestment of 11 platforms in federal and state waters off the coast of California and three related onshore facilities and essentially all our remaining assets in South Texas and New
Mexico. These divestments were conducted via negotiated and auction transactions. In aggregate, we received net proceeds of approximately $153 million from these transactions. These amounts are subject to customary post closing adjustments and the
offshore California sale is subject to certain post closing regulatory approvals and transfer conditions. The offshore California properties were acquired in May 2004 as a result of the Nuevo acquisition. We have agreed to retain certain abandonment
obligations in connection with the offshore California properties.



In a
series of transactions in the first and second quarters of 2004 we sold our interests in certain non-core producing properties in New Mexico, Texas, Mississippi, Louisiana, and Illinois for proceeds of approximately $28 million. Our oil and gas
interests in the Illinois Basin were not in our core areas of operation and did not compete well for capital with the properties within our core areas. The Illinois properties also had high operating costs. These factors led to the sale of our
Illinois properties through an extensive auction process. The sale was completed through a stock purchase agreement with standard terms, including typical purchase price adjustments, representations and warranties, and assumption of liabilities by
the purchaser for an adjusted purchase price of approximately $14 million. The reserves attributable to our Illinois properties were not material in relation to our total reserves.



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 million.



Other



During the second and third quarters of 2004, we sold certain real estate parcels acquired in the Nuevo merger and received aggregate proceeds of approximately $4
million. The properties represented approximately 609 surface acres located in Santa Barbara and Los Angeles counties in California.



In April 2004, Nuevo entered into definitive agreements for the sale of the stock of its subsidiaries that held oil and gas interests in the Republic of Congo. The
sale closed on July 30, 2004 and we received net cash consideration of approximately $54 million. When we acquired Nuevo, the fair value of the investment in the Congo operations was accounted for as an asset held for sale.



In December 2003, Nuevo sold its Tonner Hills residential development property for
approximately $47 million. To date approximately $41 million of the purchase price has been received and the remainder is due upon completion of certain habitat restoration activities, which we expect to complete during 2005.



13



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##### Table of Contents

Acquisition, Exploration, Exploitation and Development Expenditures



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



|                                   |  |                           |           |      |   |         |  |   |        |  
|---------------------------------- |  | ------------------------- | --------- | ---- | - | ------- |  | - | ------ | -
|                                   |  | Year Ended December 31,   |          
|                                   |  | 2004                      |           | 2003 |   | 2002    | 
|                                   |  | (In thousands of dollars) |          
|Property acquisitions costs:       |  |                           |           |      |   |         |  |   |        |  
|Unproved properties                |  | $                         | 144,894   |      | $ | 80,141  |  | $ | 65     |  
|Proved properties (1)              |  |                           | 1,210,758 |      |   | 295,553 |  |   | (4,516 | )
|Exploration costs                  |  |                           | 57,530    |      |   | 8,947   |  |   | 602    |  
|Exploitation and development costs |  |                           | 141,198   |      |   | 101,334 |  |   | 68,346 |  
|                                   |  |                           |           |      |   |         |  |   |        |  
|                                   |  | $                         | 1,554,380 |      | $ | 485,975 |  | $ | 64,497 |  
|                                   |  |                           |           |      |   |         |  |   |        |  

---

|(1) | In connection with the 2002 acquisition of an additional interest in the Point Arguello field, offshore California, 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
$31.2 million in 2004, $30.2 million in 2003 and $27.3 million in 2002 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



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##### 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, 2004, 2003 and 2002.



|                                         |  |                         |          |   |      |   |         |      |  |   |         |  
|---------------------------------------- |  | ----------------------- | -------- | - | ---- | - | ------- | ---- |  | - | ------- | -
|                                         |  | Year Ended December 31, |         
|                                         |  | 2004                    |          |   | 2003 |   |         | 2002 | 
|Sales                                    |  |                         |          |   |      |   |         |      |  |   |         |  
|Oil (MBbls)                              |  |                         | 16,441   |   |      |   | 9,267   |      |  |   | 8,783   |  
|Gas (MMcf)                               |  |                         | 38,590   |   |      |   | 18,195  |      |  |   | 3,362   |  
|MBOE                                     |  |                         | 22,872   |   |      |   | 12,300  |      |  |   | 9,343   |  
|Revenue ($ in thousands)                 |  |                         |          |   |      |   |         |      |  |   |         |  
|Oil                                      |  | $                       | 593,809  |   |      | $ | 249,500 |      |  | $ | 193,615 |  
|Oil hedging                              |  |                         | (145,753 | ) |      |   | (51,352 | )    |  |   | (15,577 | )
|                                         |  |                         |          |   |      |   |         |      |  |   |         |  
|                                         |  |                         | 448,056  |   |      |   | 198,148 |      |  |   | 178,038 |  
|                                         |  |                         |          |   |      |   |         |      |  |   |         |  
|Gas                                      |  |                         | 227,468  |   |      |   | 91,267  |      |  |   | 10,299  |  
|Gas hedging                              |  |                         | (6,108   | ) |      |   | 13,787  |      |  |   |        |  
|                                         |  |                         |          |   |      |   |         |      |  |   |         |  
|                                         |  |                         | 221,360  |   |      |   | 105,054 |      |  |   | 10,299  |  
|                                         |  |                         |          |   |      |   |         |      |  |   |         |  
|Other                                    |  |                         | 2,290    |   |      |   | 888     |      |  |   | 226     |  
|                                         |  |                         |          |   |      |   |         |      |  |   |         |  
|                                         |  | $                       | 671,706  |   |      | $ | 304,090 |      |  | $ | 188,563 |  
|                                         |  |                         |          |   |      |   |         |      |  |   |         |  
|Average Prices and Costs                 |  |                         |          |   |      |   |         |      |  |   |         |  
|Average Oil Sales Price ($/Bbl)          |  |                         |          |   |      |   |         |      |  |   |         |  
|Net realized price before hedging        |  | $                       | 36.12    |   |      | $ | 26.92   |      |  | $ | 22.04   |  
|Hedging revenue (expense)                |  |                         | (8.87    | ) |      |   | (5.54   | )    |  |   | (1.77   | )
|                                         |  |                         |          |   |      |   |         |      |  |   |         |  
|Net realized price                       |  | $                       | 27.25    |   |      | $ | 21.38   |      |  | $ | 20.27   |  
|                                         |  |                         |          |   |      |   |         |      |  |   |         |  
|Average Gas Sales Price ($/Mcf)          |  |                         |          |   |      |   |         |      |  |   |         |  
|Net realized price before hedging        |  | $                       | 5.90     |   |      | $ | 5.01    |      |  | $ | 3.06    |  
|Hedging revenue (expense)                |  |                         | (0.16    | ) |      |   | 0.76    |      |  |   |        |  
|                                         |  |                         |          |   |      |   |         |      |  |   |         |  
|Net realized price                       |  | $                       | 5.74     |   |      | $ | 5.77    |      |  | $ | 3.06    |  
|                                         |  |                         |          |   |      |   |         |      |  |   |         |  
|Average Realized Price per BOE           |  | $                       | 29.27    |   |      | $ | 24.65   |      |  | $ | 20.16   |  
|Costs and Expenses per BOE               |  |                         |          |   |      |   |         |      |  |   |         |  
|Production costs                         |  |                         |          |   |      |   |         |      |  |   |         |  
|Lease operating expenses                 |  |                         | 5.36     |   |      |   | 5.44    |      |  |   | 5.57    |  
|Steam gas costs                          |  |                         | 1.77     |   |      |   | 0.23    |      |  |   | 0.19    |  
|Electricity                              |  |                         | 1.32     |   |      |   | 1.82    |      |  |   | 2.18    |  
|Production and ad valorem taxes          |  |                         | 0.98     |   |      |   | 0.82    |      |  |   | 0.46    |  
|Gathering and transportation             |  |                         | 0.33     |   |      |   | 0.21    |      |  |   |        |  
|Depletion, depreciation and amortization |  |                         | 5.93     |   |      |   | 3.86    |      |  |   | 3.17    |  



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 are subject to wide fluctuations and depend on numerous
factors beyond our control, including location and quality differentials, 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



15



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##### Table of Contents

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.



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.



A substantial portion of our oil and gas reserves are located in California and
approximately 55% of our production is attributable to heavy crude (generally 21 degree API gravity crude oil or lower). Our heavy crude is primarily sold to ConocoPhilips under a 15 year contract which expires on December 31, 2014. This contract
provides for pricing based on a percentage of the NYMEX crude oil price for each type of crude oil that we produce and deliver to ConocoPhillips in California. This percentage may be renegotiated every two years, with the current percentage rates
eligible for renegotiation effective at the end of 2005. We are currently receiving approximately 80% of the NYMEX index price for crude oil sold under the ConocoPhillips contract, representing approximately 46% of our total crude oil production.



Approximately 44% of our crude oil production is sold through Plains All
American Pipeline, L.P. (PAA) with 71% sold under contracts that provide for NYMEX less a fixed price differential (currently averaging NYMEX less $4.80) and 29% sold under contracts that provide for monthly field posted prices. These
contracts expire at various times from January 1, 2006 through 2008. The marketing agreement with PAA provides that PAA will purchase for resale at market prices certain of our oil production for which PAA charges a marketing fee of either $0.20 or
$0.15 per barrel based upon the contract the barrels are resold under.



The remaining 10% of our crude oil production is sold to others under contracts tied to monthly field posted prices. All production volumes in the foregoing discussion are based on the Companys fourth quarter 2004 production volumes,
pro forma as if the property sales completed in the fourth quarter were effective as of October 1, 2004.



The market price for California crude oil differs from the established market indices in the U.S., due principally to the higher transportation and refining costs
associated with heavy oil. While the contracts providing for NYMEX based pricing do not reduce our exposure to price volatility, they do help manage the risk of widening basis differentials between the NYMEX index price and the field posted prices
for our California oil production. During 2004, the basis differentials for California crude oil widened significantly from past levels and the prices received by the Company under NYMEX based crude oil contracts were favorable relative to the
current market prices. There can be no assurance that the Company will continue to receive the favorable differentials when the price differentials are renegotiated or that the market differentials will not decrease below our contracted prices.



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. Approximately 84% of our gas production is sold monthly based on industry recognized, published index pricing. The remaining 16% is priced daily on
the spot market. Fluctuations between the two pricing mechanisms can significantly impact the overall differential to the Henry Hub.



16



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##### Table of Contents

During 2004, 2003 and 2002 sales to PAA accounted for 33%, 70% and 95%, respectively, of our total revenues and
during 2004 sales to ConocoPhillips accounted for 33% of our total revenues. During such periods no other purchaser accounted for more than 10% of our total revenues. The loss of any single significant customer or contract could have a material
adverse short-term effect, however, we do not believe that the loss of any single significant customer or contract would materially affect our business in the long-term. We believe such purchasers could be replaced by other purchasers under
contracts with similar terms and conditions. However, their role as the purchaser of a significant portion of our oil production does have the potential to impact our overall exposure to credit risk, either positively or negatively, in that they may
be affected by changes in economic, industry or other conditions.



Productive Wells
and Acreage



As of December 31, 2004 we had working interests in
2,662 gross (2,620 net) active producing oil wells and 1,077 gross (573 net) active producing gas wells. The following table sets forth information with respect to our developed and undeveloped acreage as of December 31, 2004:



.



|                    |  |                 |  |                       |  |         |  |        
|------------------- |  | --------------- |  | --------------------- |  | ------- |  | -------
|                    |  | Developed Acres |  | Undeveloped Acres (1)
|                    |  | Gross           |  | Net                   |  | Gross   |  | Net    
|Onshore California  |  | 215,961         |  | 126,904               |  | 108,415 |  | 76,209 
|Offshore California |  | 41,588          |  | 34,328                |  | 167,050 |  | 21,503 
|Kansas              |  |                |  |                      |  | 48,147  |  | 37,647 
|Louisiana           |  | 19,734          |  | 7,797                 |  | 49,159  |  | 41,454 
|Oklahoma            |  | 10,511          |  | 3,991                 |  | 630     |  | 76     
|Texas               |  | 108,861         |  | 52,893                |  | 5,590   |  | 4,684  
|                    |  |                 |  |                       |  |         |  |        
|Total               |  | 396,655         |  | 225,913               |  | 378,991 |  | 181,573
|                    |  |                 |  |                       |  |         |  |        

---

|(1) | Less than 10% of total net undeveloped acres are covered by leases that expire from 2005 through 2007.
|--- | ------------------------------------------------------------------------------------------------------



Drilling Activities



Information with regard to our drilling activities during the years ended December 31, 2004, 2003 and 2002 is set forth below:



|                  |  |                         |  |       |  |       |  |       |  |       |  |     
|----------------- |  | ----------------------- |  | ----- |  | ----- |  | ----- |  | ----- |  | ----
|                  |  | Year Ended December 31,
|                  |  | 2004                    |  | 2003  |  | 2002 
|                  |  | Gross                   |  | Net   |  | Gross |  | Net   |  | Gross |  | Net 
|Exploratory Wells |  |                         |  |       |  |       |  |       |  |       |  |     
|Oil               |  | 13.0                    |  | 13.0  |  |      |  |      |  |      |  |    
|Gas               |  | 5.0                     |  | 2.0   |  | 7.0   |  | 2.2   |  |      |  |    
|Dry               |  | 10.0                    |  | 5.3   |  | 3.0   |  | 1.0   |  |      |  |    
|                  |  |                         |  |       |  |       |  |       |  |       |  |     
|                  |  | 28.0                    |  | 20.3  |  | 10.0  |  | 3.2   |  |      |  |    
|                  |  |                         |  |       |  |       |  |       |  |       |  |     
|Development Wells |  |                         |  |       |  |       |  |       |  |       |  |     
|Oil               |  | 65.0                    |  | 64.2  |  | 121.0 |  | 121.0 |  | 79.0  |  | 77.4
|Gas               |  | 52.0                    |  | 22.4  |  | 32.0  |  | 14.0  |  |      |  |    
|Dry               |  | 1.0                     |  | 1.0   |  | 1.0   |  | 0.4   |  | 1.0   |  | 0.5 
|                  |  |                         |  |       |  |       |  |       |  |       |  |     
|                  |  | 118.0                   |  | 87.6  |  | 154.0 |  | 135.4 |  | 80.0  |  | 77.9
|                  |  |                         |  |       |  |       |  |       |  |       |  |     
|                  |  | 146.0                   |  | 107.9 |  | 164.0 |  | 138.6 |  | 80.0  |  | 77.9
|                  |  |                         |  |       |  |       |  |       |  |       |  |     



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At December 31, 2004 there were 13 development wells (4.7 net) and 6 exploratory wells (5.4 net) in progress.



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                                 
|Lompoc        |  | Santa Barbara County, California   |  | 3,728                                 
|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.



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



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regulations can result in substantial penalties. The regulatory burden on the oil and gas industry increases our cost of doing business and, consequently, affects our
profitability. However, we do not believe that we are affected in a significantly different manner by these laws and regulations than are our competitors. Due to the myriad 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, 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 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. The MMS 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.



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



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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, 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.



We estimate our 2005
cash expenditures related to plugging, abandonment and remediation will be approximately $4.3 million. Due to the long life of our onshore California reserve base we do not expect our cash outlays for such expenditures for these properties will
increase significantly in the next several years. Although our offshore California properties have a shorter reserve life, third parties have retained the majority of the obligations for abandoning these properties.



In connection with the sale of certain properties offshore California in December 2004
we retained the responsibility for certain abandonment costs, including removing, dismantling and disposing of the existing offshore platforms. The present value of such abandonment costs, $35.0 million ($62.5 million undiscounted), are included in
our asset retirement obligation as reflected on our consolidated balance sheet. In addition, we agreed to guarantee the performance of the purchaser with respect to the remaining abandonment obligations related to the properties (approximately $44
million).



Employees



As of February 28, 2005 we had 696 full-time employees, 410 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.



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 negative



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impact 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.
| | - |  | -------------------------



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 operations and cash flows.



The majority of our oil production in California is dedicated to two customers and as a result, our credit exposure to those customers is significant.



We have entered into oil marketing arrangements with Plains All
American Pipeline, L.P., or PAA, and with ConocoPhillips under which PAA or ConocoPhillips purchase the majority of our net oil production in California. We generally do not require letters of credit or other collateral from PAA or from
ConocoPhillips to support these trade receivables. Accordingly, a material adverse change in PAAs or ConocoPhillipss financial condition could adversely impact our ability to collect the applicable receivables, and thereby affect our
financial condition.



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If we are unable to replace the reserves that we have produced, our reserves and revenues will decline.



Our future success depends on our ability to find, develop and
acquire additional oil and gas reserves that are economically recoverable which, in itself, is dependent on oil and gas prices. Without continued successful exploitation, acquisition or exploration activities, our reserves and revenues will decline
as a result of our current reserves being depleted by production. We 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 dates 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;
| | - |  | ------------------------------------------------------------



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| |  |  | assumptions concerning future oil and gas prices; and
| | - |  | -----------------------------------------------------



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



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



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



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



| |  |  | the production and operating costs incurred; and
| | - |  | ------------------------------------------------



| |  |  | the amount and timing of future development expenditures.
| | - |  | ---------------------------------------------------------



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



The discounted future net revenues included in this 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 subject to local conditions more 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 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 California oil production 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 grades of oil.



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Operating hazards, natural disasters or other interruptions of our operations could result in potential
liabilities, which may not be fully covered by our insurance.



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



| |  |  | well blowouts;
| | - |  | --------------



| |  |  | cratering;
| | - |  | ----------



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



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



| |  |  | fires;
| | - |  | ------



| |  |  | 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.



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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 broad 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, or their interpretations, could be changed, and any changes could increase costs of compliance and costs of operating drilling
equipment or significantly limit drilling activity.



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. 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 of our onshore California fields 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 coastal California gnatcatcher, which is a type of bird designated as threatened under the Federal 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



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existing or future laws, rules and guidelines could prohibit or limit our operations and our planned activities for this property.



Our acquisition strategy could fail or present unanticipated problems for our
business in the future, which could adversely affect our ability to make acquisitions or realize anticipated benefits of those acquisitions.



Our growth strategy may include acquiring oil and gas businesses and properties. We 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 maximum 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
maximum 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 maximum 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. We do not have key man insurance.



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Under our tax allocation agreement with our former parent, Plains Resources Inc., 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 it may prevent a change in control of us.



Prior to December 18, 2002 we were a wholly owned subsidiary of Plains Resources Inc. (Plains Resources, now known as Vulcan Energy Corporation). 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. 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.



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 obtain 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 negatively affected by stock appreciation rights charges.



Stock appreciation rights (SARs) 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. Under current accounting rules, 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



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decreased, the stock appreciation right accounting charge would decrease, resulting in increased net income for us. For the year ended December 31, 2004 we recognized
$35.5 million of SAR expense. Based on the number of stock appreciation rights outstanding at December 31, 2004, a $0.25 change in the price of our common stock would result in a change of $0.6 million in our net income.



In December 2004 the FASB issued SFAS No. 123R (revised 2004), Share-Based
Payment (SFAS 123(R)). SFAS 123(R) requires that the compensation cost relating to share-based payment transactions be recognized in financial statements effective with the third quarter of 2005, Under SFAS No. 123(R) our SARs will
be remeasured to fair value each reporting period. We have not determined how the new method of valuing stock-based compensation as prescribed in SFAS 123(R) will be applied to valuing stock-based awards and the impact the recognition of
compensation expense related to such awards will have on our financial statements.



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 acquisitions of 3TEC and Nuevo, goodwill totaled $170.5 million and represented 6% of our total assets at December 31, 2004.



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.



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.



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 28, 2005 and their business experience for the last five years.



Directors



James C. Flores, age 45,
Chairman of the Board, Chief Executive Officer and a Director since September 2002 and President since March 2004.    He has also been a director of Nabors Industries Ltd. since January 2005. He was Chairman of the Board from
December 2002 to July 2004 of Plains former parent, Plains Resources. He was Chairman of the Board and Chief Executive Officer of Plains



29



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Resources from May 2001 to December 2002. He was Co-founder as well as Chairman, Vice Chairman and Chief Executive Officer at various times from 1992 until January
2001 of Ocean Energy, Inc., an oil and gas company. From January 2001 to May 2001 Mr. Flores managed various private investments.



Isaac Arnold, Jr., age 69, Director since May 2004.    He also was a director of Nuevo from 1990 to May 2004. He has been a
director of Legacy Holding Company since 1989 and Legacy Trust Company since 1997. He has been a director of Cullen Center Bank & Trust since its inception in 1969 and is a director of Cullen/Frost Bankers, Inc. Mr. Arnold is a trustee of the
Museum of Fine Arts and The Texas Heart Institute. Mr. Arnold received his B.B.A. from the University of Houston in 1959.



Alan R. Buckwalter, III, age 58, 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 boards of Service Corporation International, the Texas Medical Center, Greater Houston Area Red Cross, University of St. Thomas and St. Lukes Hospital System. He sits on the Audit Committee
and is Chairman of the Compensation Committee for Service Corporation International.



Jerry L. Dees, age 65, 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 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 64, 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.



Robert L. Gerry III, age 67, Director since May
2004.    He was also a director of Nuevo from 1990 to May 2004. He has been chairman and chief executive officer of Vaalco Energy, Inc., a publicly traded independent oil and gas company which does not compete with Plains,
since 1997. From 1994 to 1997, Mr. Gerry was vice chairman of Nuevo. Prior to that, he was president and chief operating officer of Nuevo since its formation in 1990. Mr. Gerry also currently serves as a trustee of Texas Childrens Hospital.



John H. Lollar, age 66, 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 Chairman 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.



30



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Executive Officers



Stephen A. Thorington, age 49, Executive Vice President and Chief Financial Officer since September 2002.    He was also Plains
Resources Executive Vice President and Chief Financial Officer from February 2003 to June 2004. 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.



John F. Wombwell, age 43, Executive Vice President, General Counsel
and Secretary since September 2003.    He was also Plains Resources Executive Vice President, General Counsel, and Secretary from September 2003 to June 2004. He was previously a Senior Executive Officer with two New
York Stock Exchange traded companies, serving as General Counsel of ExpressJet Holdings, Inc. from April 2002 until September 2003 and prior to joining ExpressJet, Mr. Wombwell was General Counsel of Integrated Electrical Services, Inc. from January
1998 to April 2002. Prior to that time, Mr. Wombwell was a partner at the national law firm of Andrews Kurth LLP with a practice focused on representing public companies with respect to corporate and securities matters.



Thomas M. Gladney, age 52, Executive Vice PresidentExploration and Production
since June 2003.    He was Plains 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.



Item 5.Market For Registrants Common Stock, Related Stockholder Matters And Issuer Purchases Of Equity Securities



Price Range of Common stock



Our common stock is listed on the New York Stock Exchange under the symbol PXP. The following table sets forth the range
of high and low closing sales prices for our common stock as reported on the New York Stock Exchange Composite Tape for the periods indicated below:



|            |  |      |       |     |   |      
|----------- |  | ---- | ----- | --- | - | -----
|            |  | High |       | Low
|2004        |  |      |       |     |   |      
|1st Quarter |  | $    | 18.64 |     | $ | 14.87
|2nd Quarter |  |      | 20.53 |     |   | 17.19
|3rd Quarter |  |      | 23.86 |     |   | 18.58
|4th Quarter |  |      | 28.03 |     |   | 23.81
|2003        |  |      |       |     |   |      
|1st Quarter |  | $    | 10.36 |     | $ | 8.25 
|2nd Quarter |  |      | 11.15 |     |   | 8.11 
|3rd Quarter |  |      | 12.85 |     |   | 10.32
|4th Quarter |  |      | 15.68 |     |   | 12.90



At December 31, 2004 we had
approximately 1,542 shareholders of record.



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. As discussed in Item 7. Managements Discussion and Analysis of Financial Condition and Results of OperationsFinancing Activities, our credit facility and the indentures relating to our 8.75% and 7.125% notes restrict our
ability to pay cash dividends.



31



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##### 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,                             |         
|                                                                         |  | 2004(1)                                             |          |   | 2003(2) |   |         | 2002 |  |   | 2001    |   |  | 2000 |        
|                                                                         |  | (In thousands of dollars, except per share amounts) |         
|Revenues                                                                 |  | $                                                   | 671,706  |   |         | $ | 304,090 |      |  | $ | 188,563 |   |  | $    | 204,139 |   |  | $ | 142,451 |  
|                                                                         |  |                                                     |          |   |         |   |         |      |  |   |         |   |  |      |         |   |  |   |         |  
|Costs and Expenses                                                       |  |                                                     |          |   |         |   |         |      |  |   |         |   |  |      |         |   |  |   |         |  
|Production costs                                                         |  |                                                     | 223,080  |   |         |   | 104,819 |      |  |   | 78,451  |   |  |      | 63,795  |   |  |   | 56,228  |  
|General and administrative                                               |  |                                                     |          |   |         |   |         |      |  |   |         |   |  |      |         |   |  |   |         |  
|G&A excluding items below                                                |  |                                                     | 35,394   |   |         |   | 18,694  |      |  |   | 10,756  |   |  |      | 10,210  |   |  |   | 6,308   |  
|Stock appreciation rights                                                |  |                                                     | 35,464   |   |         |   | 18,010  |      |  |   | 3,653   |   |  |      |        |   |  |   |        |  
|Other stock based compensation                                           |  |                                                     | 8,092    |   |         |   | 1,190   |      |  |   |        |   |  |      |        |   |  |   |        |  
|Merger related costs                                                     |  |                                                     | 6,247    |   |         |   | 5,264   |      |  |   |        |   |  |      |        |   |  |   |        |  
|Spin-off costs                                                           |  |                                                     |         |   |         |   |        |      |  |   | 777     |   |  |      |        |   |  |   |        |  
|Provision for legal and regulatory settlements                           |  |                                                     | 6,845    |   |         |   |        |      |  |   |        |   |  |      |        |   |  |   |        |  
|Depreciation, depletion, amortization and accretion                      |  |                                                     | 147,985  |   |         |   | 52,484  |      |  |   | 30,359  |   |  |      | 24,105  |   |  |   | 18,859  |  
|                                                                         |  |                                                     |          |   |         |   |         |      |  |   |         |   |  |      |         |   |  |   |         |  
|                                                                         |  |                                                     | 463,107  |   |         |   | 200,461 |      |  |   | 123,996 |   |  |      | 98,110  |   |  |   | 81,395  |  
|                                                                         |  |                                                     |          |   |         |   |         |      |  |   |         |   |  |      |         |   |  |   |         |  
|Income from Operations                                                   |  |                                                     | 208,599  |   |         |   | 103,629 |      |  |   | 64,567  |   |  |      | 106,029 |   |  |   | 61,056  |  
|Other Income (Expense)                                                   |  |                                                     |          |   |         |   |         |      |  |   |         |   |  |      |         |   |  |   |         |  
|Interest expense                                                         |  |                                                     | (37,294  | ) |         |   | (23,778 | )    |  |   | (19,377 | ) |  |      | (17,411 | ) |  |   | (15,885 | )
|Gain (loss) on mark-to-market derivative contracts (3)                   |  |                                                     | (150,314 | ) |         |   | 847     |      |  |   |        |   |  |      |        |   |  |   |        |  
|Interest and other income (expense)                                      |  |                                                     | 723      |   |         |   | (159    | )    |  |   | 174     |   |  |      | 463     |   |  |   | 343     |  
|Extinguishment of debt                                                   |  |                                                     | (19,691  | ) |         |   |        |      |  |   |        |   |  |      |        |   |  |   |        |  
|Expenses of terminated public equity offering                            |  |                                                     |         |   |         |   |        |      |  |   | (2,395  | ) |  |      |        |   |  |   |        |  
|                                                                         |  |                                                     |          |   |         |   |         |      |  |   |         |   |  |      |         |   |  |   |         |  
|Income Before Income Taxes and Cumulative Effect of Accounting Change    |  |                                                     | 2,023    |   |         |   | 80,539  |      |  |   | 42,969  |   |  |      | 89,081  |   |  |   | 45,514  |  
|Income tax (expense) benefit                                             |  |                                                     |          |   |         |   |         |      |  |   |         |   |  |      |         |   |  |   |         |  
|Current                                                                  |  |                                                     | (375     | ) |         |   | (1,224  | )    |  |   | (6,353  | ) |  |      | (6,014  | ) |  |   | (2,431  | )
|Deferred                                                                 |  |                                                     | 7,192    |   |         |   | (32,228 | )    |  |   | (10,379 | ) |  |      | (28,374 | ) |  |   | (14,334 | )
|                                                                         |  |                                                     |          |   |         |   |         |      |  |   |         |   |  |      |         |   |  |   |         |  
|Income Before Cumulative Effect of Accounting Changes                    |  |                                                     | 8,840    |   |         |   | 47,087  |      |  |   | 26,237  |   |  |      | 54,693  |   |  |   | 28,749  |  
|Cumulative effect of accounting change, net of tax (expense) benefit (4) |  |                                                     |         |   |         |   | 12,324  |      |  |   |        |   |  |      | (1,522  | ) |  |   |        |  
|                                                                         |  |                                                     |          |   |         |   |         |      |  |   |         |   |  |      |         |   |  |   |         |  
|Net Income                                                               |  | $                                                   | 8,840    |   |         | $ | 59,411  |      |  | $ | 26,237  |   |  | $    | 53,171  |   |  | $ | 28,749  |  
|                                                                         |  |                                                     |          |   |         |   |         |      |  |   |         |   |  |      |         |   |  |   |         |  
|Earnings Per Share                                                       |  |                                                     |          |   |         |   |         |      |  |   |         |   |  |      |         |   |  |   |         |  
|Basic and Diluted                                                        |  |                                                     |          |   |         |   |         |      |  |   |         |   |  |      |         |   |  |   |         |  
|Income before cumulative effect of accounting change                     |  | $                                                   | 0.14     |   |         | $ | 1.41    |      |  | $ | 1.08    |   |  | $    | 2.26    |   |  | $ | 1.19    |  
|Cumulative effect of accounting change                                   |  |                                                     |         |   |         |   | 0.37    |      |  |   |        |   |  |      | (0.06   | ) |  |   |        |  
|                                                                         |  |                                                     |          |   |         |   |         |      |  |   |         |   |  |      |         |   |  |   |         |  
|Net income                                                               |  | $                                                   | 0.14     |   |         | $ | 1.78    |      |  | $ | 1.08    |   |  | $    | 2.20    |   |  | $ | 1.19    |  
|                                                                         |  |                                                     |          |   |         |   |         |      |  |   |         |   |  |      |         |   |  |   |         |  
|Weighted Average Common Shares Outstanding                               |  |                                                     |          |   |         |   |         |      |  |   |         |   |  |      |         |   |  |   |         |  
|Basic                                                                    |  |                                                     | 63,542   |   |         |   | 33,321  |      |  |   | 24,193  |   |  |      | 24,200  |   |  |   | 24,200  |  
|Diluted                                                                  |  |                                                     | 64,014   |   |         |   | 33,469  |      |  |   | 24,201  |   |  |      | 24,200  |   |  |   | 24,200  |  

---

|(1) |  | Reflects acquisition of Nuevo effective May 14, 2005.
|--- |  | -----------------------------------------------------

|(2) |  | Reflects acquisition of 3TEC effective June 1, 2003.
|--- |  | ----------------------------------------------------

|(3) |  | During 2004 we recognized a pre-tax loss of $150.3 million from derivatives that do not qualify for hedge accounting consisting of a mark-to-market loss of $118.1 million and cash settlements
of $32.2 million. We recognized a mark-to-market gain of $0.9 million in 2003.
|--- |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|(4) |  | 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





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|                                                    |  |                           |          |   |      |   |          |      |  |   |         |   |  |      |          |   |  |   |         |  
|--------------------------------------------------- |  | ------------------------- | -------- | - | ---- | - | -------- | ---- |  | - | ------- | - |  | ---- | -------- | - |  | - | ------- | -
|                                                    |  | Year Ended December 31,   |         
|                                                    |  | 2004                      |          |   | 2003 |   |          | 2002 |  |   | 2001    |   |  | 2000 |         
|                                                    |  | (In thousands of dollars) |         
|Cash Flow Data                                      |  |                           |          |   |      |   |          |      |  |   |         |   |  |      |          |   |  |   |         |  
|Net cash provided by operating activities           |  | $                         | 363,219  |   |      | $ | 118,278  |      |  | $ | 78,826  |   |  | $    | 116,808  |   |  | $ | 79,464  |  
|Net cash (used in) provided by investing activities |  |                           | 5,414    |   |      |   | (368,710 | )    |  |   | (64,158 | ) |  |      | (125,880 | ) |  |   | (70,871 | )
|Net cash provided by (used in) financing activities |  |                           | (368,465 | ) |      |   | 250,781  |      |  |   | (13,653 | ) |  |      | 8,549    |   |  |   | (13,132 | )



|                                               |  |                           |           |   |      |   |           |      |  |   |         |   |      |   |         |  |   |        
|---------------------------------------------- |  | ------------------------- | --------- | - | ---- | - | --------- | ---- |  | - | ------- | - | ---- | - | ------- |  | - | -------
|                                               |  | As of December 31,       
|                                               |  | 2004                      |           |   | 2003 |   |           | 2002 |  |   | 2001    |   | 2000
|                                               |  | (In thousands of dollars)
|Balance Sheet Data                             |  |                           |           |   |      |   |           |      |  |   |         |   |      |   |         |  |   |        
|Assets                                         |  |                           |           |   |      |   |           |      |  |   |         |   |      |   |         |  |   |        
|Cash and cash equivalents                      |  | $                         | 1,545     |   |      | $ | 1,377     |      |  | $ | 1,028   |   |      | $ | 13      |  | $ | 536    
|Other current assets                           |  |                           | 256,622   |   |      |   | 87,104    |      |  |   | 47,854  |   |      |   | 42,798  |  |   | 36,916 
|Property and equipment, net                    |  |                           | 2,171,089 |   |      |   | 956,895   |      |  |   | 493,212 |   |      |   | 455,117 |  |   | 353,344
|Goodwill                                       |  |                           | 170,467   |   |      |   | 147,251   |      |  |   |        |   |      |   |        |  |   |       
|Other assets                                   |  |                           | 33,522    |   |      |   | 19,641    |      |  |   | 18,929  |   |      |   | 18,827  |  |   | 10,239 
|                                               |  |                           |           |   |      |   |           |      |  |   |         |   |      |   |         |  |   |        
|                                               |  | $                         | 2,633,245 |   |      | $ | 1,212,268 |      |  | $ | 561,023 |   |      | $ | 516,755 |  | $ | 401,035
|                                               |  |                           |           |   |      |   |           |      |  |   |         |   |      |   |         |  |   |        
|Liabilities and Stockholders Equity           |  |                           |           |   |      |   |           |      |  |   |         |   |      |   |         |  |   |        
|Current liabilities                            |  | $                         | 426,395   |   |      | $ | 155,086   |      |  | $ | 86,175  |   |      | $ | 50,648  |  | $ | 44,313 
|Long-term debt and payable to Plains Resources |  |                           | 635,468   |   |      |   | 487,906   |      |  |   | 233,166 |   |      |   | 236,183 |  |   | 226,529
|Other long-term liabilities                    |  |                           | 381,524   |   |      |   | 65,429    |      |  |   | 6,303   |   |      |   | 1,413   |  |   |       
|Deferred income taxes                          |  |                           | 319,483   |   |      |   | 149,591   |      |  |   | 61,559  |   |      |   | 48,424  |  |   | 19,161 
|Stockholders equity/combined owners equity   |  |                           |           |   |      |   |           |      |  |   |         |   |      |   |         |  |   |        
|Accumulated other comprehensive income (loss)  |  |                           | (123,874  | ) |      |   | (40,439   | )    |  |   | (12,858 | ) |      |   | 15,884  |  |   |       
|Other                                          |  |                           | 994,249   |   |      |   | 394,695   |      |  |   | 186,678 |   |      |   | 164,203 |  |   | 111,032
|                                               |  |                           |           |   |      |   |           |      |  |   |         |   |      |   |         |  |   |        
|                                               |  | $                         | 2,633,245 |   |      | $ | 1,212,268 |      |  | $ | 561,023 |   |      | $ | 516,755 |  | $ | 401,035
|                                               |  |                           |           |   |      |   |           |      |  |   |         |   |      |   |         |  |   |        





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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.



Company Overview



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



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



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



| |  |  | the Gulf Coast Basin onshore and offshore Louisiana, including the Gulf of Mexico;
| | - |  | ----------------------------------------------------------------------------------



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



| |  |  | the Val Verde portion of the greater Permian Basin in Texas.
| | - |  | ------------------------------------------------------------



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 have historically hedged portions of our oil and gas production to manage our exposure to commodity price risk.



Our primary sources of liquidity are cash generated from our operations and our revolving credit facility. At December 31, 2004 we had
approximately $383 million of availability under our revolving credit facility. We have a capital budget for 2005 of approximately $375 million. 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. In addition, the majority of our capital expenditures are
discretionary and could be curtailed if our cash flows declined from expected levels.



Our cash flows depend on many factors, including the price of oil and gas, the success of our acquisition and drilling activities and the operational performance of our producing properties. We hedge to limit our commodity
price exposure. The level of hedging activity depends on our view of market conditions, available hedge prices and our operating strategy. Under our hedging program, we have typically hedged up to 70%-75% of our production for the current year, up
to 40%-50% of our production for the next year and up to 25%-40% of our production for the following year. Our hedging activities mitigate our exposure to price declines and allow us the flexibility to continue to execute our capital plan even if
prices decline during the period our hedges are in place. Hedging also prevents us from receiving the full advantage of increases in oil or gas prices above the maximum 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 maximum 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
maximum 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.



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Completion of our acquisition of Nuevo had a significant impact on our company. We now have a large proved reserve
base that is 68% proved developed, a significantly improved balance sheet and an attractive growth profile. The combined company is expected to generate significant cash flow that will be available for debt reduction and future growth opportunities.



Acquisitions and Dispositions



On May 14, 2004 we acquired Nuevo in a stock-for-stock transaction. We accounted for
the acquisition of Nuevo as a purchase effective May 14, 2004. See Items 1 and 2. Business and Properties. Acquisition of Nuevo Energy Company. In connection with our acquisition of Nuevo we have completed a series of transactions to
refinance a portion of our and all of Nuevos outstanding debt (the Recapitalization Transactions). See Financing Activities.On June 4, 2003, we acquired 3TEC for a combination of cash and common stock. We accounted for the
acquisition of 3TEC as a purchase effective June 1, 2003. See Items 1 and 2. Business and Properties. Acquisition of 3TEC Energy Corporation.



We periodically evaluate and from time to time have elected to sell certain of our mature producing properties that we consider to be nonstrategic. Such sales
enable us to focus on our core properties, maintain financial flexibility and redeploy the proceeds therefrom to activities that we believe potentially have a higher financial return. In December 2004, we completed the sale of certain properties
located offshore California and onshore South Texas, New Mexico, and South Louisiana. These divestments were conducted via negotiated and auction transactions and we received net proceeds of approximately $153 million. In a series of transactions in
the first and second quarters of 2004 we sold our interests in certain non-core producing properties in New Mexico, Texas, Mississippi, Louisiana, and Illinois for proceeds of approximately $28 million. 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 million. See Items 1
and 2. Business and Properties. Description of PropertiesProperty Divestments.



Hedge Restructuring



In September 2004 we
entered into new oil price collars for the period 2005 through 2008 and eliminated approximately 80% of our 2005 fixed price crude oil swaps. By converting fixed price swaps to collars we retained downside protection while potentially capturing
significantly higher cash flow. In addition, we now have certainty of an attractive price range for a meaningful amount of our production for the next several years. Specifically, we exchanged existing 2005 oil price swaps with respect to 22,000
barrels of oil per day at an average price of $24.25 for new oil price collars relating to 22,000 barrels of oil per day during the period 2005 through 2008 that have a floor price of $25.00 and an average ceiling price of $34.76. Our only remaining
2005 crude oil swaps involve 13,000 barrels of oil per day in the first quarter and 10,000 barrels of oil per day in the second quarter, at fixed prices averaging $25.82 and $25.80, respectively.



The restructured collars as well as certain other commodity derivative contracts to
which we are a party, do not qualify for hedge accounting. Consequently, these contracts are marked-to-market each quarter with changes in fair value recognized currently as a derivative gain or loss on the income statement. For example, if the
forward curve for oil prices is higher at the end of an accounting period than at the beginning of the period a derivative fair value loss will be recorded. Conversely, if the forward curve for oil prices declines during the accounting period a fair
value gain will be recorded. As a consequence of this accounting treatment we expect that there will be significant volatilty in our reported earnings. Cash flow is only impacted to the extent the actual settlements under the contracts result in
making or receiving a payment from the counterparty.



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During 2004 we recognized a pre-tax loss of $150.3 million from derivatives that do not qualify for hedge
accounting. The foregoing amount consists of mark-to-market losses of $118.1 million and cash settlements of $32.2 million.



Price Differentials



Our realized wellhead oil and gas prices are lower than the NYMEX index level as a result of location and quality differentials. A substantial portion of our oil
and gas reserves are located in California and approximately 55% of our production is attributable to heavy crude (generally 21 degree API gravity crude oil or lower). Our heavy crude is primarily sold to ConocoPhilips under a 15 year contract which
expires on December 31, 2014. This contract provides for pricing based on a fixed percentage of the NYMEX crude oil price for each type of crude oil that we produce and deliver to ConocoPhillips in California. This fixed percentage may be
renegotiated every two years, with the current fixed percentage rates eligible for renegotiation effective at the end of 2005. We are currently receiving approximately 80% of the NYMEX index price for crude oil sold under the ConocoPhillips
contract, representing approximately 46% of our total crude oil production.



Approximately 44% of our crude oil production is sold through Plains All American Pipeline, L.P. (PAA) with 71% sold under contracts that provide for NYMEX less a fixed price differential (currently averaging NYMEX less $4.80)
and 29% sold under contracts that provide for monthly field posted prices. These contracts expire at various times from January 1, 2006 through 2008. The marketing agreement with PAA provides that PAA will purchase for resale at market prices
certain of our oil production for which PAA charges a marketing fee of either $0.20 or $0.15 per barrel based upon the contract the barrels are resold under.



The remaining 10% of our crude oil production is sold to others under contracts tied to monthly field posted prices. All production volumes in the foregoing
discussion are based on the Companys fourth quarter 2004 production volumes, pro forma as if the property sales completed in the fourth quarter were effective as of October 1, 2004.



The market price for California crude oil differs from the established market indices in the U.S., due principally to the higher
transportation and refining costs associated with heavy oil. While the contracts providing for NYMEX based pricing do not reduce our exposure to price volatility, they do help manage the risk of widening basis differentials between the NYMEX index
price and the field posted prices for our California oil production. During 2004, the basis differentials for California crude oil widened significantly from past levels and the prices received by the Company under NYMEX based crude oil contracts
were favorable relative to the current market prices. There can be no assurance that the Company will continue to receive the favorable differentials when the price differentials are renegotiated or that the market differentials will not decrease
below our contracted prices.



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. Approximately 84% of our gas production is sold monthly based on industry recognized, published index pricing. The
remaining 16% is priced daily on the spot market. Fluctuations between the two pricing mechanisms can significantly impact the overall differential to the Henry Hub.



2004 Results Overview



Primarily as a result of the $150.3 million derivative mark-to-market loss, we reported net income of $8.8 million, or $0.14 per diluted share for 2004 compared to
net income of $59.4 million, or $1.78 per diluted share for 2003. Net income includes the effect of the properties in our acquisition of Nuevo, which are included in our results effective May 14, 2004, and the effect of the properties in our



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acquisition of 3TEC which are included in our results effective June 1, 2003. Net income for 2003 includes a non-cash, after-tax $12.3 million credit related to the
adoption of Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations.



Income from operations increased to $208.6 million in 2004 from $103.6 million in 2003. The improvement is primarily attributable to higher oil and gas sales as a
result of increased sales volumes due to the Nuevo and 3TEC properties and increased oil and gas prices. The increase in income from operations was offset by the derivative mark-to-market loss, debt extinguishment costs, expenses related to stock
appreciation rights and higher interest costs related to the Nuevo and 3TEC acquisitions.



General



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 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.



Our oil and gas production expenses include salaries and benefits of personnel involved in production activities, steam gas costs,
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 (G&A) consist primarily of salaries
and related benefits of administrative personnel, office rent, systems costs and other administrative costs.





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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, |        
|                                      |  | 2004                    |         |   | 2004 vs2003 |     |   | 2003 |   |        | 2004 vs2002 |  |     | 2002 | 
|Sales Volumes                         |  |                         |         |   |             |     |   |      |   |        |             |  |     |      |  |   |        |  
|Oil and liquids (MBbls)               |  |                         | 16,441  |   |             | 177 | % |      |   | 9,267  |             |  | 106 | %    |  |   | 8,783  |  
|Gas (MMcf)                            |  |                         | 38,590  |   |             | 212 | % |      |   | 18,195 |             |  | 541 | %    |  |   | 3,362  |  
|MBOE                                  |  |                         | 22,872  |   |             | 186 | % |      |   | 12,300 |             |  | 132 | %    |  |   | 9,343  |  
|Daily Average Sales Volumes           |  |                         |         |   |             |     |   |      |   |        |             |  |     |      |  |   |        |  
|Oil and liquids (Bbls/d)              |  |                         | 44,920  |   |             | 177 | % |      |   | 25,389 |             |  | 106 | %    |  |   | 24,062 |  
|Gas (Mcfpd)                           |  |                         | 105,436 |   |             | 212 | % |      |   | 49,849 |             |  | 541 | %    |  |   | 9,211  |  
|BOEPD                                 |  |                         | 62,492  |   |             | 185 | % |      |   | 33,699 |             |  | 132 | %    |  |   | 25,597 |  
|Unit Economics (in dollars)           |  |                         |         |   |             |     |   |      |   |        |             |  |     |      |  |   |        |  
|Average Oil Sales Price ($/Bbl)       |  |                         |         |   |             |     |   |      |   |        |             |  |     |      |  |   |        |  
|Net realized price before hedging     |  | $                       | 36.12   |   |             | 134 | % |      | $ | 26.92  |             |  | 122 | %    |  | $ | 22.04  |  
|Hedging revenue (expense) (1)         |  |                         | (8.87   | ) |             | 160 | % |      |   | (5.54  | )           |  | 313 | %    |  |   | (1.77  | )
|                                      |  |                         |         |   |             |     |   |      |   |        |             |  |     |      |  |   |        |  
|Net realized price                    |  | $                       | 27.25   |   |             | 127 | % |      | $ | 21.38  |             |  | 105 | %    |  | $ | 20.27  |  
|                                      |  |                         |         |   |             |     |   |      |   |        |             |  |     |      |  |   |        |  
|Average Gas Sales Price ($/Mcf)       |  |                         |         |   |             |     |   |      |   |        |             |  |     |      |  |   |        |  
|Net realized price before hedging     |  | $                       | 5.90    |   |             | 118 | % |      | $ | 5.01   |             |  | 164 | %    |  | $ | 3.06   |  
|Hedging revenue (expense) (1)         |  |                         | (0.16   | ) |             | -21 | % |      |   | 0.76   |             |  |     |      |  |   |       |  
|                                      |  |                         |         |   |             |     |   |      |   |        |             |  |     |      |  |   |        |  
|Net realized price                    |  | $                       | 5.74    |   |             | 99  | % |      | $ | 5.77   |             |  | 189 | %    |  | $ | 3.06   |  
|                                      |  |                         |         |   |             |     |   |      |   |        |             |  |     |      |  |   |        |  
|Average Realized Price per BOE        |  | $                       | 29.27   |   |             | 119 | % |      | $ | 24.65  |             |  | 122 | %    |  | $ | 20.16  |  
|Costs and Expenses per BOE            |  |                         |         |   |             |     |   |      |   |        |             |  |     |      |  |   |        |  
|Production costs                      |  |                         |         |   |             |     |   |      |   |        |             |  |     |      |  |   |        |  
|Lease operating expenses              |  |                         | 5.36    |   |             | 99  | % |      |   | 5.44   |             |  | 98  | %    |  |   | 5.57   |  
|Steam gas costs                       |  |                         | 1.77    |   |             | 770 | % |      |   | 0.23   |             |  | 121 | %    |  |   | 0.19   |  
|Electricity                           |  |                         | 1.32    |   |             | 73  | % |      |   | 1.82   |             |  | 83  | %    |  |   | 2.18   |  
|Production and ad valorem taxes       |  |                         | 0.98    |   |             | 120 | % |      |   | 0.82   |             |  | 178 | %    |  |   | 0.46   |  
|Gathering and transportation          |  |                         | 0.33    |   |             | 157 | % |      |   | 0.21   |             |  |     |      |  |   |       |  
|G&A                                   |  |                         |         |   |             |     |   |      |   |        |             |  |     |      |  |   |        |  
|G&A excluding items below             |  |                         | 1.55    |   |             | 102 | % |      |   | 1.52   |             |  | 132 | %    |  |   | 1.15   |  
|Stock appreciation rights             |  |                         | 1.55    |   |             | 106 | % |      |   | 1.46   |             |  | 374 | %    |  |   | 0.39   |  
|Other stock based compensation        |  |                         | 0.35    |   |             | 362 | % |      |   | 0.10   |             |  |     |      |  |   |       |  
|Merger related costs                  |  |                         | 0.27    |   |             | 63  | % |      |   | 0.43   |             |  |     |      |  |   |       |  
|Spinoff related costs                 |  |                         |        |   |             |     |   |      |   |       |             |  |     |      |  |   | 0.09   |  
|DD&A per BOE (oil and gas properties) |  |                         | 5.93    |   |             | 154 | % |      |   | 3.86   |             |  | 122 | %    |  |   | 3.17   |  

---

|(1) | Realized gains and losses on derivative instruments that are designated as hedges and qualify for hedge accounting are generally included in oil and gas revenues in the period the hedged
volumes are sold. However, in the case of the derivatives acquired in connection with our acquisitions of Nuevo and 3TEC, only cash settlements for changes in fair value subsequent to the acquisition date will be reflected in our oil and gas
revenues. Cash settlements for the liability existing at the merger date are reflected as the payment of a liability. Realized gains and losses on hedges that do not qualify for hedge accounting are recognized in gain (loss) on mark-to-market
derivative contracts on the income statement.
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



Oil sales
hedging expense for 2004 and 2003 does not include $3.75 per barrel and $(.05) per barrel, respectively, of cash settlement payments (receipts) for hedges assumed in connection with the Nuevo and 3TEC acquisitions. Gas hedging expense for 2004 and
2003 does not include $0.30 per Mcf and $0.74 per Mcf, respectively, with respect to such cash settlement payments.



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Comparison of Year Ended December 31, 2004 to Year Ended December 31, 2003



Oil and gas revenues.    Oil and gas revenues increased
$366.2 million, to $669.4 million for 2004 from $303.2 million for 2003. The increase is primarily due to increased production volumes attributable to the properties acquired from Nuevo and 3TEC and higher realized prices. Our average realized price
per BOE increased to $29.27 and our production increased to 22.9 MMBOE. Production attributable to the properties acquired from Nuevo was 9.6 MMBOE in 2004.



Oil revenues increased $250.0 million, to $448.1 million for 2004 from $198.1 million for 2003, reflecting higher realized prices ($54.5 million) and higher
production ($195.5 million). Our average realized price for oil increased $5.87, to $27.25 per Bbl for 2004 from $21.38 per Bbl for 2003. The increase is primarily attributable to an improvement in the NYMEX oil price, which averaged $41.43 per Bbl
in 2004 versus $30.99 per Bbl in 2003. Hedging had the effect of decreasing our average price per Bbl by $8.87 in 2004 compared to $5.54 per Bbl in 2003. Oil production increased to 16.4 MMBbls in 2004 from 9.3 MMBbls in 2003. Production
attributable to the properties acquired from Nuevo was 8.4 MMBbls in 2004.



Gas revenues increased $116.3 million, to $221.4 million in 2004 from $105.1 million in 2003. A 20.4 Bcf increase in production volumes, primarily from the properties acquired from Nuevo and 3TEC, accounted for a $117.0 million increase in
gas revenues. Our average realized price for gas decreased $0.03, to $5.74 per Mcf for 2004 from $5.77 per Mcf for 2003 reducing revenues by $0.7 million. In 2004 hedging revenues decreased our average price by $0.16 per Mcf while in 2003 hedging
revenues increased our average price by $0.76 per Mcf.



Lease
operating expenses.    Lease operating expenses (including steam gas costs and electricity) increased $101.1 million, to $193.2 million for 2004 from $92.1 million for 2003, primarily due to the properties acquired from Nuevo
which accounted for $98.7 million of the 2004 operating expenses. On a per unit basis, lease operating expenses increased to $8.45 per BOE in 2004 versus $7.49 per BOE in 2003. The per unit increase is primarily attributable to the steam gas costs
attributable to the properties acquired from Nuevo. Steam gas costs averaged $1.77 per BOE in 2004 versus $0.23 per BOE in 2003.



Production and ad valorem taxes.    Production and ad valorem taxes increased $12.2 million, to $22.3 million for 2004 from $10.1 million
for 2003 primarily due to the properties acquired from Nuevo and 3TEC and increased oil prices.



Gathering and transportation expenses.    Gathering and transportation expenses increased $5.0 million, to $7.6 million for 2004 from
$2.6 million for 2003 primarily due to the properties acquired from Nuevo and 3TEC.



General and administrative expense.    G&A expense, excluding amounts attributable to SARs other stock based compensation and merger related costs, increased $16.7 million, to $35.4 million for
2004 from $18.7 million for 2003. Audit and accounting consulting costs increased $1.5 million primarily reflecting increased audit costs and compliance with the Sarbanes-Oxley Act. The remainder of the increase is primarily a result of increased
costs resulting from the Nuevo and 3TEC acquisitions.



G&A expense
related to outstanding stock appreciation rights or SARs was $35.5 million and $18.0 million in 2004 and 2003, respectively. Accounting for SARs requires that we record an expense or credit for vested or deemed vested SARs depending on whether,
during the period, our stock price either rose or fell, respectively. Such expense in 2004 and 2003 reflects additional vesting of outstanding SARs as well as an increase in our stock price. Our stock price was $26.00 per share on December 31, 2004,
$15.39 per share on December 31, 2003 and $9.75 per share on December 31,



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2002. In 2004 and 2003 we made cash payments of $15.1 million and $2.1 million, respectively, for SARs that were exercised during the period.



G&A expense for 2004 and 2003 includes other stock based compensation costs of $8.1
million and $1.2 million, respectively, related to restricted stock and restricted stock unit grants. G&A expense for 2004 also includes $6.2 million of merger related expenses for the Nuevo acquisition and 2003 includes $5.3 million of merger
related expenses for the 3TEC acquisition. Merger related expenses primarily consist of severance and other compensation costs and accounting system integration and conversion expenses.



G&A expense does not include amounts capitalized as part of our acquisition, exploration and development activities. We
capitalized $16.2 million and $11.0 million of G&A expense in 2004 and 2003, respectively.



Provision for legal and regulatory settlements.    In the fourth quarter of 2004 we made a $6.8 million provision with respect to legal and regulatory matters, primarily related to leasehold ownership
matters and operations and permit compliance matters that arose during the fourth quarter.



Depreciation, depletion and amortization, or DD&A.    DD&A expense increased $89.6 million, to $139.4 million in 2004 from $49.8 million in 2003. Approximately $88.0 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 $5.93 per BOE in 2004 compared to $3.86 per BOE in 2003. The increase primarily reflects the
effect of the Nuevo acquisition.



Accretion
expense.    Accretion expense increased $6.0 million to $8.6 million in 2004 from $2.6 million in 2003. The increase is primarily attributable to the increase in asset retirement obligations related to the Nuevo acquisition.



Interest expense.    Interest expense
increased $13.5 million, to $37.3 million for 2004 from $23.8 million for 2003 primarily due to higher outstanding debt as a result of the Nuevo and 3TEC acquisitions. Interest expense does not include interest capitalized on oil and gas properties
not subject to amortization. We capitalized $7.0 million and $3.2 million of interest in 2004 and 2003, respectively.



Debt extinguishment costs.    In connection with the retirement of the debt assumed in the acquisition of Nuevo we recorded $19.7 million
of debt extinguishment consisting primarily of a $6.6 million loss on the repurchase of all $150 million of Nuevos outstanding 9 3/8% Senior Subordinated Notes and a $13.1 million loss on redemption of all outstanding $118 million aggregate
principal amount of Nuevos 5.75% Convertible Subordinated Debentures due December 15, 2026.



Gain (loss) on mark-to-market derivative contracts.    The restructured collars discussed above as well as certain other commodity
derivative contracts to which we are a party, do not qualify for hedge accounting. Consequently, these contracts are marked-to-market each quarter with changes in fair value recognized currently as a derivative gain or loss on the income statement.
Cash flow is only impacted to the extent the actual settlements under the contracts result in making or receiving a payment from the counterparty.



During 2004 we recognized a pre-tax loss of $150.3 million from derivatives that do not qualify for hedge accounting consisting of a mark-to-market loss of $118.1
million and cash settlements of $32.2 million. We recognized a mark-to-market gain of $0.9 million in 2003.



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Income tax expense.    Income tax expense for 2004 was a benefit of $6.8 million
compared to an expense of $33.5 million for 2003. The decrease in income tax expense is primarily attributable to the reduction of pre-tax income from $80.5 million in 2003 to $2.0 million in 2004 and the benefit of federal and state Enhanced Oil
Recovery Tax Credits (EORTC). Our overall effective tax rate decreased to a negative (benefit) rate of (337%) in 2004 from 42% in 2003. Current income tax expense for 2004 was $0.4 million compared to $1.2 million in 2003. A $2.9 million
benefit related to provision-to-return adjustments for 2003 income tax returns (which is offset by a $2.9 million deferred tax expense) was offset by the federal and state impacts of reduced deductions as required by EORTC rules, an increase in the
alternative minimum tax and increased state income taxes on our operating subsidiary that is required to file a stand-alone income tax return in the states of Louisiana and Texas. Our current effective rate was 18.5% for 2004 compared to 2% for
2003. Deferred income tax expense for 2004 includes a $9.5 million benefit related to EORTCs and a $2.8 million benefit related to the restructuring of certain subsidiaries with respect to the payment of state income taxes.



EORTCs are a credit against federal and state income taxes for certain costs related to
extracting high-cost oil, utilizing certain prescribed enhanced (tertiary) recovery methods. Cyclic steam and steam drive are qualifying tertiary methods for heavy oil and PXP uses them extensively. EORTCs are subject to a phase-out
according to the level of average domestic crude prices. No phase-out occurred in 2004, however, a partial phase-out of the credits that may be earned in 2005 is expected.



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 $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 $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 $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.



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Our average realized price for gas increased $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.



Lease operating expenses.    Lease operating expenses
(including steam gas costs and electricity) increased $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 $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.



General and administrative expense.    G&A, expense,
excluding amounts attributable to stock appreciation rights, stock based compensation and merger-related costs, increased $7.9 million, to $18.7 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 for 2003 also includes other
stock based compensation costs of $1.2 million related to restricted stock and restricted stock unit grants.



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 and, amortization.    DD&A expense increased $19.4 million, to $49.8 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.



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Accretion expense.    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 $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 3TEC acquisition. 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.



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.



Liquidity and Capital Resources



Our primary sources of liquidity are cash generated from our operations and our revolving credit facility. At December 31, 2004 we had
approximately $383 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 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. Hedging also prevents us from receiving the full advantage of increases in oil or
gas prices above the maximum fixed amount specified in the hedge agreement. The majority of our oil derivatives in 2005 to 2008 are collars. In a typical collar transaction, we have the right to receive from the hedge counterparty the
excess of the minimum 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 minimum fixed price and is less than the maximum fixed price, no
payment is required by either party. If the floating price exceeds the maximum 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



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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.



At December 31,
2004 we had a working capital deficit of approximately $168.2 million. Approximately $92.9 million of the working capital deficit is attributable to the fair value of our commodity derivative instruments (net of related deferred income taxes). 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. Our hedge agreements provide for monthly settlement based on the
difference between the fixed price in the contract and the actual NYMEX oil price. Cash received for the sale of physical production will be based on actual market prices and will generally offset any gains or losses realized on the derivative
instruments. None of our derivative contracts have margin requirements or collateral provisions that could require funding prior to the scheduled cash settlement date. In addition, $21.3 million (net of related deferred income taxes) of the working
capital deficit is attributable to the in-the-money value of stock appreciation rights that were deemed vested at December 31, 2004.



As discussed in OverviewAcquisition and Dispositions in 2004 we sold certain oil and gas properties for cash proceeds of approximately $181
million.



Financing Activities



In connection with our acquisition of Nuevo, we completed the Recapitalization
Transactions described below to refinance a portion of our and all of Nuevos outstanding debt. In connection with the Recapitalization Transactions we recognized a $19.7 million pre-tax loss on early extinguishment of debt in the second
quarter of 2004. The following is a summary of our outstanding debt instruments and the Recapitalization Transactions. For additional information, including the covenants and restrictions included in such debt instruments, see Note 5 to the
Consolidated Financial Statements.



Senior Revolving Credit
Facility.    In May 2004 we amended our three-year, $500 million senior revolving credit facility with a group of lenders and with JPMorgan Chase Bank serving as administrative agent. This credit facility provides for a
current borrowing base of $600 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. The credit facility has commitments for up to $500 million in borrowings. Additionally, the credit facility contains a $50.0 million sub-limit on letters of credit. This amended
credit facility matures on April 4, 2007. To secure borrowings, we pledged 100% of the shares of stock of our domestic subsidiaries and gave mortgages covering at least 80% of the total present value of our domestic oil and gas properties.



At December 31, 2004, we had $110.0 million in borrowings and $6.9
million in letters of credit outstanding under the credit facility. At that date we were in compliance with the covenants contained in the credit facility and could have borrowed the full amount available under the credit facility. The effective
interest rate on our borrowings under this revolving credit facility was 3.6% at December 31, 2004.



7.125% Senior Notes.    On June 30, 2004 we completed the private placement under Rule 144A and Regulation S of the Securities Act of
1933 of $250 million in aggregate principal amount of ten year senior unsecured notes (the 7.125% Notes). The 7.125% Notes were issued at 99.478% and bear interest at 7.125% with a yield to maturity of 7.2%. Proceeds from the 7.125%
Notes plus borrowings under our credit facility were used to repurchase Nuevos 93/8% senior subordinated notes due
2010 (the 93/8% Notes), and redeem Nuevos 5.75% convertible subordinated debentures due



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December 15, 2026 (which resulted in the redemption of the outstanding $2.875 term convertible securities, Series A, issued by a financing trust owned by Nuevo). In
October 2004 we completed an exchange of the 7.125% Notes issued in June for 7.125% Notes with substantially identical terms except that they are freely transferable and free of any covenants regarding exchange and registration rights.



8.75% Senior Subordinated Notes.    At December 31, 2004,
we had $275.0 million principal amount of 8.75% Senior Subordinated Notes due 2012 (the 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 8.75% Notes are not redeemable until July 1, 2007. We solicited and received
the requisite consents from the holders of the 8.75% Notes and the indenture under which the 8.75% Notes were issued has been amended and restated to make certain provisions more consistent with the indenture under which the 7.125% Notes were
issued. We paid a consent payment of $7.50 per $1,000 of principal amount to holders of the 8.75% Notes ($2.1 million).



Short-term Credit Facility.    In August 2004 we entered into an uncommitted short-term credit facility with a bank under which we may
make borrowings from time to time until August 14, 2005, not to exceed at any time the maximum principal amount of $15.0 million. No advance under the short-term facility may have a term exceeding fourteen days and all amounts outstanding are due
and payable no later than August 15, 2005. Each advance under the short-term facility shall bear interest at a rate per annum mutually agreed on by the bank and the Company. At all times an advance is outstanding, the Company must have $100 million
in availability under its senior revolving credit facility. No amounts were outstanding under the short-term credit facility at December 31, 2004.



Tender Offer for Nuevos 93/8% Senior Subordinated Notes due 2010.On June 30, 2004, Nuevo completed the repurchase of all $150 million of its outstanding 93/8% Senior Subordinated Notes. Nuevo paid $1,150.08 per $1,000 principal amount of 93/8% Notes tendered (comprising the tender offer price of $1,107.16, plus accrued interest through June 29, 2004 of $22.92, plus
the consent payment of $20.00). The tender offer and consent payment totaled $169.1 million.



Nuevo had an interest rate swap with a notional amount of $100.0 million to hedge a portion of the fair value of the 93/8Notes which was cancelled for total consideration of $1.7 million.



Redemption of TECONS.    On June 30, 2004, Nuevo completed the redemption of all outstanding $118 million aggregate principal amount
of its 5.75% Convertible Subordinated Debentures due December 15, 2026 (the TECON Debentures), the proceeds of which were used by Nuevos wholly-controlled financing trust to redeem all of the trusts outstanding $115.0 million
of TECONS for total consideration of $117.0 million, which were publicly held, and all outstanding $3.0 million of $2.875 term convertible securities held by Nuevo.



Cash Flows



|                            |  |                         |        |   |      |   |        |      |  |   |       |  
|--------------------------- |  | ----------------------- | ------ | - | ---- | - | ------ | ---- |  | - | ----- | -
|                            |  | Year Ended December 31, |       
|                            |  | 2004                    |        |   | 2003 |   |        | 2002 | 
|                            |  | (in millions)           |       
|Cash provided by (used in): |  |                         |        |   |      |   |        |      |  |   |       |  
|Operating activities        |  | $                       | 363.2  |   |      | $ | 118.3  |      |  | $ | 78.8  |  
|Investing activities        |  |                         | 5.4    |   |      |   | (368.7 | )    |  |   | (64.2 | )
|Financing activities        |  |                         | (368.4 | ) |      |   | 250.8  |      |  |   | (13.7 | )



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Net cash provided by operating activities were $363.2 million, $118.3 million and $78.8 million for 2004, 2003 and
2002, respectively. The increase from 2003 to 2004 is primarily a result of increased sales volumes as a result of the Nuevo acquisition and increased oil prices. 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.



Net cash provided by investing activities was $5.4 million in 2004 compared to net cash used in investing activities of $368.7 million and $64.2 million in 2003 and 2002, respectively. The net cash inflow in 2004 is a result of
property sales proceeds of $239.0 million net of costs incurred in connection with our oil and gas acquisition, development and exploration activities of $211.4 million. The 2003 and 2002 outflows consist primarily of costs incurred in connection
with our oil and gas acquisition, development and exploration activities. Our 2003 capital expenditures included $267.5 million for the acquisition of 3TEC.



Net cash used in financing activities in 2004 was $368.4 million. During the period we repaid $101.0 million under our credit facility and we received $248.7
million in proceeds from the issuance of our 7.125% Senior Notes. These proceeds and funds generated by our operations were used to retire $405.0 million in debt assumed in the Nuevo acquisition and to pay $9.3 million in debt financing costs and
$103.5 million in financing derivative settlements. 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% notes ($80.1 million). Cash outflows in 2003 included payments for debt issuance costs ($4.3 million); 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 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).



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. We have a $375 million capital budget for 2005. We expect that these capital expenditures will be funded with cash flow from our
operations and our revolving credit facility.



We will incur cash
expenditures upon the exercise of SARs, but our common shares outstanding will not increase. At December 31, 2004 we had approximately 2.8 million SARs outstanding of which 1.8 million were vested. If all of the vested SARs were exercised, based on
$26.00, the price of our common stock as of December 31, 2004, we would pay $30.7 million to holders of the SARs. In 2004 we made cash payments of $15.2 million for SARs that were exercised during that period.



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Commitments and Contingencies



Contractual obligations.    At December 31, 2004, the aggregate amounts of contractually obligated payment commitments for the next five
years are as follows (in thousands):



|                               |  |      |        |              |   |              |  |            |        |  |   |        
|------------------------------ |  | ---- | ------ | ------------ | - | ------------ |  | ---------- | ------ |  | - | -------
|                               |  | 2005 |        | 2006 and2007 |   | 2008 and2009 |  | Thereafter
|Operating leases               |  | $    | 4,704  |              | $ | 7,096        |  | $          | 5,537  |  | $ | 7,540  
|Producing property remediation |  |      | 600    |              |   | 900          |  |            | 600    |  |   | 600    
|Long-term debt                 |  |      |       |              |   | 110,000      |  |            |       |  |   | 525,000
|Interest on debt               |  |      | 47,170 |              |   | 90,421       |  |            | 83,750 |  |   | 139,570
|Natural gas purchase contract  |  |      | 15,294 |              |   |             |  |            |       |  |   |       
|Other                          |  |      |       |              |   | 8,753        |  |            | 791    |  |   | 990    
|                               |  |      |        |              |   |              |  |            |        |  |   |        
|                               |  | $    | 67,768 |              | $ | 217,170      |  | $          | 90,678 |  | $ | 673,700
|                               |  |      |        |              |   |              |  |            |        |  |   |        



Operating leases relate
primarily to obligations associated with our office facilities and certain cogeneration operations in California. The obligation for producing property remediation consists of obligations associated with the purchase of certain of our California
properties.



The long-term debt and interest payments amounts consist of
amounts due under our credit facility, 7.125% Notes and 8.75% Notes and interest payments to maturity. The principal amount under our credit facility varies based on our cash inflows and outflows and the amounts reflected in this table assume the
principal amount outstanding at December 31, 2004 remains outstanding to maturity with interest and commitment fees calculated at the rates in effect at that date.



Our liabilities also include:



| |  |  | Asset retirement obligations ($3.6 million current and $126.9 million long-term) that represent the estimated fair value at December 31, 2004 of our obligations with respect to the
retirement/abandonment of our oil and gas properties. Each reporting period the liability is accreted to its then present value. The ultimate settlement amount and the timing of the settlement of such obligations is unknown because they are subject
to, among other things, federal, state and local regulation and economic factors. See Note 4 to the Consolidated Financial Statements.
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Commodity derivative contracts ($175.5 million current and $244.1 million long-term) that represent net liabilities for oil and gas commodity derivatives based on their estimated fair value
at December 31, 2004. The ultimate settlement amounts of such contracts are unknown because they are subject to continuing market risk. See Critical Accounting Policies and Factors that May Affect Future ResultsCommodity pricing and
risk management activities and Item 7A. Quantitative and Qualitative Disclosures About Market Risk for additional information regarding our derivative obligations.
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Stock appreciation rights ($34.6 million current and $5.2 million long-term) that represent the net liability for the deemed vested portion of SARs. The liability at December 31, 2004 is
calculated based on our closing stock price at that date. The ultimate settlement amount of such liability is unknown because settlements are based on the market price of our common stock at the time the SARs are exercised. SeeCritical
Accounting Policies and Factors that May Affect Future ResultsStock appreciation rights.
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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,



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the environment. 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.



In January 2005 we discovered and self-reported a
violation related to flared gas emissions in excess of permitted levels on properties acquired in the Nuevo acquisition. Estimated excess emissions from the San Joaquin Valley casing vent recovery system located on the Gamble Lease are approximately
881 tons over a 745 day period. We brought the facility into compliance within 10 days of discovering the violation.



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. There can be no assurance that we will be able to
collect on these indemnities.



We estimate our 2005 cash expenditures
related to plugging, abandonment and remediation will be approximately $4.3 million. Due to the long life of our onshore California reserve base we do not expect our cash outlays for such expenditures for these properties will increase significantly
in the next several years. Although our offshore California properties have a shorter reserve life, third parties have retained the majority of the obligations for abandoning these properties.



In connection with the sale of certain properties offshore California in December 2004
we retained the responsibility for certain abandonment costs, including removing, dismantling and disposing of the existing offshore platforms. The present value of such abandonment costs, $35.0 million ($65.2 million undiscounted), are included in
our asset retirement obligation as reflected on our consolidated balance sheet. In addition, we agreed to guarantee the performance of the purchaser with respect to the remaining abandonment obligations related to the properties (approximately $44
million).



For a further discussion of our obligations to incur plugging,
abandonment and remediation costs, see Items 1 and 2. Business and Properties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 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.



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



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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.



Sale of Nuevos Congo operations.    Upon our acquisition of Nuevo, we became a party to an existing agreement between Nuevo, CMS
NOMECO Oil & Gas Co. (CMS) and a third party. Under the agreement, Nuevo and CMS may be liable to the third party for the recapture of dual consolidated losses (DCLs) in connection with each companys 1995 acquisition of Congolese
properties. Nuevo and CMS agreed to indemnify each other for any act that would cause the third party to experience a liability from the recapture of DCLs as a result of a triggering event.



CMS sold its interest in the Congolese properties to a subsidiary of Perenco, S.A.
(Perenco) in 2002. The sale did not trigger recapture, as both CMS and Perenco filed a request for a closing agreement with the Internal Revenue Service (IRS) in accordance with the U.S consolidated return regulations. Similarly, we do not expect
that our merger with Nuevo, nor the sale of our interest in the Congolese properties to Perenco will trigger recapture. We, along with Perenco and the IRS, expect to finalize two closing agreements in the near future. The estimated remaining
contingent liabilities are $19.2 million relative to Nuevos former interest, and $23.5 million relative to CMS former interest, for which we would be jointly liable. We believe the occurrence of a triggering event is remote and we do not
believe the agreements will have a material adverse affect upon us.



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. During 2004, 2003 and 2002 sales to PAA accounted for 33%, 70% and 95%,
respectively, of our total revenues and during 2004 sales to ConocoPhillips accounted for 33% of our total revenues. During such periods no other purchaser accounted for more than 10% of our total revenues. The loss of any single significant
customer or contract could have a material adverse short-term effect, however, we do not believe that the loss of any single significant customer or contract would materially affect our business in the long-term. We believe such purchasers could be
replaced by other purchasers under contracts with similar terms and conditions. However, their role as the purchaser of a significant portion of our oil production does have the potential to impact our overall exposure to credit risk, either
positively or negatively, in that they may be affected by changes in economic, industry or other 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, with one such counterparty holding contracts that represent approximately 34% of the fair value of all of our open positions at December 31, 2004.



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



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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 production to achieve a more predictable cash flow, as well as to reduce our exposure to adverse price fluctuations. Hedging instruments used are typically fixed price swaps and collars and purchased puts and calls. While the use of these types
of hedging instruments limits our downside risk to adverse price movements, we are subject to a number of risks, including instances in which the benefit to revenues is limited when commodity prices increase.



Certain collars and other commodity derivative contracts to which we are a party do not
qualify for hedge accounting. Consequently, these contracts are marked-to-market each quarter with changes in fair value recognized currently as a derivative gain or loss on the income statement. For example, if the forward curve for oil prices is
higher at the end of an accounting period than at the beginning of the period a derivative fair value loss will be recorded. Conversely, if the forward curve for oil prices declines during the accounting period a fair value gain will be recorded. As
a consequence of this accounting treatment we expect that there will be significant volatilty in our reported earnings. Cash flow is only impacted to the extent the actual settlements under the contracts result in making or receiving a payment from
the counterparty.



The estimation of fair values of hedging derivatives
requires substantial judgment. We estimate the fair values of our derivatives using an option-pricing model. The option-pricing model utilizes various factors including NYMEX and over-the-counter price quotations, volatility and the time value of
options. The estimated future prices are compared to the prices fixed by the hedge agreements and the resulting estimated future cash inflows (outflows) over the lives of the hedges are discounted using rates under our revolving credit facility.
These pricing and discounting variables are sensitive to market volatility as well as changes in future price forecasts, regional price differentials and interest rates.



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
| | - |  | ------------------------------------------------------------------------------------------------------------



| |  |  | the lower of cost or fair value of unproved properties not included in the costs being amortized (net of related tax effects).
| | - |  | ------------------------------------------------------------------------------------------------------------------------------



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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.



A large portion of our reserve base (approximately 84% at December 31, 2004) is comprised of oil properties that are sensitive to oil
price volatility. 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.    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 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. Under current accounting rules, 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



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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 $35.5 million related to SARs for the year ended December 31, 2004, representing the increase in our stock price and the
vesting deemed to have occurred during the year. In 2004 we made cash payments of $15.2 million for SARs that were exercised during the year. As of December 31, 2004, we have approximately 2.8 million SARs outstanding with an average exercise price
of $10.10, of which 2.4 million of the SARs were deemed vested. Based on the number of stock appreciation rights outstanding at December 31, 2004, a $0.25 change in the price of our common stock would result in a change of $0.6 million in our net
income.



Under SFAS No. 123R (revised 2004), effective with the third
quarter of 2005, our SARs will be remeasured to fair value each reporting period. We have not determined how the new method of valuing stock-based compensation as prescribed in SFAS 123R will impact the recognition of compensation expense related to
such awards in our financial statements.



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. At December 31, 2004 goodwill totaled $170.5 million and represented approximately 6% of our total assets.



We account for goodwill in accordance with SFAS No. 142, Goodwill and Other Intangible Assets. Goodwill is not amortized, it is tested at least annually
for impairment at a level of reporting referred to as a reporting unit. Impairment is the condition that exists when the carrying amount of goodwill exceeds its implied fair value. A two-step impairment test is used to identify potential goodwill
impairment and measure the amount of a goodwill impairment loss to be recognized (if any). The first step of the goodwill impairment test, used to identify potential impairment, compares the fair value of a reporting unit with its carrying amount,
including goodwill. If the fair value of a reporting unit exceeds its carrying amount, goodwill of the reporting unit is considered not impaired, thus the second step of the impairment test is unnecessary.



The second step of the goodwill impairment test, used to measure the amount of
impairment loss, compares the implied fair value of reporting unit goodwill with the carrying amount of that goodwill. If the carrying amount of reporting unit goodwill exceeds the implied fair value of that goodwill, an impairment loss is
recognized in an amount equal to that excess. The loss recognized cannot exceed the carrying amount of goodwill.



We follow the full cost method of accounting and all of our operations are located in the United States. We have determined that for the purpose of performing an
impairment test in accordance with SFAS No. 142, the Company is the reporting unit. SFAS 142 states that quoted market prices in active markets are the best evidence of fair value and shall be used as the basis for the measurement, if available.
Accordingly, we use the quoted market price of our common stock to determine the fair value of our reporting unit.



An impairment of goodwill 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 estimated reserve volumes which would result in a decline in the fair
value of our reporting unit.



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Recent Accounting Pronouncements



In September 2004 the SEC published Staff Accounting Bulletin No. 106 (SAB 106), which is effective January 1, 2005. SAB 106 relates to the Staffs views
regarding the application of SFAS 143 by oil and gas producing companies following the full cost accounting method. SAB 106 requires that the future outflows associated with settling AROs that have been accrued on the balance sheet should be
excluded from the computation of the present value of estimated future net revenues for purposes of the full cost ceiling test calculation. SAB 106 also requires that to the extent that estimated dismantlement and abandonment costs, net of estimated
salvage values, have not been included as capitalized costs in the base for computing depletion, depreciation and amortization (DD&A) because they have not yet been capitalized as asset retirement costs under SFAS 143, such costs that will be
incurred as a result of future development activities on proved reserves should be estimated and included in the costs to be amortized. Our computation of DD&A is in compliance with the guidance in SAB 106. Our ceiling test calculation at
December 31, 2004 is in compliance with the guidance in SAB 106 and compliance with such guidelines in prior periods would not have resulted in a ceiling test writedown.



In December 2004 the FASB issued SFAS No. 123(R) that requires that the compensation cost relating to share-based payment transactions
be recognized in financial statements. That cost will be measured based on the fair value of the equity or liability instruments issued. SFAS No. 123(R) covers a wide range of share-based compensation arrangements including stock options, restricted
stock plans, performance-based awards, stock appreciation rights, and employee stock purchase plans. SFAS 123(R) replaces FASB Statement No. 123, Accounting for Stock-Based Compensation, and supersedes APB Opinion No. 25,
Accounting for Stock Issued to Employees. Public entities (other than those filing as small business issuers) will be required to apply SFAS 123(R) as of the first interim or annual reporting period that begins after June 15, 2005. We
are in the process of determining how the new method of valuing stock-based compensation as prescribed in SFAS 123R will be applied to valuing stock-based awards and the impact the recognition of compensation expense related to such awards will have
on our financial statements.



In February 2005, the SEC issued guidance
concerning the specific circumstance of a property disposition by a company that follows the full cost accounting method that resulted in a less than 25% alteration of the proved oil and gas reserve quantities within a full cost center. In
connection with that disposition, the SEC considered if goodwill should be allocated to the property disposed, and, if so, whether that allocated goodwill should remain as a component of the capitalized full cost center or be reflected in the
statement of operations.



The SEC concluded that only the fair value
allocated to the oil and gas properties in a business acquisition should be included in the costs accounted for under Rule 4-10(c) of Regulation S-X. Goodwill associated with acquisitions of oil and gas properties that constitute a business is
recognized in accordance with SFAS 141 but accounted for outside of the full cost rules. Therefore, when dispositions of these properties occur, the goodwill previously recognized does not affect the associated adjustments contemplated under Rule
4-10(c)(6)(i). Rather, the accounting for the goodwill and any potential impairment should follow the provisions of FASB Statement No. 142, Goodwill and Other Intangible Assets (SFAS 142). Companies are required to consider whether a property
disposition that results in a less than 25% alteration of the proved oil and gas reserve quantities within a given cost center is a trigger that requires goodwill be evaluated for impairment under SFAS 142. The SEC has not yet addressed whether any
portion of goodwill should be allocated to a disposition of greater than 25%, but less than 100%, of the oil and gas reserves in a given cost center.



We determined that the property dispositions completed in the fourth quarter of 2004 did not cause an impairment of goodwill. In the first quarter of 2004, prior to
the SEC guidance on this issue, we



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recorded a $2.4 million decrease in goodwill in connection with the sale of our Illinois properties and recognized this amount as an adjustment to oil and gas
properties subject to amortization.



Item 7A.Qualitative and Quantitative Disclosures About Market Risks



Commodity Price Risk



Commodity derivatives.    We actively manage our exposure to commodity price fluctuations by hedging portions of our oil and gas
production through the use of derivative instruments. The derivative instruments currently consist of oil and gas swaps, collars and option contracts entered into with financial institutions. Although certain of our derivatives do not qualify for
hedge accounting, we do not enter into derivative instruments for speculative trading purposes. Derivative instruments utilized to manage commodity price risk 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 changes in fair value
are recognized currently in our earnings as other income (expense). If a derivative is designated as a cash flow hedge and 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 until the sale of the hedged oil and gas production. Realized gains and losses on derivative instruments that are designated as a hedge and qualify for hedge accounting are generally
included in oil and gas revenues in the period the hedged volumes are sold. However, in the case of the derivatives acquired in connection with our acquisitions of Nuevo and 3TEC, only changes in fair value subsequent to the acquisition date will be
reflected in our oil and gas revenues.



As discussed in
Managements Discussion and Analysis of Financial Condition and Results of OperationsOverviewHedge Restructuring, in September 2004 we entered into new oil price collars for the period 2005-2008 and eliminated
approximately 80% of our 2005 fixed price crude oil swaps. By converting fixed price swaps to collars we retained downside protection while potentially capturing significantly higher cash flow. In addition, we now have certainty of an attractive
price range for a meaningful amount of our production for the next several years. The restructured collars as well as certain other commodity derivative contracts to which we are a party do not qualify for hedge accounting. Consequently, these
contracts are marked-to-market each quarter with changes in fair value recognized currently as a derivative gain or loss on the income statement. Cash flow is only impacted to the extent the actual settlements under the contracts result in making or
receiving a payment from the counterparty.



During 2004 we recognized a
pre-tax loss of $150.3 million from derivatives that do not qualify for hedge accounting. The foregoing amount consists of mark-to-market losses of $118.1 million and cash settlements of $32.2 million.



See Note 3 to the Consolidated Financial StatementsDerivative Instruments
and Hedging Activities for a complete discussion of our hedging activities.



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Derivative Instruments Designated as Cash Flow Hedges.



At December 31, 2004, we had the following open commodity derivative positions
designated as cash flow hedges:



|                         |  |             |  |                |  |                |  |              |       |       |           
|------------------------ |  | ----------- |  | -------------- |  | -------------- |  | ------------ | ----- | ----- | ----------
|Period                   |  | Commodity   |  | InstrumentType |  | Daily Volumes  |  | AveragePrice |       | Index
|Sales of Production      |  |             |  |                |  |                |  |              |       |       |           
|2005                     |  |             |  |                |  |                |  |              |       |       |           
|1st Quarter              |  | Crude oil   |  | Swap           |  | 13,000/Barrels |  | $            | 25.82 |       | WTI       
|2nd Quarter              |  | Crude oil   |  | Swap           |  | 10,000/Barrels |  | $            | 25.80 |       | WTI       
|1st Quarter              |  | Natural gas |  | Swap           |  | 13,000/MMBtu   |  | $            | 4.75  |       | Waha Socal
|2nd Quarter              |  | Natural gas |  | Swap           |  | 9,500/MMBtu    |  | $            | 4.66  |       | Waha      
|3rd Quarter              |  | Natural gas |  | Swap           |  | 5,000/MMBtu    |  | $            | 4.40  |       | Waha      
|4th Quarter              |  | Natural gas |  | Swap           |  | 5,000/MMBtu    |  | $            | 4.40  |       | Waha      
|2006                     |  |             |  |                |  |                |  |              |       |       |           
|January-December         |  | Crude oil   |  | Swap           |  | 15,000/Barrels |  | $            | 25.28 |       | WTI       
|                         |  |             |  |                | 
|Purchases of Natural Gas |  |             |  |                |  |                |  |              |       |       |           
|2005                     |  |             |  |                |  |                |  |              |       |       |           
|January-December         |  | Natural gas |  | Swap           |  | 8,000/MMBtu    |  | $            | 3.85  |       | Socal     



Derivative Instruments Not
Designated as Hedging Instruments.



At December 31, 2004, we had the
following open commodity derivative positions that were not designated as hedging instruments:



|                    |  |           |  |                |  |                |  |                             |  |      
|------------------- |  | --------- |  | -------------- |  | -------------- |  | --------------------------- |  | -----
|Period              |  | Commodity |  | InstrumentType |  | Daily Volumes  |  | Average Price               |  | Index
|Sales of Production |  |           |  |                |  |                |  |                             |  |      
|2005                |  |           |  |                |  |                |  |                             |  |      
|1st Quarter         |  | Crude oil |  | Collar         |  | 4,300/Barrels  |  | $27.00 Floor-$31.75 Ceiling |  | WTI  
|2nd Quarter         |  | Crude oil |  | Collar         |  | 6,800/Barrels  |  | $27.00 Floor-$30.40 Ceiling |  | WTI  
|3rd Quarter         |  | Crude oil |  | Collar         |  | 14,400/Barrels |  | $26.00 Floor-$30.03 Ceiling |  | WTI  
|4th Quarter         |  | Crude oil |  | Collar         |  | 14,000/Barrels |  | $26.00 Floor-$29.33 Ceiling |  | WTI  
|January-December    |  | Crude oil |  | Collar         |  | 22,000/Barrels |  | $25.00 Floor-$34.76 Ceiling |  | WTI  
|2006                |  |           |  |                |  |                |  |                             |  |      
|January-December    |  | Crude oil |  | Collar         |  | 22,000/Barrels |  | $25.00 Floor-$34.76 Ceiling |  | WTI  
|2007                |  |           |  |                |  |                |  |                             |  |      
|January-December    |  | Crude oil |  | Collar         |  | 22,000/Barrels |  | $25.00 Floor-$34.76 Ceiling |  | WTI  
|2008                |  |           |  |                |  |                |  |                             |  |      
|January-December    |  | Crude oil |  | Collar         |  | 22,000/Barrels |  | $25.00 Floor-$34.76 Ceiling |  | WTI  



Physical Purchase Contracts.



Although not a derivative, at December 31, 2004 we also had the
following contracts for the purchase of natural gas utilized in our steam flood operations:



|                         |  |             |  |                   |  |               |  |              |      |       |      
|------------------------ |  | ----------- |  | ----------------- |  | ------------- |  | ------------ | ---- | ----- | -----
|Period                   |  | Commodity   |  | Instrument Type   |  | Daily Volumes |  | AveragePrice |      | Index
|Purchases of Natural Gas |  |             |  |                   |  |               |  |              |      |       |      
|2005                     |  |             |  |                   |  |               |  |              |      |       |      
|January-December         |  | Natural gas |  | Physical purchase |  | 10,000/MMBtu  |  | $            | 4.19 |       | Socal



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



|                                                  |  |              |        |   |                           |   |        |           |  |   |                           |   |  |   |       |  
|------------------------------------------------- |  | ------------ | ------ | - | ------------------------- | - | ------ | --------- |  | - | ------------------------- | - |  | - | ----- | -
|                                                  |  | December 31, |       
|                                                  |  | 2004         |        |   | 2003                      |  
|                                                  |  | FairValue    |        |   | Effectof 10%PriceIncrease |   |        | FairValue |  |   | Effect of10%PriceIncrease |  
|Derivatives designated as cash flow hedges        |  | $            | (111.8 | ) |                           | $ | (29.6  | )         |  | $ | (78.7                     | ) |  | $ | (62.8 | )
|Derivatives not designated as hedging instruments |  |              | (283.0 | ) |                           |   | (113.8 | )         |  |   |                          |   |  |   |      |  



The decrease in the fair value of commodity
derivative instruments in 2004 versus 2003 reflects an increase in the number of barrels of oil associated with such instruments, differences in the terms of the instruments and an increase in the per barrel oil price.



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 agreement, and approximate the gain or loss that would have been realized if the contracts had been closed out at period 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% increase 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 prices, the fair value of our derivative portfolio would typically change less than that shown in the table due
to lower volatility in out-month prices.



The contract counterparties for
our derivative commodity contracts are all major financial institutions with Standard & Poors ratings of A or better. Six of the financial institutions are participating lenders in our revolving credit facility, with one counterparty
holding contracts that represent approximately 34% of the fair value of all open positions as of December 31, 2004.



Our management intends to continue to maintain hedging arrangements for a 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 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.



Price
differentials.    Our realized wellhead oil and gas prices are lower than the NYMEX index level as a result of area and quality differentials. See Items 1 and 2. Business and PropertiesProduct Markets and Major
Customers.



Approximately 84% of our gas production is sold monthly off
of industry recognized, published index pricing. The remaining 16% is priced daily on the spot market. Fluctuations between the two pricing mechanisms can significantly impact the overall differential to the Henry Hub.



Interest Rate Risk



We use both fixed and variable rate debt and are exposed to market risk due to the floating interest rates on our credit facilities.
Our 7.125% Notes and 8.75% Notes are fixed rate notes and are not subject to market risk. Our Senior Revolving Credit Facility and our Short-Term Credit Facility have variable rates. At December 31, 2004 $110.0 million was outstanding under our
Senior Revolving Credit Facility at an effective interest rate of 3.6%. No amounts were outstanding under our Short-Term Credit Facility at December 31, 2004.



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The following table reflects the carrying amounts and fair values of our fixed and variable rate debt (in
millions):



|                                 |  |                   |       |           |   |      
|-------------------------------- |  | ----------------- | ----- | --------- | - | -----
|                                 |  | December 31, 2004
|                                 |  | CarryingAmount    |       | FairValue
|Long-Term Debt                   |  |                   |       |           |   |      
|Senior revolving credit facility |  | $                 | 110.0 |           | $ | 110.0
|7.125% Notes                     |  |                   | 248.7 |           |   | 274.4
|8.75% Notes                      |  |                   | 276.7 |           |   | 308.0



The carrying value of our senior
revolving credit facility approximates its fair value, as interest rates are variable, based on prevailing market rates. The fair values of the 7.125% Notes and 8.75% Notes are based on quoted market prices based on trades of such debt.



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



Not Applicable.



Item 9A.Controls and Procedures



Conclusion Regarding the Effectiveness of Disclosure 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 Rules 13a-15(e) and 15d-15(e) to the Securities Exchange Act of 1934, as amended (the Exchange Act)).
Based on this evaluation, our Chief Executive Officer and our Chief Financial Officer believe that the disclosure controls and procedures as of December 31, 2004 were 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.



Managements Annual Report on Internal Control Over Financial Reporting



Our management is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control
over financial reporting is a process designed by, or under the supervision of, the Companys principal executive and principal financial officers and implemented by the Companys board of directors, management and other personnel, to
provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles and includes those policies and procedures
that: (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company; (2) provide reasonable assurance that transactions are recorded as necessary to
permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the
Company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Companys assets that could have a material effect



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on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections
of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.



Under the supervision and with the participation of our management, including our
principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal ControlIntegrated Framework issued
by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation, our management concluded that our internal control over financial reporting was effective as of December 31, 2004. Our managements assessment of
the effectiveness of our internal control over financial reporting as of December 31, 2004 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which is included herein.



Changes in Internal Control



There were no changes in our internal control over financial reporting during the
quarter ended December 31, 2004 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.



Item 9B.Other Information



Not Applicable



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 2005 annual meeting
of stockholders, in either case, to be filed within 120 days after December 31, 2004, 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.



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PART IV



Item 15.Exhibits, Financial Statement Schedules



(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



|              |   |  |                                                                                                                                                                                                                                                                                                                                                        
|------------- | - |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|ExhibitNumber |   |  | Description                                                                                                                                                                                                                                                                                                                                            
|              |  
|3.1           |   |  | Certificate of Incorporation of Plains Exploration & Production Company (incorporated by reference to Exhibit 3.1 to the Companys Amendment No. 2 to Registration Statement on Form S-1 (file
no. 333-90974) filed on October 3, 2002 (the Amendment No. 2 to Form S-1)).                                                                           
|              |  
|3.2           |   |  | Certificate of Amendment to the Certificate of Incorporation of Plains Exploration & Production Company dated May 14, 2004 (incorporated by reference to Exhibit 3.1 to the Companys Form 10-Q
for the period ending June 30, 2004 (the June 30, 2004 10-Q))                                                                                        
|              |  
|3.3           |   |  | Bylaws of Plains Exploration & Production Company (incorporated by reference to Exhibit 3.2 to the Amendment No. 2 to Form S-1).                                                                                                                                                                                                                       
|              |  
|4.1           |   |  | Amended and Restated Indenture, dated as of June 18, 2004, among Plains Exploration & Production Company, Plains E&P Company, the Subsidiary Guarantor Parties Thereto, and J.P. Morgan Chase
Bank, as Trustee (including form of 83⁄4% Senior Subordinated Note) (incorporated by reference to Exhibit 4.1 to the June 30, 2004 10-Q).                  
|              |  
|4.2           |   |  | Second Supplemental Indenture to Amended and Restated Indenture dated as of June 18, 2004, dated as of June 30, 2004, among Plains Exploration & Production Company, Plains E&P Company, the
Subsidiary Guarantor Parties Thereto, and J.P. Morgan Chase Bank, as Trustee (incorporated by reference to Exhibit 4.2 to the June 30, 2004 10-Q).        
|              |  
|4.3           | * |  | Third Supplemental Indenture to Amended and Restated Indenture dated as of June 18, 2004, dated as of December 30, 2004, among Plains Exploration & Production Company, the Subsidiary Guarantor
Parties thereto, Plains Louisiana Inc., PXP Louisiana L.L.C. and J.P. Morgan Chase Bank, as Trustee.                                                  
|              |  
|4.4           |   |  | Indenture dated as of June 30, 2004, among Plains Exploration & Production Company, the Subsidiary Guarantor Parties thereto, and Wells Fargo Bank, N.A., as Trustee (including form of 71/8% Senior Note) (incorporated by reference to Exhibit 4.1 to the Companys Form S-4 (file no. 333-118350) filed on August
18, 2004 (the August 2004 S-4)).
|              |  
|4.5           | * |  | First Supplemental Indenture to Indenture dated as of June 30, 2004, dated as of December 30, 2004, among Plains Exploration & Production Company, Plains Louisiana Inc., PXP Louisiana L.L.C., and
Wells Fargo Bank, N.A., as Trustee.                                                                                                                
|              |  
|10.1          |   |  | 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 10-12/B filed on November 21, 2002 (the Amendment No. 1 to Form 10)).                                     



59



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|              |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                           
|------------- |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|ExhibitNumber |  | Description                                                                                                                                                                                                                                                                                                                                                                                                                                                               
|10.2          |  | 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 (file no. 333-103149)
filed on May 1, 2003).
|              | 
|10.3          |  | First Amendment to Credit Agreement, dated as of August 8, 2003 to be effective as of April 4, 2003, among, Plains Exploration & Production Company, each of the subsidiary guarantor parties
thereto, each of the lenders party thereto, and J.P. Morgan Chase Bank as administrative agent (incorporated by reference to Exhibit 10.1 to the June 30, 2004 10-Q).                                                                                                       
|              | 
|10.4          |  | Second Amendment to Credit Agreement dated as of May 14, 2004, among, Plains Exploration & Production Company, each of the subsidiary guarantor parties thereto, each of the lenders party thereto,
and J.P. Morgan Chase Bank as administrative agent (incorporated by reference to Exhibit 10.2 to the June 30, 2004 10-Q).                                                                                                                                             
|              | 
|10.5          |  | Third Amendment to Credit Agreement, dated as of May 28, 2004, 2004, among Plains Exploration & Production Company, each of the subsidiary guarantor parties thereto, each of the lenders party
thereto, and J.P. Morgan Chase Bank as administrative agent (incorporated by reference to Exhibit 10.13 to the August 2004 S-4).                                                                                                                                          
|              | 
|10.6          |  | Fourth Amendment to Credit Agreement, dated effective as of September 30 2004, among Plains Exploration & Production Company, each of the subsidiary guarantor parties thereto, each of the lenders
party thereto, and J.P. Morgan Chase Bank as administrative agent (incorporated by reference to Exhibit 10.1 to the Companys Form 10-Q for the period ending September 30, 2004 (the September 30, 2004 10-Q)).                                                    
|              | 
|10.7*         |  | Crude Oil Marketing Agreement, dated as of July 15, 2004, among Plains Exploration & Production Company, Arguello, Inc., PXP Gulf Coast Inc., and Plains Marketing, L.P.                                                                                                                                                                                                                                                                                                  
|              | 
|10.8          |  | First Amendment to Crude Oil Marketing Agreement, dated as of October 19, 2004, among Plains Exploration & Production Company, Arguello, Inc., PXP Gulf Coast Inc., (Sellers) and Plains
Marketing, L.P. (Buyer) (incorporated by reference to Exhibit 10.2 to the September 30, 2004 10-Q).                                                                                                                                                                          
|              | 
|10.9          |  | Crude Oil Purchase Agreement dated February 4, 2000 between Plains Exploration & Production Company (as successor to Nuevo Energy Company) and ConocoPhillips (as successor to Tosco Corporation)
(incorporated by reference to Exhibit 10.1 to Nuevo Energy Companys Current Report on Form 8-K filed February 23, 2000).                                                                                                                                               
|              | 
|10.10         |  | Plains Exploration & Production Company 2002 Stock Incentive Plan (incorporated by reference to Exhibit 10.21 to the Amendment No. 1 to Form 10).                                                                                                                                                                                                                                                                                                                         
|              | 
|10.11         |  | Form of Plains Restricted Stock Agreement under the 2002 Incentive Plan (incorporated by reference to Exhibit 10.19 to the Companys 2002 Form 10-K).                                                                                                                                                                                                                                                                                                                     
|              | 
|10.12         |  | Form of Plains Stock Appreciation Rights Agreement under the 2002 Incentive Plan (incorporated by reference to Exhibit 10.18 to the Companys 2002 Form 10-K).                                                                                                                                                                                                                                                                                                            
|              | 
|10.13         |  | Form of Restricted Stock Unit Agreement under the 2002 Incentive Plan (incorporated by reference to Exhibit 10.33 to the Companys 2002 Form 10-K).                                                                                                                                                                                                                                                                                                                       



60



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|              |  |                                                                                                                                                                                                                                      
|------------- |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|ExhibitNumber |  | Description                                                                                                                                                                                                                          
|              | 
|10.14         |  | 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 (file no.
333-103149) filed on March 27, 2003).    
|              | 
|10.15         |  | Plains Exploration & Production Company 2002 Transition Stock Incentive Plan (incorporated by reference to Exhibit 10.33 to the Amendment No. 1 to Form 10).                                                                         
|              | 
|10.16         |  | Plains Exploration & Production Company 2002 Rollover Stock Plan (incorporated by reference to Exhibit 10.34 to the Amendment No. 1 to Form 10).                                                                                     
|              | 
|10.17         |  | Plains Exploration & Production Company 2004 Stock Incentive Plan (incorporated by reference to Annex D to the Companys Amendment No. 1 to Form S-4 (file no. 333-113536) filed on April 12,
2004).                                 
|              | 
|10.18         |  | Form of Restricted Stock Unit Agreement under the 2004 Incentive Plan (incorporated by reference to Exhibit 10.5 to the June 30, 2004 10-Q).                                                                                         
|              | 
|10.19*        |  | Form of Restricted Stock Unit Agreement for Executive Retention Grant.                                                                                                                                                               
|              | 
|10.20*        |  | Employment Agreement, dated as of June 9, 2004, between Plains Exploration & Production Company and James C. Flores.                                                                                                                 
|              | 
|10.21*        |  | Employment Agreement, dated as of June 9, 2004, between Plains Exploration & Production Company and Stephen A. Thorington.                                                                                                           
|              | 
|10.22*        |  | Employment Agreement, dated as of June 9, 2004, between Plains Exploration & Production Company and John F. Wombwell.                                                                                                                
|              | 
|10.23*        |  | Employment Agreement dated as of June 9, 2004, between Plains Exploration & Production Company and Thomas M. Gladney.                                                                                                                
|              | 
|10.24         |  | 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
Amendment No. 1 to the Form 10).
|              | 
|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 13(a)-14(a)/15d-14(a) Certificate of the Chief Executive Officer.                                                                                                                                                               
|              | 
|31.2*         |  | Rule 13(a)-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.
|-- | -------------------



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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 EXPLORATION & PRODUCTION COMPANY                                                                    
|                     |  | 
|Date: March 15, 2005 |  |  |  | /S/    JAMES C. FLORES                                                                                     
|                     |  |  |  | James C. Flores, Chairman of the Board, President and Chief Executive Officer (Principal Executive 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 15, 2005 |  |  |  | /S/    JAMES C. FLORES                                                                                     
|                     |  |  |  | James C. Flores, Chairman of the Board, President and Chief Executive Officer (Principal Executive Officer)
|                     |  | 
|Date: March 15, 2005 |  |  |  | /S/    ISAAC ARNOLD,
JR.                                                                                   
|                     |  |  |  | Isaac Arnold, Jr., Director                                                                                
|                     |  | 
|Date: March 15, 2005 |  |  |  | /S/    ALAN R. BUCKWALTER,
III                                                                             
|                     |  |  |  | Alan R. Buckwalter, III, Director                                                                          
|                     |  | 
|Date: March 15, 2005 |  |  |  | /S/    JERRY L. DEES                                                                                       
|                     |  |  |  | Jerry L. Dees, Director                                                                                    
|                     |  | 
|Date: March 15, 2005 |  |  |  | /S/    TOM H.
DELIMITROS                                                                                   
|                     |  |  |  | Tom H. Delimitros, Director                                                                                
|                     |  | 
|Date: March 15, 2005 |  |  |  | /S/    ROBERT L. GERRY,
III                                                                                
|                     |  |  |  | Robert L. Gerry, III, Director                                                                             
|                     |  | 
|Date: March 15, 2005 |  |  |  | /S/    JOHN H. LOLLAR                                                                                      
|                     |  |  |  | John H. Lollar, Director                                                                                   
|                     |  | 
|Date: March 15, 2005 |  |  |  | /S/    STEPHEN A.
THORINGTON                                                                               
|                     |  |  |  | Stephen A. Thorington, Executive Vice President and Chief Financial Officer (Principal Financial Officer)  
|                     |  | 
|Date: March 15, 2005 |  |  |  | /S/    CYNTHIA A.
FEEBACK                                                                                  
|                     |  |  |  | Cynthia A. Feeback, Vice President / Controller and Chief Accounting Officer (Principal Accounting Officer)



62



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PLAINS EXPLORATION & PRODUCTION COMPANY



INDEX TO CONSOLIDATED FINANCIAL STATEMENTS



|                                                                                                     |  |     
|---------------------------------------------------------------------------------------------------- |  | ----
|                                                                                                     |  | Page
|Financial Statements                                                                                 |  |     
|                                                                                                     | 
|Report of Independent Registered Public Accounting Firm                                              |  | F-2 
|Consolidated Balance SheetsAs of December 31, 2004 and 2003                                          |  | F-4 
|Consolidated Statements of IncomeFor the years ended December 31, 2004, 2003 and 2002                |  | F-5 
|Consolidated Statements of Cash FlowsFor the years ended December 31, 2004, 2003 and 2002            |  | F-6 
|Consolidated Statements of Comprehensive IncomeFor the years ended December 31, 2004, 2003, and 2002 |  | F-7 
|Consolidated Statements of Stockholders EquityFor the years ended December 31, 2004, 2003, and 2002 |  | F-8 
|Notes to Consolidated Financial Statements                                                           |  | F-9 



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



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##### Table of Contents

Report of Independent Registered Public Accounting Firm



To
the Board of Directors and Shareholders

of Plains Exploration and Production Company:



We have completed an integrated audit of Plains Exploration and Production Companys 2004 consolidated financial statements and
of its internal control over financial reporting as of December 31, 2004 and audits of its 2003 and 2002 consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our
opinions, based on our audits, are presented below.



Consolidated financial statements



In our opinion, the accompanying consolidated balance sheets and
the related consolidated statements of income, cash flows, comprehensive income and stockholders equity present fairly, in all material respects, the financial position of Plains Exploration and Production Company and its subsidiaries
at December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004 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 the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.
An audit of financial statements 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 4 to the consolidated financial statements, on January 1, 2003, the Company changed its method of accounting for its asset retirement
obligations in connection with its adoption of Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations.



Internal control over financial reporting



Also, in our opinion, managements assessment, included in Managements Report on Internal Control Over Financial Reporting appearing under Item 9A, that
the Company maintained effective internal control over financial reporting as of December 31, 2004 based on criteria established in Internal ControlIntegrated Framework issued by the Committee of Sponsoring Organizations of the Treadway
Commission (COSO), is fairly stated, in all material respects, based on those criteria. Furthermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31,
2004, based on criteria established in Internal ControlIntegrated Framework issued by the COSO. The Companys management is responsible for maintaining effective internal control over financial reporting and for its assessment of
the effectiveness of internal control over financial reporting. Our responsibility is to express opinions on managements assessment and on the effectiveness of the Companys internal control over financial reporting based on our audit. We
conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable
assurance about whether effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial
reporting, evaluating managements assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit
provides a reasonable basis for our opinions.



F-2



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##### Table of Contents

A companys internal control over financial reporting is a process designed to provide reasonable assurance
regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A companys internal control over financial reporting includes those
policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are
recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management
and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the companys assets that could have a material effect on the financial
statements.



Because of its inherent limitations, internal control over
financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of
compliance with the policies or procedures may deteriorate.



PricewaterhouseCoopers LLP



Houston, Texas

March 15, 2005



F-3



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##### Table of Contents

PLAINS EXPLORATION & PRODUCTION COMPANY



CONSOLIDATED BALANCE SHEETS

(in thousands of dollars)



|                                                                                                                                                                                                                                        |  |              |           |   |      |   |           |  
|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------- |  | ------------ | --------- | - | ---- | - | --------- | -
|                                                                                                                                                                                                                                        |  | December 31, |          
|                                                                                                                                                                                                                                        |  | 2004         |           |   | 2003 |  
|ASSETS                                                                                                                                                                                                                                  |  |              |           |   |      |   |           |  
|Current Assets                                                                                                                                                                                                                          |  |              |           |   |      |   |           |  
|Cash and cash equivalents                                                                                                                                                                                                               |  | $            | 1,545     |   |      | $ | 1,377     |  
|Accounts receivablePlains All American Pipeline, L.P.                                                                                                                                                                                  |  |              | 26,224    |   |      |   | 25,344    |  
|Other accounts receivable                                                                                                                                                                                                               |  |              | 96,064    |   |      |   | 25,267    |  
|Inventories                                                                                                                                                                                                                             |  |              | 8,505     |   |      |   | 5,318     |  
|Deferred income taxes                                                                                                                                                                                                                   |  |              | 76,823    |   |      |   | 28,156    |  
|Assets held for sale                                                                                                                                                                                                                    |  |              | 44,222    |   |      |   |          |  
|Other current assets                                                                                                                                                                                                                    |  |              | 4,784     |   |      |   | 3,019     |  
|                                                                                                                                                                                                                                        |  |              |           |   |      |   |           |  
|                                                                                                                                                                                                                                        |  |              | 258,167   |   |      |   | 88,481    |  
|                                                                                                                                                                                                                                        |  |              |           |   |      |   |           |  
|Property and Equipment, at cost                                                                                                                                                                                                         |  |              |           |   |      |   |           |  
|Oil and natural gas propertiesfull cost method                                                                                                                                                                                         |  |              |           |   |      |   |           |  
|Subject to amortization                                                                                                                                                                                                                 |  |              | 2,402,179 |   |      |   | 1,074,302 |  
|Not subject to amortization                                                                                                                                                                                                             |  |              | 79,405    |   |      |   | 63,658    |  
|Other property and equipment                                                                                                                                                                                                            |  |              | 12,546    |   |      |   | 4,939     |  
|                                                                                                                                                                                                                                        |  |              |           |   |      |   |           |  
|                                                                                                                                                                                                                                        |  |              | 2,494,130 |   |      |   | 1,142,899 |  
|Less allowance for depreciation, depletion and amortization                                                                                                                                                                             |  |              | (323,041  | ) |      |   | (186,004  | )
|                                                                                                                                                                                                                                        |  |              |           |   |      |   |           |  
|                                                                                                                                                                                                                                        |  |              | 2,171,089 |   |      |   | 956,895   |  
|                                                                                                                                                                                                                                        |  |              |           |   |      |   |           |  
|Goodwill                                                                                                                                                                                                                                |  |              | 170,467   |   |      |   | 147,251   |  
|                                                                                                                                                                                                                                        |  |              |           |   |      |   |           |  
|Other Assets                                                                                                                                                                                                                            |  |              | 33,522    |   |      |   | 19,641    |  
|                                                                                                                                                                                                                                        |  |              |           |   |      |   |           |  
|                                                                                                                                                                                                                                        |  | $            | 2,633,245 |   |      | $ | 1,212,268 |  
|                                                                                                                                                                                                                                        |  |              |           |   |      |   |           |  
|LIABILITIES AND STOCKHOLDERS EQUITY                                                                                                                                                                                                    |  |              |           |   |      |   |           |  
|Current Liabilities                                                                                                                                                                                                                     |  |              |           |   |      |   |           |  
|Accounts payable                                                                                                                                                                                                                        |  | $            | 90,469    |   |      | $ | 41,736    |  
|Commodity derivative contracts                                                                                                                                                                                                          |  |              | 175,473   |   |      |   | 60,222    |  
|Royalties payable                                                                                                                                                                                                                       |  |              | 39,174    |   |      |   | 19,080    |  
|Stock appreciation rights                                                                                                                                                                                                               |  |              | 34,589    |   |      |   | 16,049    |  
|Interest payable                                                                                                                                                                                                                        |  |              | 13,070    |   |      |   | 622       |  
|Deposit on assets held for sale                                                                                                                                                                                                         |  |              | 40,711    |   |      |   |          |  
|Other current liabilities                                                                                                                                                                                                               |  |              | 32,909    |   |      |   | 17,377    |  
|                                                                                                                                                                                                                                        |  |              |           |   |      |   |           |  
|                                                                                                                                                                                                                                        |  |              | 426,395   |   |      |   | 155,086   |  
|                                                                                                                                                                                                                                        |  |              |           |   |      |   |           |  
|Long-Term Debt                                                                                                                                                                                                                          |  |              |           |   |      |   |           |  
|8.75% Senior Subordinated Notes                                                                                                                                                                                                         |  |              | 276,727   |   |      |   | 276,906   |  
|7.125% Senior Notes                                                                                                                                                                                                                     |  |              | 248,741   |   |      |   |          |  
|Revolving credit facility                                                                                                                                                                                                               |  |              | 110,000   |   |      |   | 211,000   |  
|                                                                                                                                                                                                                                        |  |              |           |   |      |   |           |  
|                                                                                                                                                                                                                                        |  |              | 635,468   |   |      |   | 487,906   |  
|                                                                                                                                                                                                                                        |  |              |           |   |      |   |           |  
|Other Long-Term Liabilities                                                                                                                                                                                                             |  |              |           |   |      |   |           |  
|Asset retirement obligation                                                                                                                                                                                                             |  |              | 126,850   |   |      |   | 33,235    |  
|Commodity derivative contracts                                                                                                                                                                                                          |  |              | 244,140   |   |      |   | 23,697    |  
|Other                                                                                                                                                                                                                                   |  |              | 10,534    |   |      |   | 8,497     |  
|                                                                                                                                                                                                                                        |  |              |           |   |      |   |           |  
|                                                                                                                                                                                                                                        |  |              | 381,524   |   |      |   | 65,429    |  
|                                                                                                                                                                                                                                        |  |              |           |   |      |   |           |  
|Deferred Income Taxes                                                                                                                                                                                                                   |  |              | 319,483   |   |      |   | 149,591   |  
|                                                                                                                                                                                                                                        |  |              |           |   |      |   |           |  
|Commitments and Contingencies (Note 10)                                                                                                                                                                                                 |  |              |           |   |      |   |           |  
|Stockholders Equity                                                                                                                                                                                                                    |  |              |           |   |      |   |           |  
|Common stock, $0.01 par value, 150.0 million shares authorized, 77.2 million issued and 77.1 million outstanding at December 31, 2004; 100.0 million
shares authorized, 40.3 million shares issued and outstanding at December 31, 2003 |  |              | 772       |   |      |   | 403       |  
|Additional paid-in capital                                                                                                                                                                                                              |  |              | 913,466   |   |      |   | 322,856   |  
|Retained earnings                                                                                                                                                                                                                       |  |              | 80,406    |   |      |   | 71,566    |  
|Accumulated other comprehensive income                                                                                                                                                                                                  |  |              | (123,874  | ) |      |   | (40,439   | )
|Treasury stock, at cost                                                                                                                                                                                                                 |  |              | (395      | ) |      |   | (130      | )
|                                                                                                                                                                                                                                        |  |              |           |   |      |   |           |  
|                                                                                                                                                                                                                                        |  |              | 870,375   |   |      |   | 354,256   |  
|                                                                                                                                                                                                                                        |  |              |           |   |      |   |           |  
|                                                                                                                                                                                                                                        |  | $            | 2,633,245 |   |      | $ | 1,212,268 |  
|                                                                                                                                                                                                                                        |  |              |           |   |      |   |           |  



See notes to consolidated
financial statements.



F-4



---

##### Table of Contents

PLAINS EXPLORATION & PRODUCTION COMPANY



CONSOLIDATED STATEMENTS OF INCOME

(in thousands, except per share data)



|                                                                               |  |                         |          |   |      |   |         |      |  |   |         |  
|------------------------------------------------------------------------------ |  | ----------------------- | -------- | - | ---- | - | ------- | ---- |  | - | ------- | -
|                                                                               |  | Year Ended December 31, |         
|                                                                               |  | 2004                    |          |   | 2003 |   |         | 2002 | 
|Revenues                                                                       |  |                         |          |   |      |   |         |      |  |   |         |  
|Oil sales to Plains All American Pipeline, L.P.                                |  | $                       | 274,447  |   |      | $ | 238,663 |      |  | $ | 193,615 |  
|Other oil sales                                                                |  |                         | 319,362  |   |      |   | 10,837  |      |  |   |        |  
|Oil hedging                                                                    |  |                         | (145,753 | ) |      |   | (51,352 | )    |  |   | (15,577 | )
|Gas sales (includes $23.2 million related to buy/sell contracts in 2004)       |  |                         | 227,468  |   |      |   | 91,267  |      |  |   | 10,299  |  
|Gas hedging                                                                    |  |                         | (6,108   | ) |      |   | 13,787  |      |  |   |        |  
|Other operating revenues                                                       |  |                         | 2,290    |   |      |   | 888     |      |  |   | 226     |  
|                                                                               |  |                         |          |   |      |   |         |      |  |   |         |  
|                                                                               |  |                         | 671,706  |   |      |   | 304,090 |      |  |   | 188,563 |  
|                                                                               |  |                         |          |   |      |   |         |      |  |   |         |  
|Costs and Expenses                                                             |  |                         |          |   |      |   |         |      |  |   |         |  
|Production costs                                                               |  |                         |          |   |      |   |         |      |  |   |         |  
|Lease operating expenses                                                       |  |                         | 122,540  |   |      |   | 66,858  |      |  |   | 52,050  |  
|Steam gas costs (includes $23.4 million related to buy/sell contracts in 2004) |  |                         | 40,521   |   |      |   | 2,841   |      |  |   | 1,733   |  
|Electricity                                                                    |  |                         | 30,137   |   |      |   | 22,385  |      |  |   | 20,384  |  
|Production and ad valorem taxes                                                |  |                         | 22,332   |   |      |   | 10,125  |      |  |   | 4,284   |  
|Gathering and transportation expenses                                          |  |                         | 7,550    |   |      |   | 2,610   |      |  |   |        |  
|General and administrative                                                     |  |                         |          |   |      |   |         |      |  |   |         |  
|G&A excluding items below                                                      |  |                         | 35,394   |   |      |   | 18,694  |      |  |   | 10,756  |  
|Stock appreciation rights                                                      |  |                         | 35,464   |   |      |   | 18,010  |      |  |   | 3,653   |  
|Other stock-based compensation                                                 |  |                         | 8,092    |   |      |   | 1,190   |      |  |   |        |  
|Merger related costs                                                           |  |                         | 6,247    |   |      |   | 5,264   |      |  |   |        |  
|Spin-off costs                                                                 |  |                         |         |   |      |   |        |      |  |   | 777     |  
|Provision for legal and regulatory settlements                                 |  |                         | 6,845    |   |      |   |        |      |  |   |        |  
|Depreciation, depletion and amortization                                       |  |                         | 139,422  |   |      |   | 49,847  |      |  |   | 30,359  |  
|Accretion                                                                      |  |                         | 8,563    |   |      |   | 2,637   |      |  |   |        |  
|                                                                               |  |                         |          |   |      |   |         |      |  |   |         |  
|                                                                               |  |                         | 463,107  |   |      |   | 200,461 |      |  |   | 123,996 |  
|                                                                               |  |                         |          |   |      |   |         |      |  |   |         |  
|Income from Operations                                                         |  |                         | 208,599  |   |      |   | 103,629 |      |  |   | 64,567  |  
|Other Income (Expense)                                                         |  |                         |          |   |      |   |         |      |  |   |         |  
|Interest expense                                                               |  |                         | (37,294  | ) |      |   | (23,778 | )    |  |   | (19,377 | )
|Debt extinguishment costs                                                      |  |                         | (19,691  | ) |      |   |        |      |  |   |        |  
|Gain (loss) on mark-to-market derivative contracts                             |  |                         | (150,314 | ) |      |   | 847     |      |  |   |        |  
|Expenses of terminated public equity offering                                  |  |                         |         |   |      |   |        |      |  |   | (2,395  | )
|Interest and other income (expense)                                            |  |                         | 723      |   |      |   | (159    | )    |  |   | 174     |  
|                                                                               |  |                         |          |   |      |   |         |      |  |   |         |  
|Income Before Income Taxes and Cumulative Effect of Accounting Change          |  |                         | 2,023    |   |      |   | 80,539  |      |  |   | 42,969  |  
|Income tax (expense) benefit                                                   |  |                         |          |   |      |   |         |      |  |   |         |  
|Current                                                                        |  |                         | (375     | ) |      |   | (1,224  | )    |  |   | (6,353  | )
|Deferred                                                                       |  |                         | 7,192    |   |      |   | (32,228 | )    |  |   | (10,379 | )
|                                                                               |  |                         |          |   |      |   |         |      |  |   |         |  
|Income Before Cumulative Effect of Accounting Change                           |  |                         | 8,840    |   |      |   | 47,087  |      |  |   | 26,237  |  
|Cumulative effect of accounting change, net of tax expense                     |  |                         |         |   |      |   | 12,324  |      |  |   |        |  
|                                                                               |  |                         |          |   |      |   |         |      |  |   |         |  
|Net Income                                                                     |  | $                       | 8,840    |   |      | $ | 59,411  |      |  | $ | 26,237  |  
|                                                                               |  |                         |          |   |      |   |         |      |  |   |         |  
|Earnings per share, basic and diluted                                          |  |                         |          |   |      |   |         |      |  |   |         |  
|Income before cumulative effect of accounting change                           |  | $                       | 0.14     |   |      | $ | 1.41    |      |  | $ | 1.08    |  
|Cumulative effect of accounting change                                         |  |                         |         |   |      |   | 0.37    |      |  |   |        |  
|                                                                               |  |                         |          |   |      |   |         |      |  |   |         |  
|Net income                                                                     |  | $                       | 0.14     |   |      | $ | 1.78    |      |  | $ | 1.08    |  
|                                                                               |  |                         |          |   |      |   |         |      |  |   |         |  
|Weighted Average Shares Outstanding                                            |  |                         |          |   |      |   |         |      |  |   |         |  
|Basic                                                                          |  |                         | 63,542   |   |      |   | 33,321  |      |  |   | 24,193  |  
|                                                                               |  |                         |          |   |      |   |         |      |  |   |         |  
|Diluted                                                                        |  |                         | 64,014   |   |      |   | 33,469  |      |  |   | 24,201  |  
|                                                                               |  |                         |          |   |      |   |         |      |  |   |         |  



See notes to consolidated
financial statements.



F-5



---

##### Table of Contents

PLAINS EXPLORATION & PRODUCTION COMPANY



CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands of dollars)



|                                                                                          |  |                         |            |   |      |   |          |      |  |   |          |  
|----------------------------------------------------------------------------------------- |  | ----------------------- | ---------- | - | ---- | - | -------- | ---- |  | - | -------- | -
|                                                                                          |  | Year Ended December 31, |           
|                                                                                          |  | 2004                    |            |   | 2003 |   |          | 2002 | 
|CASH FLOWS FROM OPERATING ACTIVITIES                                                      |  |                         |            |   |      |   |          |      |  |   |          |  
|Net income                                                                                |  | $                       | 8,840      |   |      | $ | 59,411   |      |  | $ | 26,237   |  
|Items not affecting cash flows from operating activities                                  |  |                         |            |   |      |   |          |      |  |   |          |  
|Depreciation, depletion, amortization and accretion                                       |  |                         | 147,985    |   |      |   | 52,484   |      |  |   | 30,359   |  
|Deferred income taxes                                                                     |  |                         | (7,192     | ) |      |   | 32,228   |      |  |   | 10,379   |  
|Debt extinguishment costs                                                                 |  |                         | (4,453     | ) |      |   |         |      |  |   |         |  
|Cumulative effect of adoption of accounting change                                        |  |                         |           |   |      |   | (12,324  | )    |  |   |         |  
|Commodity derivative contracts                                                            |  |                         |            |   |      |   |          |      |  |   |          |  
|Loss (gain) on derivatives                                                                |  |                         | 49,841     |   |      |   | (847     | )    |  |   |         |  
|Reclassify financing derivative settlements                                               |  |                         | 103,521    |   |      |   |         |      |  |   |         |  
|Noncash compensation                                                                      |  |                         |            |   |      |   |          |      |  |   |          |  
|Stock appreciation rights                                                                 |  |                         | 20,268     |   |      |   | 15,895   |      |  |   |         |  
|Other                                                                                     |  |                         | 8,092      |   |      |   | 1,190    |      |  |   | 32       |  
|Other noncash items                                                                       |  |                         | (144       | ) |      |   | 123      |      |  |   | 425      |  
|Change in assets and liabilities from operating activities, net of effect of acquisitions |  |                         |            |   |      |   |          |      |  |   |          |  
|Accounts receivable and other assets                                                      |  |                         | (15,982    | ) |      |   | (3,548   | )    |  |   | (11,964  | )
|Inventories                                                                               |  |                         | (1,947     | ) |      |   | 91       |      |  |   | (576     | )
|Payable to Plains Resources Inc.                                                          |  |                         |           |   |      |   | (1,435   | )    |  |   | 4,946    |  
|Accounts payable and other liabilities                                                    |  |                         | 54,390     |   |      |   | (24,990  | )    |  |   | 18,988   |  
|                                                                                          |  |                         |            |   |      |   |          |      |  |   |          |  
|Net cash provided by operating activities                                                 |  |                         | 363,219    |   |      |   | 118,278  |      |  |   | 78,826   |  
|                                                                                          |  |                         |            |   |      |   |          |      |  |   |          |  
|CASH FLOWS FROM INVESTING ACTIVITIES                                                      |  |                         |            |   |      |   |          |      |  |   |          |  
|Additions to oil and gas properties                                                       |  |                         | (211,387   | ) |      |   | (122,070 | )    |  |   | (64,497  | )
|Acquisition of Nuevo Energy Company, net of cash acquired                                 |  |                         | (14,156    | ) |      |   |         |      |  |   |         |  
|Acquisition of 3TEC Energy Corporation, net of cash acquired                              |  |                         |           |   |      |   | (267,546 | )    |  |   |         |  
|Proceeds from sales of properties                                                         |  |                         | 238,989    |   |      |   | 23,420   |      |  |   | 529      |  
|Other property and equipment                                                              |  |                         | (8,032     | ) |      |   | (2,514   | )    |  |   | (190     | )
|                                                                                          |  |                         |            |   |      |   |          |      |  |   |          |  
|Net cash (used in) provided by investing activities                                       |  |                         | 5,414      |   |      |   | (368,710 | )    |  |   | (64,158  | )
|                                                                                          |  |                         |            |   |      |   |          |      |  |   |          |  
|CASH FLOWS FROM FINANCING ACTIVITIES                                                      |  |                         |            |   |      |   |          |      |  |   |          |  
|Revolving credit facilities                                                               |  |                         |            |   |      |   |          |      |  |   |          |  
|Borrowings                                                                                |  |                         | 1,044,850  |   |      |   | 471,600  |      |  |   | 212,300  |  
|Repayments                                                                                |  |                         | (1,145,850 | ) |      |   | (296,400 | )    |  |   | (176,500 | )
|Proceeds from issuance of 7.125% Senior Notes                                             |  |                         | 248,695    |   |      |   |         |      |  |   |         |  
|Proceeds from issuance of 8.75% Senior Subordinated Notes                                 |  |                         |           |   |      |   | 80,061   |      |  |   | 196,752  |  
|Retirement of debt assumed in acquisition of Nuevo Energy Company                         |  |                         | (405,000   | ) |      |   |         |      |  |   |         |  
|Costs incurred in connection with financing arrangements                                  |  |                         | (9,325     | ) |      |   | (4,349   | )    |  |   | (5,936   | )
|Derivative settlements                                                                    |  |                         | (103,521   | ) |      |   |          |      |  |   |         |  
|Contribution from Plains Resources Inc.                                                   |  |                         |           |   |      |   | 510      |      |  |   | 52,200   |  
|Distribution to Plains Resources Inc.                                                     |  |                         |           |   |      |   |         |      |  |   | (311,964 | )
|Receipts from Plains Resources Inc.                                                       |  |                         |           |   |      |   |         |      |  |   | 20,363   |  
|Other                                                                                     |  |                         | 1,686      |   |      |   | (641     | )    |  |   | (868     | )
|                                                                                          |  |                         |            |   |      |   |          |      |  |   |          |  
|Net cash (used in) provided by financing activities                                       |  |                         | (368,465   | ) |      |   | 250,781  |      |  |   | (13,653  | )
|                                                                                          |  |                         |            |   |      |   |          |      |  |   |          |  
|Net increase in cash and cash equivalents                                                 |  |                         | 168        |   |      |   | 349      |      |  |   | 1,015    |  
|Cash and cash equivalents, beginning of period                                            |  |                         | 1,377      |   |      |   | 1,028    |      |  |   | 13       |  
|                                                                                          |  |                         |            |   |      |   |          |      |  |   |          |  
|Cash and cash equivalents, end of period                                                  |  | $                       | 1,545      |   |      | $ | 1,377    |      |  | $ | 1,028    |  
|                                                                                          |  |                         |            |   |      |   |          |      |  |   |          |  



See notes to consolidated
financial statements.



F-6



---

##### Table of Contents

PLAINS EXPLORATION & PRODUCTION COMPA
NY



CONSOLIDATED STATEMENTS OF
COMPREHENSIVE INCOME

(in thousands of dollars)



|                                                  |  |                         |          |   |      |   |         |      |  |   |         |  
|------------------------------------------------- |  | ----------------------- | -------- | - | ---- | - | ------- | ---- |  | - | ------- | -
|                                                  |  | Year Ended December 31, |         
|                                                  |  | 2004                    |          |   | 2003 |   |         | 2002 | 
|Net Income                                        |  | $                       | 8,840    |   |      | $ | 59,411  |      |  | $ | 26,237  |  
|                                                  |  |                         |          |   |      |   |         |      |  |   |         |  
|Other Comprehensive Income (Loss)                 |  |                         |          |   |      |   |         |      |  |   |         |  
|Commodity hedging contracts                       |  |                         |          |   |      |   |         |      |  |   |         |  
|Change in fair value                              |  |                         | (287,186 | ) |      |   | (83,288 | )    |  |   | (62,268 | )
|Reclassification adjustment for settled contracts |  |                         | 152,983  |   |      |   | 37,564  |      |  |   | 14,747  |  
|Related tax benefit                               |  |                         | 50,617   |   |      |   | 17,999  |      |  |   | 19,073  |  
|Other                                             |  |                         |          |   |      |   |         |      |  |   |         |  
|Interest rate swap and minimum pension liability  |  |                         | 250      |   |      |   | 239     |      |  |   | (490    | )
|Related tax benefit (expense)                     |  |                         | (99      | ) |      |   | (95     | )    |  |   | 196     |  
|                                                  |  |                         |          |   |      |   |         |      |  |   |         |  
|                                                  |  |                         | (83,435  | ) |      |   | (27,581 | )    |  |   | (28,742 | )
|                                                  |  |                         |          |   |      |   |         |      |  |   |         |  
|Comprehensive Income (Loss)                       |  | $                       | (74,595  | ) |      | $ | 31,830  |      |  | $ | (2,505  | )
|                                                  |  |                         |          |   |      |   |         |      |  |   |         |  







See notes to consolidated financial statements.



F-7



---

##### Table of Contents

PLAINS EXPLORATION AND PRODUCTION COMPANY



CONSOLIDATED 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 at December 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                 |        |                                        |        |        |                |   |       |       |   |         |   |  |    |   |  |   |     |   |  |   | 2        |  
|Deferred compensation                                                       |  |                         |         |   |              |       |                            |  |   |                  |        |                                        | 30      |        |                |   |       |       |   |         |   |  |    |   |  |   |     |   |  |   | 30       |  
|Other comprehensive income                                                  |  |                         |         |   |              |       |                            |  |   |                  |        |                                        |        |        |                |   |       |       |   | (28,742  | ) |  |    |   |  |   |     |   |  |   | (28,742  | )
|                                                                            |  |                         |          |   |              |        |                            |  |   |                   |        |                                        |         |        |                |   |        |       |   |          |   |  |     |   |  |   |      |   |  |   |          |  
|Balance at December 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 at December 31, 2003                                                |  |                         |         |   |              | 40,316 |                            |  |   | 403               |        |                                        | 322,856 |        |                |   | 71,566 |       |   | (40,439  | ) |  | (17 | ) |  |   | (130 | ) |  |   | 354,256  |  
|Net income                                                                  |  |                         |         |   |              |       |                            |  |   |                  |        |                                        |        |        |                |   | 8,840  |       |   |         |   |  |    |   |  |   |     |   |  |   | 8,840    |  
|Acquisition of Nuevo Energy Company                                         |  |                         |          |   |              |        |                            |  |   |                   |        |                                        |         |        |                |   |        |       |   |          |   |  |     |   |  |   |      |   |  |   |         |  
|Issuance of common stock                                                    |  |                         |         |   |              | 36,486 |                            |  |   | 365               |        |                                        | 574,658 |        |                |   |       |       |   |         |   |  |    |   |  |   |     |   |  |   | 575,023  |  
|Other                                                                       |  |                         |         |   |              |       |                            |  |   |                  |        |                                        | 4,389   |        |                |   |       |       |   |         |   |  |    |   |  |   |     |   |  |   | 4,389    |  
|Restricted stock awards                                                     |  |                         |          |   |              |        |                            |  |   |                   |        |                                        |         |        |                |   |        |       |   |          |   |  |     |   |  |   |      |   |  |   |          |  
|Issuance of restricted stock                                                |  |                         |         |   |              | 235    |                            |  |   | 3                 |        |                                        |        |        |                |   |       |       |   |         |   |  |    |   |  |   |     |   |  |   | 3        |  
|Deferred compensation                                                       |  |                         |         |   |              |       |                            |  |   |                  |        |                                        | 8,082   |        |                |   |       |       |   |         |   |  |    |   |  |   |     |   |  |   | 8,082    |  
|Additions to treasury stock                                                 |  |                         |         |   |              |       |                            |  |   |                  |        |                                        |        |        |                |   |       |       |   |         |   |  | (15 | ) |  |   | (265 | ) |  |   | (265     | )
|Other comprehensive income                                                  |  |                         |         |   |              |       |                            |  |   |                  |        |                                        |        |        |                |   |       |       |   | (83,435  | ) |  |    |   |  |   |     |   |  |   | (83,435  | )
|Other                                                                       |  |                         |         |   |              | 142    |                            |  |   | 1                 |        |                                        | 3,481   |        |                |   |       |       |   |         |   |  |    |   |  |   |     |   |  |   | 3,482    |  
|                                                                            |  |                         |          |   |              |        |                            |  |   |                   |        |                                        |         |        |                |   |        |       |   |          |   |  |     |   |  |   |      |   |  |   |          |  
|Balance at December 31, 2004                                                |  | $                       |         |   |              | 77,179 |                            |  | $ | 772               |        | $                                      | 913,466 |        |                | $ | 80,406 |       | $ | (123,874 | ) |  | (32 | ) |  | $ | (395 | ) |  | $ | 870,375  |  
|                                                                            |  |                         |          |   |              |        |                            |  |   |                   |        |                                        |         |        |                |   |        |       |   |          |   |  |     |   |  |   |      |   |  |   |          |  



See notes to consolidated
financial statements.



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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 all its wholly-owned 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 Inc. (Plains Resources currently known as Vulcan Energy Inc.), 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, 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



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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 May 14, 2004 we acquired Nuevo Energy Company (Nuevo) and on June 4, 2003, we acquired 3TEC Energy Corporation (3TEC). We have accounted for the acquisitions as a purchase. The Nuevo acquisition was accounted for
with effect from May 14, 2004 and the 3TEC was accounted for 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 6.



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 (SFAS) 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.    We account
for our asset retirement obligations in accordance with 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.



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Other Property and Equipment.    Other property and equipment is recorded at cost and
consists primarily of aircraft, 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 operating income in the period in which the transaction occurs.



Use of Estimates.    The preparation of financial statements
in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the
financial statements and the reported amounts of revenues and expenses during the reporting period. Significant estimates made by management include (1) 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,
2004 and 2003, the majority of cash and cash equivalents was concentrated in one institution and at times may exceed federally insured limits. We periodically assess the financial condition of the institution and believe that any possible credit
risk is minimal. Accounts payable at December 31, 2004 and 2003 includes $14.4 million and $5.3 million, respectively, representing outstanding checks that had not been presented for payment.



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,
|                       |  | 2004         |       | 2003
|Oil                    |  | $            | 1,526 |      | $ | 863  
|Materials and supplies |  |              | 6,979 |      |   | 4,455
|                       |  |              |       |      |   |      
|                       |  | $            | 8,505 |      | $ | 5,318
|                       |  |              |       |      |   |      



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



|                      |  |              |        |      |   |       
|--------------------- |  | ------------ | ------ | ---- | - | ------
|                      |  | December 31,
|                      |  | 2004         |        | 2003
|Land                  |  | $            | 13,873 |      | $ | 8,853 
|Debt issue costs, net |  |              | 15,131 |      |   | 8,068 
|Other                 |  |              | 4,518  |      |   | 2,720 
|                      |  |              |        |      |   |       
|                      |  | $            | 33,522 |      | $ | 19,641
|                      |  |              |        |      |   |       



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



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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. We have changed the classification of deferred income taxes related to our current liability with respect to stock appreciation rights in our December 31, 2003 consolidated
balance sheet.



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 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, 2004 and 2003 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 actively manage our exposure to commodity price fluctuations by hedging portions of our oil and gas production through the use of derivative instruments. The derivative instruments currently consist of oil
and gas swaps, collars and option contracts entered into with financial institutions. We do not enter into derivative instruments for speculative trading purposes. Derivative instruments utilized to manage commodity price risk are accounted for in
accordance with SFAS No. 133 Accounting for Derivative Instruments and Hedging Activities, as amended (SFAS 133). See Note 3.



Stock Based Compensation.    We account for stock based compensation using the intrinsic value method. No adjustments to our net income
or earnings per share would be required under SFAS No. 123, Accounting for Stock-Based Compensation. See Note 7.



Earnings Per Share.    Weighted average shares outstanding for computing basic and diluted earnings for the years ended December 31,
2004, 2003 and 2002 were (in thousands):



|                                                                    |  |                         |  |        |  |       
|------------------------------------------------------------------- |  | ----------------------- |  | ------ |  | ------
|                                                                    |  | Year Ended December 31,
|                                                                    |  | 2004                    |  | 2003   |  | 2002  
|Common shares outstandingbasic                                     |  | 63,542                  |  | 33,321 |  | 24,193
|Unvested restricted stock, restricted stock units and stock options |  | 472                     |  | 148    |  | 8     
|                                                                    |  |                         |  |        |  |       
|Common shares outstandingdiluted                                   |  | 64,014                  |  | 33,469 |  | 24,201
|                                                                    |  |                         |  |        |  |       



In computing earnings per share,
no adjustments were made to reported net income.



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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 estimated reserve volumes which would result in a decline in the fair value of our oil and gas properties.



In 2003 we recorded $147.3 million of goodwill in connection with our acquisition of 3TEC. In 2004, as a result of our acquisitions of Nuevo and 3TEC goodwill
increased by $25.4 million and $0.2 million, respectively. As a result of the sale of our Illinois properties in 2004, goodwill was decreased by $2.4 million which was considered in the disposition and recognized as an adjustment to oil and gas
properties subject to amortization.



Business Segment
Information.    SFAS 131, Disclosures about Segments of an Enterprise and Related Information establishes standards for reporting information about operating segments. Segment reporting is not applicable for us
since our operating areas have similar economic characteristics and meet the criteria for aggregation as defined in SFAS 131. We acquire, exploit, develop, explore for and produce oil and gas and all of our operations are located in the United
States. Our corporate management team that administers all properties as a whole rather than as discrete operating segments. We track basic operational data by area, however, we measure financial performance as a single enterprise and not on an
area-by-area basis. We allocate capital resources on a project-by-project basis across our entire asset base to maximize profitability without regard to individual areas or segments.



Buy/Sell Contracts.    Steam generators utilized in our thermal recovery operations in California are
fueled by natural gas. In certain instances we have entered into buy/sell contracts that allow us to exchange gas we produce elsewhere for gas delivered to our thermal recovery operations. The buy/sell transactions result in us making or receiving
physical delivery of the gas and involve the attendant risks and rewards of ownership, including title transfer.



We account for buy/sell contracts in the same manner as any other monetary transaction for which title passes and the risk and reward of ownership are assumed by
the counterparties. The SEC has questioned whether the industrys accounting for buy/sell contracts should instead be shown net on the income statement and accounted for under the provisions of Accounting Principles Board (APB) Opinion No. 29,
Accounting for Nonmonetary Transactions(APB 29). The topic is under deliberation by the Emerging Issues Task Force (EITF) of the FASB as Issue No. 04-13, Accounting for Purchases and Sales of Inventory with the Same
Counterparty.The EITF first discussed this issue in November 2004. Additional research is being performed by the FASB staff, and the topic will be discussed again at a future EITF meeting. While this issue is under deliberation, the SEC
staff directed companies in a February 2005 letter to disclose on the face of the income statement, if material, the amounts associated with buy/sell contracts and to discuss in a footnote to the financial statements the basis for the underlying
accounting.



We believe our buy/sell contracts are monetary transactions
that are outside the scope of APB 29. We also believe our accounting is supported by the indicators of gross reporting of purchases and sales in paragraph 3 of EITF Issue No. 99-19, Reporting Revenue Gross as a Principal versus Net as an
Agent.



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For the year ended December 31, 2004, Gas Sales and Production Costs  steam gas costs include $23.2 million
and $23.4 million, respectively, related to buy/sell contracts. If the EITF were to determine these transactions should be accounted for as non-monetary, such amounts would be netted in our Consolidated Statements of Income. We did not enter into
buy/sell contracts in periods prior to our acquisition of Nuevo in May 2004.



Recent Accounting Pronouncements.    In September 2004 the SEC published Staff Accounting Bulletin No. 106 (SAB 106), which is effective January 1, 2005. SAB 106 relates to the Staffs views regarding the
application of SFAS 143 by oil and gas producing companies following the full cost accounting method. SAB 106 requires that the future outflows associated with settling AROs that have been accrued on the balance sheet should be excluded from the
computation of the present value of estimated future net revenues for purposes of the full cost ceiling test calculation. SAB 106 also requires that to the extent that estimated dismantlement and abandonment costs, net of estimated salvage values,
have not been included as capitalized costs in the base for computing depletion, depreciation and amortization (DD&A) because they have not yet been capitalized as asset retirement costs under SFAS 143, such costs that will be incurred as a
result of future development activities on proved reserves should be estimated and included in the costs to be amortized. Our computation of DD&A is in compliance with the guidance in SAB 106. Our ceiling test calculation at December 31, 2004 is
in compliance with the guidance in SAB 106 and compliance with such guidelines in prior periods would not have resulted in a ceiling test writedown.



In December 2004 the FASB issued SFAS No.123R (revised 2004), Share-Based Payment (SFAS 123R). SFAS 123(R) requires that the compensation
cost relating to share-based payment transactions be recognized in financial statements. That cost will be measured based on the fair value of the equity or liability instruments issued. SFAS No. 123(R) covers a wide range of share-based
compensation arrangements including stock options, restricted stock plans, performance-based awards, stock appreciation rights, and employee stock purchase plans. SFAS 123(R) replaces FASB Statement No. 123, Accounting for Stock-Based
Compensation, and supersedes APB Opinion No. 25, Accounting for Stock Issued to Employees. Public entities (other than those filing as small business issuers) will be required to apply SFAS 123(R) as of the first interim or annual
reporting period that begins after June 15, 2005. We are in the process of determining how the new method of valuing stock-based compensation as prescribed in SFAS 123R will be applied to valuing stock-based awards and the impact the recognition of
compensation expense related to such awards will have on our financial statements.



In February 2005, the SEC issued guidance concerning the specific circumstance of a property disposition by a company that follows the full cost accounting method that resulted in a less than 25% alteration of the proved oil
and gas reserve quantities within a full cost center. In connection with that disposition, the SEC considered if goodwill should be allocated to the property disposed, and, if so, whether that allocated goodwill should remain as a component of the
capitalized full cost center or be reflected in the statement of operations.



The SEC concluded that only the fair value allocated to the oil and gas properties in a business acquisition should be included in the costs accounted for under Rule 4-10(c) of Regulation S-X. Goodwill associated with acquisitions of oil
and gas properties that constitute a business is recognized in accordance with FASB Statement No. 141, Business Combinations (SFAS 141) but accounted for outside of the full cost rules. Therefore, when dispositions of these properties occur,
the goodwill previously recognized does not affect the associated adjustments contemplated under Rule 4-10(c)(6)(i). Rather, the accounting for the goodwill and any potential impairment should follow the provisions of FASB Statement No. 142,
Goodwill and Other Intangible Assets(SFAS 142). Companies are required to consider whether a property disposition that results in a less than 25% alteration of the



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proved oil and gas reserve quantities within a given cost center is a trigger that requires goodwill be evaluated for impairment under SFAS 142. The SEC has not yet
addressed whether any portion of goodwill should be allocated to a disposition of greater than 25%, but less than 100%, of the oil and gas reserves in a given cost center.



We determined that the property dispositions completed in the fourth quarter of 2004 did not cause an impairment of goodwill. In the
first quarter of 2004, prior to the SEC guidance on this issue, we recorded a $2.4 million decrease in goodwill in connection with the sale of our Illinois properties and recognized this amount as an adjustment to oil and gas properties subject to
amortization.



Note 2Acquisitions



Nuevo Energy Company



On May 14, 2004 we acquired Nuevo in a stock-for-stock transaction (the Nuevo acquisition). In the Nuevo acquisition, each
outstanding share of Nuevo common stock was converted into 1.765 shares of PXP common stock and Nuevo became our wholly owned subsidiary. The Nuevo acquisition required the issuance of 36.5 million additional PXP common shares, plus the assumption
of $254 million in net debt and $115 million of $2.875 Term Convertible Securities, Series A, or TECONS. We have accounted for the Nuevo acquisition as a purchase effective May 14, 2004.



The calculation of the Nuevo acquisition purchase price and the allocation to assets and liabilities as of May 14, 2004 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 business days before the merger was announced.



|                                                            |  |                                  |          
|----------------------------------------------------------- |  | -------------------------------- | ---------
|                                                            |  | (in thousands,except shareprice)
|Shares of PXP common stock issued                           |  |                                  | 36,486   
|Average PXP stock price                                     |  | $                                | 15.76    
|                                                            |  |                                  |          
|Fair value of PXP common stock issued                       |  | $                                | 575,023  
|Fair value of Nuevo stock options assumed by Plains         |  |                                  | 4,389    
|Tender offer for Nuevo stock options                        |  |                                  | 17,056   
|Estimated merger expenses                                   |  |                                  | 36,652   
|                                                            |  |                                  |          
|Total estimated purchase price before liabilities assumed   |  |                                  | 633,120  
|Fair value of liabilities:                                  |  |                                  |          
|Senior Subordinated Notes                                   |  |                                  | 162,945  
|Bank Credit Facility                                        |  |                                  | 140,000  
|TECONS                                                      |  |                                  | 103,815  
|Current liabilities (1)                                     |  |                                  | 201,662  
|Other noncurrent liabilities                                |  |                                  | 33,583   
|Deferred income tax liabilities                             |  |                                  | 222,936  
|Asset retirement obligation                                 |  |                                  | 128,053  
|                                                            |  |                                  |          
|Total estimated purchase price plus liabilities assumed     |  | $                                | 1,626,114
|                                                            |  |                                  |          
|Fair value of assets acquired:                              |  |                                  |          
|Current assets (including deferred income taxes of $42,367) |  | $                                | 247,966  
|Oil and gas properties                                      |  |                                  |          
|Subject to amortization                                     |  |                                  | 1,208,020
|Not subject to amortization                                 |  |                                  | 137,457  
|Other noncurrent assets                                     |  |                                  | 7,248    
|Goodwill                                                    |  |                                  | 25,423   
|                                                            |  |                                  |          
|Total estimated fair value of assets acquired               |  | $                                | 1,626,114
|                                                            |  |                                  |          

| | 
| | 

| | (1) | $47,776,000 of accrued liabilities are included under the captions tender offer for Nuevo stock options and estimated merger expenses.
| | --- | --------------------------------------------------------------------------------------------------------------------------------------





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We acquired Nuevo to allow us to take advantage of the synergies that will result in significant cost savings and
because of the complementary nature of Nuevos assets and operations onshore and offshore California to our existing asset base. The allocation of purchase price includes $25.4 million of goodwill. The goodwill is related to deferred income tax
liabilities to be recorded due to the non-taxable nature of the merger. The allocation of purchase price to oil and gas properties is based on our estimate of the fair value of such properties on a discounted, after-tax basis. The goodwill is not
deductible for income tax purposes.



Under Section 43 of the Internal
Revenue Code of 1986 (as amended) and similar California tax rules, taxpayers may claim enhanced oil recovery (EOR) tax credits based on capital spending and lease operating expense of qualified projects. We have evaluated certain
projects that were operated by Nuevo to determine if they qualify for such credits. Based on our evaluation, we have or will amend certain federal and state income tax returns previously filed by Nuevo to claim EOR tax credits not previously claimed
by Nuevo. The credits are subject to various risks, including possible future legislative changes, possible phase out of the credit as a result of high crude oil prices, and audit positions that may be taken by taxing authorities. Our purchase price
allocation reflects $43.5 million with respect to these credits.



|3TEC | Energy Corporation
|---- | ------------------



On June 4, 2003, we acquired 3TEC (the 3TEC acquisition), for approximately $312.9 million in cash and common stock plus $90.0 million to retire
3TECs outstanding debt. 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 3TEC acquisition, 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 3TEC acquisition 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 business days before the merger was announced.



|                                                          |  |                                  |        
|--------------------------------------------------------- |  | -------------------------------- | -------
|                                                          |  | (in thousands,except shareprice)
|Shares of PXP common stock issued                         |  |                                  | 16,071 
|Average PXP stock price                                   |  | $                                | 9.47   
|                                                          |  |                                  |        
|Fair value of PXP common stock issued                     |  | $                                | 152,186
|Cash to 3TEC stockholders and warrantholders              |  |                                  | 160,720
|Estimated merger expenses                                 |  |                                  | 5,041  
|                                                          |  |                                  |        
|Total estimated purchase price before liabilities assumed |  |                                  | 317,947
|Fair value of liabilities:                                |  |                                  |        
|3TEC debt (including accrued interest)                    |  |                                  | 90,065 
|Current liabilities                                       |  |                                  | 73,342 
|Other noncurrent liabilities                              |  |                                  | 254    
|Deferred income tax liabilities                           |  |                                  | 40,281 
|Asset retirement obligation                               |  |                                  | 4,577  
|                                                          |  |                                  |        
|Total estimated purchase price plus liabilities assumed   |  | $                                | 526,466
|                                                          |  |                                  |        
|Fair value of assets acquired:                            |  |                                  |        
|Current assets                                            |  | $                                | 23,525 
|Oil and gas properties                                    |  |                                  |        
|Subject to amortization                                   |  |                                  | 294,356
|Not subject to amortization                               |  |                                  | 61,116 
|Other noncurrent assets                                   |  |                                  | 218    
|Goodwill                                                  |  |                                  | 147,251
|                                                          |  |                                  |        
|Total estimated fair value of assets acquired             |  | $                                | 526,466
|                                                          |  |                                  |        



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Prior to the acquisition, 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 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.



Pro Forma Information



The following unaudited pro forma information shows the proforma effect of the Nuevo acquisition, the issuance by PXP of $250 million of 7.125% Senior Notes due
2014 and the retirement of Nuevos 9 3/8% Senior Subordinated Notes and TECONS as discussed in Note 5, the sale of Nuevos Congo operations as discussed in Note 9, the 3TEC acquisition, and PXPs issuance of $75 million of 8.75%
senior subordinated notes on May 30, 2003. This unaudited pro forma information assumes the Nuevo acquisition, the issuance of the 7.125% Senior Notes and the sale of Nuevos Congo operations occurred on January 1 of the year presented. The
3TEC acquisition and the issuance of the $75 million of 8.75% senior subordinated notes are assumed to have occurred on January 1, 2003.



This unaudited pro forma information has been prepared based on our historical consolidated statements of income and the historical consolidated statements of
income of Nuevo and 3TEC. 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 EndedDecember 31,
|(in thousands, except per share data)                               |  | 2004                   |         | 2003
|Revenues                                                            |  | $                      | 806,637 |      | $ | 706,250
|Income from operations                                              |  |                        | 228,152 |      |   | 189,115
|Income (loss) from continuing operations                            |  |                        | 1,053   |      |   | 51,037 
|Discontinued operations and cumulative effect of accounting changes |  |                        |        |      |   | 26,575 
|Net income (loss)                                                   |  |                        | 1,053   |      |   | 77,612 
|Basic earnings per share                                            |  |                        |         |      |   |        
|Income (loss) from continuing operations                            |  | $                      | 0.01    |      | $ | 0.67   
|Discontinued operations and cumulative effect of accounting changes |  |                        |        |      |   | 0.35   
|Net income (loss)                                                   |  |                        | 0.01    |      |   | 1.02   
|Diluted earnings per share                                          |  |                        |         |      |   |        
|Income (loss) from continuing operations                            |  | $                      | 0.01    |      | $ | 0.66   
|Discontinued operations and cumulative effect of accounting changes |  |                        |        |      |   | 0.34   
|Net income (loss)                                                   |  |                        | 0.01    |      |   | 1.00   
|Weighted average shares outstanding                                 |  |                        |         |      |   |        
|Basic                                                               |  |                        | 76,902  |      |   | 76,686 
|Diluted                                                             |  |                        | 77,374  |      |   | 77,240 



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Income from continuing operations has been reduced by debt extinguishment costs of $14.0 million and $7.5 million
in year December 31, 2004 and 2003, respectively.



Note 3Derivative Instruments
and Hedging Activities



General



We actively manage our exposure to commodity price fluctuations by hedging portions of
our oil and gas production through the use of derivative instruments. The derivative instruments currently consist of oil and gas swaps, collars and option contracts entered into with financial institutions. Although certain of our derivatives do
not qualify for hedge accounting, we do not enter into derivative instruments for speculative trading purposes. 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 changes in fair value are recognized currently in our statement of operations as gain (loss) on mark-to-market derivative contracts. If a derivative is designated as a cash flow hedge and 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 until the sale of the hedged oil and gas production. Realized gains and losses on
derivative instruments that are designated as a hedge and qualify for hedge accounting are generally included in oil and gas revenues in the period the hedged volumes are sold. However, in the case of the derivatives acquired in connection with our
acquisitions of Nuevo and 3TEC, only changes in fair value subsequent to the acquisition date will be reflected in our oil and gas revenues.



We assumed certain liabilities related to open derivative positions in connection with the Nuevo acquisition. In accordance with SFAS 141 and supported by
Derivative Implementation Group, or DIG, issues related to SFAS 133 these derivative positions were recorded at fair value in the purchase price allocation as a liability of $132.5 million. The recognition of the derivative liability as do other
liabilities assumed in connection with the acquisition resulted in an increase in the total purchase price which is allocated to the assets acquired, including any goodwill. Because of this accounting treatment, only cash settlements for changes in
fair value subsequent to the acquisition date for the derivative positions assumed will result in adjustments to our oil and gas revenues upon settlement. For example, if the fair value of the derivative positions assumed do not change then upon the
sale of the underlying production and corresponding settlement of the derivative positions, cash would be paid to the counterparties and there would be no reduction to oil and gas revenues related to the derivative positions. If, however, the actual
sales price is different than the price assumed in the original fair value calculation the difference would be reflected as either a decrease or increase in oil and gas revenues, depending upon whether the sales price was higher or lower,
respectively, than the price assumed in the original fair value calculation.



Pursuant to SFAS 149 Amendment of SFAS 133 on Derivative Instruments and Hedging Activities, the derivative instruments assumed in connection with the Nuevo acquisition are deemed to contain a significant financing element and
all cash flows associated with these positions are reported as a financing activity in the statement of cash flows.



To qualify for hedge accounting, 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 in OCI 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.





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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.



Derivative Instruments Designated as Cash Flow
Hedges.



At December 31, 2004, we had the following open
commodity derivative positions designated as cash flow hedges:



|                         |  |             |  |                 |  |                |  |               |       |       |           
|------------------------ |  | ----------- |  | --------------- |  | -------------- |  | ------------- | ----- | ----- | ----------
|Period                   |  | Commodity   |  | Instrument Type |  | Daily Volumes  |  | Average Price |       | Index
|Sales of Production      |  |             |  |                 |  |                |  |               |       |       |           
|2005                     |  |             |  |                 |  |                |  |               |       |       |           
|1st Quarter              |  | Crude oil   |  | Swap            |  | 13,000/Barrels |  | $             | 25.82 |       | WTI       
|2nd Quarter              |  | Crude oil   |  | Swap            |  | 10,000/Barrels |  | $             | 25.80 |       | WTI       
|1st Quarter              |  | Natural gas |  | Swap            |  | 13,000/MMBtu   |  | $             | 4.75  |       | Waha Socal
|2nd Quarter              |  | Natural gas |  | Swap            |  | 9,500/MMBtu    |  | $             | 4.66  |       | Waha      
|3rd Quarter              |  | Natural gas |  | Swap            |  | 5,000/MMBtu    |  | $             | 4.40  |       | Waha      
|4th Quarter              |  | Natural gas |  | Swap            |  | 5,000/MMBtu    |  | $             | 4.40  |       | Waha      
|2006                     |  |             |  |                 |  |                |  |               |       |       |           
|January - December       |  | Crude oil   |  | Swap            |  | 15,000/Barrels |  | $             | 25.28 |       | WTI       
|Purchases of Natural Gas |  |             |  |                 |  |                |  |               |       |       |           
|2005                     |  |             |  |                 |  |                |  |               |       |       |           
|January - December       |  | Natural gas |  | Swap            |  | 8,000 /MMBtu   |  | $             | 3.85  |       | Socal     



Location and quality
differentials attributable to our properties are not included in the foregoing prices. Because of the quality and location of our oil and gas production, these adjustments will affect our net price.



Derivative Instruments Not Designated as Hedging Instruments.



In September 2004 we entered into new oil price collars for the period 2005 through
2008 and eliminated approximately 80% of our 2005 fixed price crude oil swaps. We exchanged existing 2005 oil price swaps with respect to 22,000 barrels of oil per day at an average price of $24.25 for new oil price collars relating to 22,000
barrels of oil per day during the period 2005 through 2008 that have a floor price of $25.00 and an average ceiling price of $34.76.



The new collars do not qualify for hedge accounting because they incorporate a net liability position associated with the cancelled swaps. As a result, changes to
the market value of the collars will be recorded on the income statement as gain (loss) on mark-to-market derivative contracts. Any cash flow impact associated with the new collars are reported as a financing activity in the statement of cash flows
rather than an operating cash flow because the collars are deemed to contain a significant financing element. OCI at December 31, 2004 includes $106.2 million ($65.5 million after tax) of deferred losses representing the mark-to-market value of the
cancelled 2005 swaps as of the date of the restructuring. These deferred losses will remain in OCI until the hedged production is delivered during 2005, at which time they will be recognized as a reduction to oil revenues.



The restructured collars discussed above as well as certain other commodity derivative
contracts to which we are a party, do not qualify for hedge accounting. Consequently, these contracts are



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marked-to-market each quarter with changes in fair value recognized currently as gain (loss) on mark-to-market derivative contracts in the statement of operations.
Cash flow is only impacted to the extent the actual settlements under the contracts result in making or receiving a payment from the counterparty. During the years ended December 31, 2004 and 2003 we recognized pre-tax losses of $150.3 million and
pre-tax income of $0.8 million, respectively, from derivatives that do not qualify for hedge accounting.



At December 31, 2004, we had the following open commodity derivative positions that were not designated as hedging instruments:



|                    |  |           |  |                 |  |                |  |                               |  |      
|------------------- |  | --------- |  | --------------- |  | -------------- |  | ----------------------------- |  | -----
|Period              |  | Commodity |  | Instrument Type |  | Daily Volumes  |  | Average Price                 |  | Index
|Sales of Production |  |           |  |                 |  |                |  |                              
|2005                |  |           |  |                 |  |                |  |                               |  |      
|1st Quarter         |  | Crude oil |  | Collar          |  | 4,300/Barrels  |  | $27.00 Floor - $31.75 Ceiling |  | WTI  
|2nd Quarter         |  | Crude oil |  | Collar          |  | 6,800/Barrels  |  | $27.00 Floor - $30.40 Ceiling |  | WTI  
|3rd Quarter         |  | Crude oil |  | Collar          |  | 14,400/Barrels |  | $26.00 Floor - $30.03 Ceiling |  | WTI  
|4th Quarter         |  | Crude oil |  | Collar          |  | 14,000/Barrels |  | $26.00 Floor - $29.33 Ceiling |  | WTI  
|January - December  |  | Crude oil |  | Collar          |  | 22,000/Barrels |  | $25.00 Floor - $34.76 Ceiling |  | WTI  
|2006                |  |           |  |                 |  |                |  |                               |  |      
|January - December  |  | Crude oil |  | Collar          |  | 22,000/Barrels |  | $25.00 Floor - $34.76 Ceiling |  | WTI  
|2007                |  |           |  |                 |  |                |  |                               |  |      
|January - December  |  | Crude oil |  | Collar          |  | 22,000/Barrels |  | $25.00 Floor - $34.76 Ceiling |  | WTI  
|2008                |  |           |  |                 |  |                |  |                               |  |      
|January - December  |  | Crude oil |  | Collar          |  | 22,000/Barrels |  | $25.00 Floor - $34.76 Ceiling |  | WTI  



Physical Purchase
Contracts.



Although not a derivative, at December 31, 2004 we
also have the following contracts for the purchase of natural gas utilized in our steam flood operations:



|                         |  |             |  |                   |  |               |  |               |      |       |      
|------------------------ |  | ----------- |  | ----------------- |  | ------------- |  | ------------- | ---- | ----- | -----
|Period                   |  | Commodity   |  | Instrument Type   |  | Daily Volumes |  | Average Price |      | Index
|Purchases of Natural Gas |  |             |  |                   |  |               |  |               |      |       |      
|2005                     |  |             |  |                   |  |               |  |               |      |       |      
|January - December       |  | Natural gas |  | Physical purchase |  | 10,000/MMBtu  |  | $             | 4.19 |       | Socal



Other Comprehensive
Income.



At December 31, 2004, OCI consisted of $200.9 million
($123.9 million after tax) of unrealized losses on our open hedging instruments, including $106.2 million ($65.5 million, net of tax) of deferred losses representing the mark-to-market value of the cancelled 2005 swaps as of the date of the
restructuring. 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, 2002, OCI consisted of $20.9 million ($12.6 million after tax) of unrealized losses on our open hedging instruments, $0.3 million ($0.2 million, net of tax) loss
related to our interest rate swap and $0.2 million ($0.1 million, net of tax) loss related to deferred compensation liabilities.



During 2004, 2003 and 2002, deferred losses for cash flow hedges of $153.0 million (including $1.3 million for ineffectiveness), $37.6 million and $14.7 million,
respectively, were reclassified from OCI and charged to income as a reduction of oil and gas sales revenues and steam gas costs. During the year ended December 31, 2005, based on estimates of future commodity prices as of



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December 31, 2004, we expect to reclassify $15.9 million of net deferred losses associated with open derivative contracts and $106.2 million of net deferred
losses on terminated derivative contracts from OCI to oil and gas revenue. Also during such period, we expect to reclassify approximately $46.8 million of deferred income tax benefits from OCI to income tax expense. The amounts ultimately
reclassified to earnings will vary due to changes in the fair value of the open derivative contracts prior to settlement. The net deferred losses associated with terminated derivative contracts that will be recognized as a reduction in our 2005 oil
and gas revenues as follows: first quarter$29.1 million, second quarter$27.3 million, third quarter$25.7 million and fourth quarter$24.1 million.



Note 4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. Prior to the adoption of SFAS 143 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.



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 reflects the changes in our asset retirement obligation during the period (in thousands):



|                                                |  |                         |         |   |      |   |        |      |  |   |       
|----------------------------------------------- |  | ----------------------- | ------- | - | ---- | - | ------ | ---- |  | - | ------
|                                                |  | Year Ended December 31,
|                                                |  | 2004                    |         |   | 2003 |   |        | 2002
|                                                |  | Pro forma              
|Asset retirement obligationbeginning of period |  | $                       | 33,735  |   |      | $ | 26,540 |      |  | $ | 21,008
|Liabilities incurred                            |  |                         |         |   |      |   |        |      |  |   |       
|Nuevo acquisition                               |  |                         | 128,053 |   |      |   |       |      |  |   |      
|3TEC acquisition                                |  |                         |        |   |      |   | 4,577  |      |  |   |      
|Property dispositions and other                 |  |                         | (38,717 | ) |      |   | (469   | )    |  |   | 3,630 
|Settlements                                     |  |                         | (218    | ) |      |   | (415   | )    |  |   |      
|Change in estimate                              |  |                         | (2,184  | ) |      |   |       |      |  |   |      
|Accretion expense                               |  |                         | 8,563   |   |      |   | 2,637  |      |  |   | 1,902 
|Asset retirement additions                      |  |                         | 1,237   |   |      |   | 865    |      |  |   |      
|                                                |  |                         |         |   |      |   |        |      |  |   |       
|Asset retirement obligationend of period (1)   |  | $                       | 130,469 |   |      | $ | 33,735 |      |  | $ | 26,540
|                                                |  |                         |         |   |      |   |        |      |  |   |       

---

|(1) | $3.6 million and $0.5 million included in current liabilities for 2004 and 2003, respectively.
|--- | ----------------------------------------------------------------------------------------------



If SFAS 143 had been applied during the year ended December 31, 2002, on a pro forma basis our reported net income for such year would
have increased by $1.2 million, or $0.05 per share (basic and diluted).



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Note 5Long-Term Debt



At December 31, 2004 and 2003, long-term debt consisted of (in thousands):



|                                                                                                                |  |                   |   |                   |   |         |  |           |     |  |   |        
|--------------------------------------------------------------------------------------------------------------- |  | ----------------- | - | ----------------- | - | ------- |  | --------- | --- |  | - | -------
|                                                                                                                |  | December 31, 2004 |   | December 31, 2003
|                                                                                                                |  | Current           |   | Long-Term         |   | Current |  | Long-Term
|Revolving credit facility                                                                                       |  | $                 |  |                   | $ | 110,000 |  | $         |    |  | $ | 211,000
|8.75% senior subordinated notes, including unamortized premium of $1.7 million in 2003 and $1.9 million in 2003 |  |                   |  |                   |   | 276,727 |  |           |    |  |   | 276,906
|7.125% senior notes, including unamortized discount of $1.3 million                                             |  |                   |  |                   |   | 248,741 |  |           |    |  |   |       
|Other                                                                                                           |  |                   |  |                   |   |        |  |           | 511 |  |   |       
|                                                                                                                |  |                   |   |                   |   |         |  |           |     |  |   |        
|                                                                                                                |  | $                 |  |                   | $ | 635,468 |  | $         | 511 |  | $ | 487,906
|                                                                                                                |  |                   |   |                   |   |         |  |           |     |  |   |        



Aggregate total maturities of
long-term debt in the next five years are as follows: 2005$0.0 million; 2006$0.0 million; 2007$110.0 million; 2008$0.0 million; 2009$0.0 million.



In connection with our acquisition of Nuevo, we completed a series of steps described below to refinance a portion of our and all of
Nuevos outstanding debt (the Recapitalization Transactions). In connection with the Recapitalization Transactions we recognized a $19.7 million pre-tax loss on early extinguishment of debt in 2004.



Senior Revolving Credit Facility.    In May 2004 we amended
our three-year, $500 million senior revolving credit facility, or credit facility, with a group of lenders and with JPMorgan Chase Bank serving as administrative agent. This credit facility provides for a current borrowing base of $600 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. The credit facility has commitments for up to $500 million in borrowings. Additionally, the credit facility contains a $50.0 million sub-limit on letters of credit. This amended credit facility matures on April 4, 2007. To secure
borrowings, we pledged 100% of the shares of stock of our domestic subsidiaries and gave mortgages covering at least 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,
which is based on LIBOR, plus a margin ranging from 1.25% to 1.875%; 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 variable amount ranging from 0% to 0.625% for each of (1)-(3). The additional variable 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 0.3% to 0.5%
of the amount available for borrowing. Letter of credit fees range from 1.25% to 1.875%. The issuer of any letter of credit receives an issuing fee of 0.125% of the undrawn amount. The effective interest rate on our borrowings under this revolving
credit facility was 3.6% at December 31, 2004.



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, guarantee other indebtedness, enter into agreements that restrict dividends from



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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 under the credit facility, of at least 1.0 to 1.0 and a minimum tangible net worth requirement.



At December 31, 2004, we had $110.0 million in borrowings and $6.9 million in letters
of credit outstanding under the credit facility. At that date we were in compliance with the covenants contained in the credit facility and could have borrowed the full amount available under the credit facility.



$250 Million Senior Notes Offering.    On June 30, 2004 we
completed the private placement under Rule 144A and Regulation S of the Securities Act of 1933 of $250 million in aggregate principal amount of ten year senior unsecured notes (the 7.125% Notes). The 7.125% Notes were issued at 99.478%
and bear interest at 7.125% with a yield to maturity of 7.2%. Proceeds from the 7.125% Notes plus borrowings under our credit facility were used to repurchase Nuevos 9 3/8% senior subordinated notes due 2010 (the 9 3/8% Notes), and redeem
Nuevos 5.75% convertible subordinated debentures due December 15, 2026 (which resulted in the redemption of the outstanding $2.875 term convertible securities, Series A, issued by a financing trust owned by Nuevo). In October 2004 we completed
an exchange of the 7.125% Notes issued in June for 7.125% Notes with substantially identical terms except that they are freely transferable and free of any covenants regarding exchange and registration rights.



The 7.125% Notes and subsidiary guarantees are senior obligations of ours and our
subsidiary guarantors. Accordingly, they rank:



| |  |  | pari passu in right of payment to our and our subsidiary guarantors existing and future senior unsecured indebtedness;
| | - |  | -----------------------------------------------------------------------------------------------------------------------



| |  |  | senior in right of payment to our and our subsidiary guarantors existing and future subordinated indebtedness;
| | - |  | ---------------------------------------------------------------------------------------------------------------



| |  |  | effectively junior in right of payment to our and our subsidiary guarantors senior secured indebtedness to the extent of the value of the collateral securing that indebtedness; and
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | effectively subordinated in right of payment to all existing and future indebtedness and other liabilities of non-guarantor subsidiaries (other than indebtedness and other liabilities owed to
us, if any).
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



The indenture governing the 7.125% 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, pay dividends, or make other distributions on capital stock or redeem or
repurchase capital stock or subordinated indebtedness, sell assets, incur dividends or 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.



On and after June 15, 2009, we may redeem all or part of
the 7.125% Notes at our option, at 103.563% of the principal amount for the twelve-month period beginning June 15, 2009, at 102.375% of the principal amount for the twelve-month period beginning June 15, 2010, at 101.188% of the principal amount for
the twelve-month period beginning June 15, 2011 and at 100% of the principal amount thereafter. In each case, accrued interest is payable to the date of redemption. In addition, before June 15, 2009, we may redeem all or part of the 7.125% Notes at
the make-whole price set forth under the indenture. At any time prior to June 15, 2007, we may redeem up to 35% of the 7.125% Notes with the net cash proceeds of certain equity offerings at the redemption price set forth under the indenture.



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Tender Offer for Nuevos 9 3/8% Senior Subordinated Notes due 2010.    On June 30,
2004, Nuevo completed the repurchase of all $150 million of its outstanding 9 3/8% Senior Subordinated Notes. Nuevo paid $1,150.08 per $1,000 principal amount of 9 3/8% Notes tendered (comprising the tender offer price of $1,107.16, plus accrued
interest through June 29, 2004 of $22.92, plus the consent payment of $20.00). The tender offer and consent payment totaled $169.1 million.



Nuevo had an interest rate swap with a notional amount of $100.0 million to hedge a portion of the fair value of the 9 3/8% Notes which was cancelled for total
consideration of $1.7 million.



Redemption of
TECONS.    On June 30, 2004, Nuevo completed the redemption of all outstanding $118 million aggregate principal amount of its 5.75% Convertible Subordinated Debentures due December 15, 2026 (the TECON Debentures),
the proceeds of which were used by Nuevos wholly controlled financing trust to redeem all of the trusts outstanding $115.0 million of TECONS for total consideration of $117.0 million, which were publicly held, and all outstanding $3.0
million of $2.875 term convertible securities held by Nuevo.



Consent Solicitation for Our 8.75% Senior Subordinated Notes.    We solicited consents from the holders of our 8.75% Senior Subordinated Notes due 2012 (the 8.75% Notes) to amend the indenture under
which the 8.75% Notes were issued to make certain provisions more consistent with the indenture under which the 7.125% Notes were issued. The consent solicitation expired on June 18, 2004 and, having received the requisite consents, we executed an
amended and restated indenture governing the 8.75% Notes, reflecting among other things, the changes for which consent was requested from the bond holders. We paid a consent payment of $7.50 per $1,000 of principal amount to holders of the 8.75%
Notes ($2.1 million).



At December 31, 2004, 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 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. 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.



Short-term Credit Facility.    In August 2004 we entered into an uncommitted short-term credit facility with a bank under which we may make borrowings from time to time until August 14, 2005, not to exceed at any
time the maximum principal amount of $15.0 million. No advance under the short-term facility may have a term exceeding fourteen days and all amounts outstanding are due and payable no later than August 15, 2005. Each advance under the short-term
facility shall bear interest at a rate per annum mutually agreed on by the bank and the Company. At all times an advance is outstanding, the Company must have $100 million in availability under its senior revolving credit facility. No amounts were
outstanding under the short-term credit facility at December 31, 2004.



Note
6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 year



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ended December 31, 2002 we were charged $10.7 million of interest on amounts payable to Plains Resources. Of such amount, $9.3 million was included in interest expense
and $1.4 million was capitalized in oil and gas properties.



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 year ended December 31, 2002 totaled $4.4 million. Of
such amount, $3.1 million was included in general and administrative expense and $1.3 million was capitalized in oil and gas properties.



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.



Our Chief Executive Officer is a director of Vulcan Energy Corporation (formerly known as Plains Resources). In connection with the reorganization and the spin-off
we entered into certain agreements with Plains Resources, including a master separation agreement; the Plains Exploration & Production transition services agreement that expired June 16, 2004; the Plains Resources transition services agreement
that expired June 8, 2004; and a technical services agreement that expired June 30, 2004. For the year ended December 31, 2004 we billed Plains Resources $0.4 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. In addition, for the year ended December 31, 2004 we billed Plains Resources $0.2 million for administrative costs associated with certain special projects performed on their
behalf. 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.



In June 2004, based on third party valuations the Company acquired two aircraft from
Cypress Aviation LLC (Cypress), for $4.5 million. Our Chief Executive Officer is a member of Cypress. Prior to acquiring the aircraft, we chartered private aircraft from Gulf Coast Aviation Inc. (Gulf Coast), a corporation
that from time-to-time leased aircraft owned by Cypress. In 2004, 2003 and 2002, we paid Gulf Coast $0.5 million, $0.8 million and $0.2 million, respectively, in connection with such services. The charter services were arranged with market-based
rates.



Plains All American Pipeline, L.P. (PAA), a publicly
traded master limited partnership, is an affiliate of Plains Resources. PAA is the marketer/purchaser for a significant portion of our oil production, including the royalty share of production. The marketing agreement provides that PAA will purchase
for resale at market prices certain of our oil production for which PAA charges a marketing fee of either $0.20 or $0.15 per barrel based upon the contract the barrels are resold under. During the years ended December 31, 2004, 2003 and 2002, the
following amounts were recorded with respect to such transactions (in thousands of dollars):



|                               |  |                         |         |      |   |         |  |   |        
|------------------------------ |  | ----------------------- | ------- | ---- | - | ------- |  | - | -------
|                               |  | Year Ended December 31,
|                               |  | 2004                    |         | 2003 |   | 2002   
|Sales of oil to PAA            |  |                         |         |      |   |         |  |   |        
|PXPs share                    |  | $                       | 274,447 |      | $ | 238,663 |  | $ | 193,615
|Royalty owners share          |  |                         | 54,208  |      |   | 45,703  |  |   | 35,969 
|                               |  |                         |         |      |   |         |  |   |        
|                               |  | $                       | 328,655 |      | $ | 284,366 |  | $ | 229,584
|                               |  |                         |         |      |   |         |  |   |        
|Charges for PAA marketing fees |  | $                       | 1,427   |      | $ | 1,728   |  | $ | 1,633  
|                               |  |                         |         |      |   |         |  |   |        



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Note 7Stock and Other Compensation Plans



In 2002 we adopted our 2002 Stock Incentive Plan (the 2002 Plan), 2002 Rollover Stock Incentive Plan
(Rollover) and 2002 Transition Stock Incentive Plan (Transition). A total of 210,000 restricted shares were granted under the Rollover and Transition Plans. In June 2003, our stockholders approved an amendment to the 2002
Stock Incentive Plan to increase the number available for issuance under the plan from 500,000 to 1,500,000 shares. In May 2004 our stockholders approved our 2004 Stock Incentive Plan (the 2004 Plan) which provides for a maximum of
5,000,000 shares available for options and awards.



The 2002 Plan and the
2004 Plan provide for the grant of stock options, and other awards (including performance units, performance shares, share awards, restricted stock, restricted stock units, and stock appreciation rights, or SARs) to our directors, officers,
employees, consultants and advisors. Our compensation committee may grant options and SARs on such terms, including vesting and payment forms, as it deems appropriate in its discretion, however, no option or SAR may be exercised more than 10 years
after its grant, and the purchase price for incentive stock options and non-qualified stock options may not be less than 100% of the fair market value of our common stock on the date of grant. The compensation committee may grant restricted stock
awards, restricted stock units, share awards, performance units and performance shares on such terms and conditions as it may in its discretion decide.



At the time of the spin-off all individuals holding outstanding options to acquire Plains Resources common stock were granted an equal number of SARs. The exercise
price of the SARs was based on the exercise price of the Plains Resources options, as adjusted. The SARs had the same amount of vesting as the related Plains Resources stock options and vesting terms remained unchanged. Generally, the SARs had a pro
rata vesting period of two to five years and an exercise period of five to ten years.



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 2004, 2003 and 2002 we recognized charges of $35.5 million, $18.0 million and $3.7
million, respectively, as compensation expense with respect to SARs vested or deemed vested during the periods. The 2004 and 2003 amounts include cash payments with respect to SARs exercised of $15.2 million and $2.1 million, respectively.



A summary of the status of our SARs as of December 31, 2004, 2003 and
2002 and changes during the years ending on those dates are presented below (shares in thousands):



|                                 |  |        |   |      |                              |       |      |       |   |                              |   |       |  |                              |  |   |     
|-------------------------------- |  | ------ | - | ---- | ---------------------------- | ----- | ---- | ----- | - | ---------------------------- | - | ----- |  | ---------------------------- |  | - | ----
|                                 |  | 2004   |   | 2003 |                              | 2002 
|                                 |  | SARs   |   |      | WeightedAverageExercisePrice |       | SARs |       |   | WeightedAverageExercisePrice |   | SARs  |  | WeightedAverageExercisePrice
|Outstanding at beginning of year |  | 3,933  |   |      | $                            | 9.25  |      | 4,047 |   |                              | $ | 8.68  |  |                             |  | $ |    
|Granted                          |  | 352    |   |      |                              | 16.32 |      | 489   |   |                              |   | 11.27 |  | 4,047                        |  |   | 8.68
|Exercised                        |  | (1,440 | ) |      |                              | 9.22  |      | (404  | ) |                              |   | 6.05  |  |                             |  |   |    
|Forfeited                        |  | (79    | ) |      |                              | 11.57 |      | (199  | ) |                              |   | 9.13  |  |                             |  |   |    
|                                 |  |        |   |      |                              |       |      |       |   |                              |   |       |  |                              |  |   |     
|Outstanding at end of year       |  | 2,766  |   |      | $                            | 10.10 |      | 3,933 |   |                              | $ | 9.25  |  | 4,047                        |  | $ | 8.68
|                                 |  |        |   |      |                              |       |      |       |   |                              |   |       |  |                              |  |   |     
|SARs exercisable at year-end     |  | 1,794  |   |      | $                            | 8.90  |      | 1,992 |   |                              | $ | 8.76  |  | 1,491                        |  | $ | 7.86
|                                 |  |        |   |      |                              |       |      |       |   |                              |   |       |  |                              |  |   |     



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The following table reflects the SARs
outstanding at December 31, 2004 (share amounts in thousands):



|                       |  |                              |  |                                          |  |                              |       |                              |       |                              |   |      
|---------------------- |  | ---------------------------- |  | ---------------------------------------- |  | ---------------------------- | ----- | ---------------------------- | ----- | ---------------------------- | - | -----
|Range ofExercise Price |  | NumberOutstandingat 12/31/04 |  | WeightedAverageRemainingContractual Life |  | WeightedAverageExercisePrice |       | NumberExercisableat 12/31/04 |       | WeightedAverageExercisePrice
|$  2.46-$8.33          |  | 177                          |  | 0.48 years                               |  | $                            | 5.05  |                              | 175   |                              | $ | 5.02 
|9.08-  9.08            |  | 1,000                        |  | 6.35 years                               |  |                              | 9.08  |                              | 1,000 |                              |   | 9.08 
|9.10-  9.10            |  | 200                          |  | 2.67 years                               |  |                              | 9.10  |                              | 100   |                              |   | 9.10 
|9.36-  9.36            |  | 290                          |  | 2.14 years                               |  |                              | 9.36  |                              | 136   |                              |   | 9.36 
|9.37-  9.76            |  | 309                          |  | 1.46 years                               |  |                              | 9.46  |                              | 221   |                              |   | 9.48 
|9.97-10.59             |  | 284                          |  | 3.11 years                               |  |                              | 10.46 |                              | 134   |                              |   | 10.45
|10.60-13.64            |  | 170                          |  | 3.66 years                               |  |                              | 12.07 |                              | 28    |                              |   | 11.84
|15.63-15.63            |  | 282                          |  | 4.13 years                               |  |                              | 15.63 |                              |      |                              |   |     
|17.20-23.86            |  | 49                           |  | 4.50 years                               |  |                              | 19.65 |                              |      |                              |   |     
|24.68-24.68            |  | 5                            |  | 4.80 years                               |  |                              | 24.68 |                              |      |                              |   |     
|                       |  |                              |  |                                          |  |                              |       |                              |       |                              |   |      
|2.46-24.68             |  | 2,766                        |  | 3.96 years                               |  | $                            | 10.10 |                              | 1,794 |                              | $ | 8.90 
|                       |  |                              |  |                                          |  |                              |       |                              |       |                              |   |      



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.
Approximately 1.3 million of our restricted stock units have a provision for accelerated vesting if the closing price of our common stock is equal to or greater than $37.92 per share for any ten of twenty consecutive trading days.



A summary of the status of our restricted stock and restricted stock units as of
December 31, 2004, 2003 and 2002 and changes during the years ending on those dates are presented below (shares in thousands):



|                                                 |  |              |       |   |      |   |       |      |  |   |     
|------------------------------------------------ |  | ------------ | ----- | - | ---- | - | ----- | ---- |  | - | ----
|                                                 |  | December 31,
|                                                 |  | 2004         |       |   | 2003 |   |       | 2002
|Outstanding at beginning of year                 |  |              | 523   |   |      |   | 210   |      |  |   |    
|Granted                                          |  |              | 1,600 |   |      |   | 455   |      |  |   | 210 
|Released                                         |  |              | (328  | ) |      |   | (107  | )    |  |   |    
|Cancelled                                        |  |              | (13   | ) |      |   | (35   | )    |  |   |    
|                                                 |  |              |       |   |      |   |       |      |  |   |     
|Outstanding at end of year                       |  |              | 1,782 |   |      |   | 523   |      |  |   | 210 
|                                                 |  |              |       |   |      |   |       |      |  |   |     
|Weighted average grant date fair value per share |  | $            | 17.31 |   |      | $ | 10.74 |      |  | $ | 9.86
|                                                 |  |              |       |   |      |   |       |      |  |   |     



During 2004 and 2003 we
recognized total compensation of $9.1 million and $2.9 million, respectively, related to our restricted stock and restricted stock unit grants.



As a result of the Nuevo acquisition, we converted certain of Nuevos outstanding stock options to options on our common stock. At December 31, 2004 there were
420,233 options outstanding with an average exercise price of $16.13 per share and an average remaining life of 3.3 years.



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 2004 and 2003 we made contributions totaling $3.5 million and $2.0 million, respectively, to the
401(k) plan.



Note 8Income Taxes



Until the date of the spin-off on December 18, 2002, our taxable income or loss was
included in the consolidated income tax returns filed by Plains Resources. Income tax obligations reflected in



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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, 2004 and 2003 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, |         
|                                                             |  | 2004         |          |   | 2003 |  
|U.S. Federal                                                 |  |              |          |   |      |   |          |  
|Deferred tax assets:                                         |  |              |          |   |      |   |          |  
|Net operating loss                                           |  | $            | 38,301   |   |      | $ | 2,952    |  
|Tax Credits                                                  |  |              | 53,718   |   |      |   | 6,038    |  
|Commodity hedging contracts and other                        |  |              | 130,424  |   |      |   | 21,879   |  
|                                                             |  |              |          |   |      |   |          |  
|                                                             |  |              | 222,443  |   |      |   | 30,869   |  
|                                                             |  |              |          |   |      |   |          |  
|Deferred tax liabilities:                                    |  |              |          |   |      |   |          |  
|Net oil & gas acquisition, exploration and development costs |  |              | (434,513 | ) |      |   | (124,269 | )
|                                                             |  |              |          |   |      |   |          |  
|Net U.S. Federal deferred tax asset (liability)              |  |              | (212,070 | ) |      |   | (93,400  | )
|States                                                       |  |              |          |   |      |   |          |  
|Deferred tax liability, net                                  |  |              | (30,590  | ) |      |   | (28,035  | )
|                                                             |  |              |          |   |      |   |          |  
|Net deferred tax assets (liability)                          |  | $            | (242,660 | ) |      | $ | (121,435 | )
|                                                             |  |              |          |   |      |   |          |  
|Current asset                                                |  | $            | 76,823   |   |      | $ | 28,156   |  
|Long-term liability                                          |  |              | (319,483 | ) |      |   | (149,591 | )
|                                                             |  |              |          |   |      |   |          |  
|                                                             |  | $            | (242,660 | ) |      | $ | 121,435  |  
|                                                             |  |              |          |   |      |   |          |  



Tax carryforwards at December
31, 2004, which are available for future utilization on income tax returns, are as follows (in thousands):



|                                     |  |        |         |            |          
|------------------------------------ |  | ------ | ------- | ---------- | ---------
|FEDERAL                              |  | Amount |         | Expiration
|Alternative minimum tax (AMT) credit |  | $      | 4,904   |            |         
|EOR credit                           |  |        | 56,136  |            | 2020-2024
|Net Operating Lossregular Tax       |  |        | 109,608 |            | 2018-2023
|Net Operating LossAMT Tax           |  |        | 70,561  |            | 2018-2023
|                                     |  |       
|STATE                                |  |        |         |           
|Alternative minimum tax (AMT) credit |  | $      | 106     |            |         
|EOR credit                           |  |        | 20,815  |            | 2014-2019
|Net Operating Lossregular Tax       |  |        | 2,016   |            | 2010-2013
|Net Operating LossAMT Tax           |  |        | 3,830   |            | 2010-2013



The tax attributes related to
the purchase of Nuevo are subject to statutory limitation under Internal Revenue Code Section 382 on the amount that can be used each year. We do not expect the limitation to materially impact our ability to use such attributes.



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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 income (in thousands):



|                                                                                                      |  |                         |        |   |      |   |        |      |  |   |        |  
|----------------------------------------------------------------------------------------------------- |  | ----------------------- | ------ | - | ---- | - | ------ | ---- |  | - | ------ | -
|                                                                                                      |  | Year Ended December 31, |       
|                                                                                                      |  | 2004                    |        |   | 2003 |   |        | 2002 | 
|U.S. federal income tax provision at statutory rate                                                   |  | $                       | 708    |   |      | $ | 35,253 |      |  | $ | 15,039 |  
|State income taxes, net of federal benefit                                                            |  |                         | 788    |   |      |   | 5,512  |      |  |   | 2,409  |  
|EOR credits                                                                                           |  |                         | (9,547 | ) |      |   | (828   | )    |  |   | (412   | )
|Other                                                                                                 |  |                         | 1,234  |   |      |   | 1,375  |      |  |   | (304   | )
|                                                                                                      |  |                         |        |   |      |   |        |      |  |   |        |  
|Income tax expense (benefit) on income before income taxes and cumulative effect of accounting change |  |                         | (6,817 | ) |      |   | 41,312 |      |  |   | 16,732 |  
|Income tax benefit allocated to cumulative effect of accounting change                                |  |                         |       |   |      |   | (7,860 | )    |  |   |       |  
|                                                                                                      |  |                         |        |   |      |   |        |      |  |   |        |  
|Income tax provision                                                                                  |  | $                       | (6,817 | ) |      | $ | 33,452 |      |  | $ | 16,732 |  
|                                                                                                      |  |                         |        |   |      |   |        |      |  |   |        |  



A deferred tax benefit related
to non-cash employee compensation of $1.2 million and $0.2 million was allocated directly to additional paid-in capital for 2004 and 2003, respectively.



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 a 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.



The
Company has determined that EOR tax credits are available for 2004 and certain prior tax years of Nuevo Energy Company. EOR tax credits reduce the Companys tax liability down to its alternative minimum tax liability. EOR tax credits are
subject to a phase-out according to the level of average domestic crude prices. No phase-out occurred in 2004.



Note 9Property Divestments



We
periodically evaluate and from time to time have elected to sell certain of our mature producing properties that we consider to be nonstrategic. In December 2004, we completed the sale of certain properties located offshore California and onshore
South Texas, New Mexico, and South Louisiana. These divestments were conducted via negotiated and auction transactions and we received net proceeds of approximately $153 million. In a series of transactions in the first and second quarters of 2004
we sold our interests in certain non-core producing properties in New Mexico, Texas, Mississippi, Louisiana, and Illinois for proceeds of approximately $28 million. 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 million.



During the second and third quarters of 2004, we sold certain real estate parcels
acquired in the Nuevo merger and received aggregate proceeds of approximately $4 million. The properties represented approximately 609 surface acres located in Santa Barbara and Los Angeles counties in California.





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In April 2004, Nuevo entered into definitive agreements for the sale of the stock of its subsidiaries that held oil
and gas interests in the Republic of Congo. The sale closed on July 30, 2004 and we received net cash consideration of approximately $54 million. When we acquired Nuevo, the fair value of the investment in the Congo operations was accounted for as
an asset held for sale.



In December 2003, Nuevo sold its Tonner Hills
residential development property for approximately $47.0 million. To date $40.7 million of the purchase price has been received and the remainder is due upon completion of certain habitat restoration activities. The fair value of our investment in
the property is reflected on the balance sheet in current assets under the caption assets held for sale. The $40.7 million that has been received to date is reflected on the balance sheet in current liabilities, as these amounts are accounted for as
deposits until the completion of the habitat restoration activities.



Note
10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):



|           |  |   |      
|---------- |  | - | -----
|2005       |  | $ | 4,704
|2006       |  |   | 3,829
|2007       |  |   | 3,267
|2008       |  |   | 3,126
|2009       |  |   | 2,411
|Thereafter |  |   | 7,540



Total expenses related to such
leases were $3.7 million, $2.2 million and less than $0.1 million in 2004, 2003 and 2002, respectively.



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. 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.



In January 2005 we discovered and self-reported a
violation related to flared gas emissions in excess of permitted levels on properties acquired in the Nuevo acquisition. Estimated excess emissions from the San Joaquin Valley casing vent recovery system located on the Gamble Lease are approximately
881 tons over a 745 day period. We brought the facility into compliance within 10 days of discovering the violation.



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. There can be no assurance that we will be able to
collect on these indemnities.



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In connection with the sale of certain properties offshore California in December 2004 we retained the
responsibility for certain abandonment costs, including removing, dismantling and disposing of the existing offshore platforms. The present value of such abandonment costs, $35.0 million ($65.2 million undiscounted), are included in our asset
retirement obligation as reflected on our consolidated balance sheet. In addition, we agreed to guarantee the performance of the purchaser with respect to the remaining abandonment obligations related to the properties (approximately $44 million).



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.



Sale of Nuevos Congo operations.    Upon our acquisition of Nuevo, we became a party to an existing
agreement between Nuevo, CMS NOMECO Oil & Gas Co. (CMS) and a third party. Under the agreement, Nuevo and CMS may be liable to the third party for the recapture of dual consolidated losses (DCLs) in connection with each companys 1995
acquisition of Congolese properties. Nuevo and CMS agreed to indemnify each other for any act that would cause the third party to experience a liability from the recapture of DCLs as a result of a triggering event.



CMS sold its interest in the Congolese properties to a subsidiary of Perenco, S.A.
(Perenco) in 2002. The sale did not trigger recapture, as both CMS and Perenco filed a request for a closing agreement with the Internal Revenue Service (IRS) in accordance with the U.S consolidated return regulations. Similarly, we do not expect
that our merger with Nuevo, nor the sale of our interest in the Congolese properties to Perenco will trigger recapture. We, along with Perenco and the IRS, expect to finalize two closing agreements in the near future. The estimated remaining
contingent liabilities are $19.2 million relative to Nuevos former interest, and $23.5 million relative to CMS former interest, for which we would be jointly liable. We believe the occurrence of a triggering event is remote and we do not
believe the agreements will have a material adverse affect upon us.



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 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.



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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. During 2004, 2003 and 2002 sales to PAA accounted for 33%, 70% and 95%, respectively, of our total revenues and during 2004 sales to ConocoPhillips
accounted for 33% of our total revenues. During such periods no other purchaser accounted for more than 10% of our total revenues. The loss of any single significant customer or contract could have a material adverse short- term effect, however, we
do not believe that the loss of any single significant customer or contract would materially affect our business in the long-term. We believe such purchasers could be replaced by other purchasers under contracts with similar terms and conditions.
However, their role as the purchaser of a significant portion of our oil production does have the potential to impact our overall exposure to credit risk, either positively or negatively, in that they may be affected by changes in economic, industry
or other conditions. We generally do not require letters of credit or other collateral from PAA or from ConocoPhillips to support trade receivables. Accordingly, a material adverse change in PAAs or ConocoPhillipss financial condition
could adversely impact our ability to collect the applicable receivables, and thereby affect our financial condition.



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, with one such counterparty holding contracts that represent approximately 34% of the fair value of all of our open positions at December 31, 2004.



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 11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 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 our financial statements are stated at fair value. The carrying amounts and
fair values of our other financial instruments are as follows (in thousands):



|                                 |  |                   |       |           |   |      
|-------------------------------- |  | ----------------- | ----- | --------- | - | -----
|                                 |  | December 31, 2004
|                                 |  | CarryingAmount    |       | FairValue
|Long-Term Debt                   |  |                   |       |           |   |      
|Senior revolving credit facility |  | $                 | 110.0 |           | $ | 110.0
|7.125% Notes                     |  |                   | 248.7 |           |   | 274.4
|8.75% Notes                      |  |                   | 276.7 |           |   | 308.0



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The carrying value of bank debt approximates its fair value, as interest rates are variable, based on prevailing
market rates. The fair value of the 7.125% Notes and the 8.75% Notes is based on quoted market prices based on trades of such debt.



Note 12Supplemental Cash Flow Information



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



|                               |  |                         |        |      |   |        |  |   |    
|------------------------------ |  | ----------------------- | ------ | ---- | - | ------ |  | - | ---
|                               |  | Year Ended December 31,
|                               |  | 2004                    |        | 2003 |   | 2002  
|Cash payments for interest     |  | $                       | 29,515 |      | $ | 32,364 |  | $ | 280
|                               |  |                         |        |      |   |        |  |   |    
|Cash payments for income taxes |  | $                       | 2,305  |      | $ | 5,534  |  | $ |   
|                               |  |                         |        |      |   |        |  |   |    



Common stock issued for no cash
payment in connection with compensation plans (amounts in thousands):



|       |  |                         |       |      |   |       |  |   |  
|------ |  | ----------------------- | ----- | ---- | - | ----- |  | - | -
|       |  | Year Ended December 31,
|       |  | 2004                    |       | 2003 |   | 2002 
|Shares |  |                         | 328   |      |   | 107   |  |   | 
|       |  |                         |       |      |   |       |  |   |  
|Amount |  | $                       | 3,855 |      | $ | 1,071 |  | $ | 
|       |  |                         |       |      |   |       |  |   |  



The Nuevo acquisition involved
non-cash consideration as follows (in thousands of dollars):



|                                |  |   |          
|------------------------------- |  | - | ---------
|Common stock issued             |  | $ | 575,023  
|Stock options assumed           |  |   | 4,389    
|Senior Subordinated Notes       |  |   | 162,945  
|Bank Credit Facility            |  |   | 140,000  
|TECONS                          |  |   | 103,815  
|Current liabilities             |  |   | 249,438  
|Other noncurrent liabilities    |  |   | 33,583   
|Deferred income tax liabilities |  |   | 222,936  
|Asset retirement obligation     |  |   | 128,053  
|                                |  |   |          
|                                |  | $ | 1,620,182
|                                |  |   |          



The 3TEC acquisition 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
|                                    |  |   |        



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Note 13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, |          
|                                       |  | 2004                    |           | 2003 |   | 2002    | 
|Property acquisitions costs            |  |                         |           |      |   |         |  |   |        |  
|Unproved properties                    |  |                         |           |      |   |         |  |   |        |  
|Nuevo acquisition                      |  | $                       | 137,457   |      | $ |        |  | $ |       |  
|3TEC acquisition                       |  |                         |          |      |   | 61,116  |  |   |       |  
|Other                                  |  |                         | 7,437     |      |   | 19,025  |  |   | 65     |  
|Proved properties                      |  |                         |           |      |   |         |  |   |        |  
|Nuevo acquisition                      |  |                         |           |      |   |         |  |   |        |  
|Asset retirement cost                  |  |                         | 128,053   |      |   |        |  |   |       |  
|Other                                  |  |                         | 1,079,967 |      |   |        |  |   |       |  
|3TEC acquisition                       |  |                         |           |      |   |         |  |   |        |  
|Asset retirement cost                  |  |                         |          |      |   | 4,577   |  |   |       |  
|Other                                  |  |                         |          |      |   | 289,779 |  |   |       |  
|Other (1)                              |  |                         | 2,738     |      |   | 1,197   |  |   | (4,516 | )
|Exploration costs                      |  |                         | 57,530    |      |   | 8,947   |  |   | 602    |  
|Exploitation and development costs (2) |  |                         | 141,198   |      |   | 101,334 |  |   | 68,346 |  
|                                       |  |                         |           |      |   |         |  |   |        |  
|                                       |  | $                       | 1,554,380 |      | $ | 485,975 |  | $ | 64,497 |  
|                                       |  |                         |           |      |   |         |  |   |        |  

---

|(1) | In 2002 in connection with the acquisition of an additional interest in the Point Arguello field, offshore California, 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 $16.2
million, $11.0 million, and $6.0 million in 2004, 2003 and 2002, respectively, and capitalized interest expense of $7.0 million, $3.2 million and $2.4 million in 2004, 2003 and 2002, 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, |          
|                  |  | 2004         |           |   | 2003 |  
|Proved properties |  | $            | 2,402,179 |   |      | $ | 1,074,302 |  
|Accumulated DD&A  |  |              | (319,745  | ) |      |   | (183,988  | )
|                  |  |              |           |   |      |   |           |  
|                  |  | $            | 2,082,434 |   |      | $ | 890,314   |  
|                  |  |              |           |   |      |   |           |  



The average DD&A rate per
equivalent unit of production was $5.93, $3.86 and $3.17 in 2004, 2003 and 2002, respectively.



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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,
|                     |  | 2004         |        | 2003 |   | 2002  
|Acquisition costs    |  | $            | 67,380 |      | $ | 44,135 |  | $ | 24,612
|Exploration costs    |  |              | 6,725  |      |   | 12,489 |  |   |      
|Capitalized interest |  |              | 5,300  |      |   | 7,034  |  |   | 5,433 
|                     |  |              |        |      |   |        |  |   |       
|                     |  | $            | 79,405 |      | $ | 63,658 |  | $ | 30,045
|                     |  |              |        |      |   |        |  |   |       



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. Certain of 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 period of several years. We expect that 66% of the costs not subject to amortization at December 31,
2004 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 63%, 27%, 0% and 10% of the balance in unproved properties at December 31, 2004, related to additions made in 2004, 2003, 2002 and prior periods, 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, |         
|                                                                                                  |  | 2004                    |          |   | 2003 |   |          | 2002 | 
|Revenues from oil and gas producing activities                                                    |  | $                       | 671,706  |   |      | $ | 304,090  |      |  | $ | 188,563 |  
|Production costs and other                                                                        |  |                         | (223,080 | ) |      |   | (104,819 | )    |  |   | (78,451 | )
|Depreciation, depletion, amortization and accretion                                               |  |                         | (144,093 | ) |      |   | (50,142  | )    |  |   | (29,632 | )
|Income tax expense                                                                                |  |                         | (120,106 | ) |      |   | (58,996  | )    |  |   | (31,307 | )
|                                                                                                  |  |                         |          |   |      |   |          |      |  |   |         |  
|Results of operations from producing activities (excluding corporate overhead and interest costs) |  | $                       | 184,427  |   |      | $ | 90,133   |      |  | $ | 49,173  |  
|                                                                                                  |  |                         |          |   |      |   |          |      |  |   |         |  



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, 2004. The following reserve information is based upon reports of the independent petroleum
consulting



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##### Table of Contents

firms of Netherland, Sewell & Associates, Inc. in 2004 and Netherland, Sewell & Associates, Inc. and Ryder Scott Company in 2003 and 2002. 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.



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 84%
of year-end 2004 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, 2004 (in thousands).



|                                            |  |                                          |   |  |           |   |  |           |   |  |           |   |  |           |   |  |           |  
|------------------------------------------- |  | ---------------------------------------- | - |  | --------- | - |  | --------- | - |  | --------- | - |  | --------- | - |  | --------- | -
|                                            |  | As of or for the Year Ended December 31, |  
|                                            |  | 2004                                     |   |  | 2003      |   |  | 2002      |   |  |           |  
|                                            |  | Oil(MBbl)                                |   |  | Gas(MMcf) |   |  | Oil(MBbl) |   |  | Gas(MMcf) |   |  | Oil(MBbl) |   |  | Gas(MMcf) |  
|Proved Reserves                             |  |                                          |   |  |           |   |  |           |   |  |           |   |  |           |   |  |           |  
|Beginning balance                           |  | 227,728                                  |   |  | 319,177   |   |  | 240,161   |   |  | 77,154    |   |  | 223,293   |   |  | 96,217    |  
|Revision of previous estimates              |  | (138                                     | ) |  | (27,773   | ) |  | (9,009    | ) |  | (12,844   | ) |  | 8,897     |   |  | (19,827   | )
|Extensions, discoveries and other additions |  | 20,980                                   |   |  | 47,677    |   |  | 2,749     |   |  | 31,529    |   |  | 15,049    |   |  | 6,661     |  
|Improved recovery                           |  | 10,225                                   |   |  | 2,617     |   |  |          |   |  |          |   |  |          |   |  |          |  
|Purchase of reserves in-place               |  | 161,068                                  |   |  | 162,527   |   |  | 5,421     |   |  | 249,301   |   |  | 2,635     |   |  |          |  
|Sale of reserves in-place                   |  | (52,019                                  | ) |  | (58,235   | ) |  | (2,327    | ) |  | (7,768    | ) |  | (930      | ) |  | (2,535    | )
|Production                                  |  | (16,441                                  | ) |  | (38,590   | ) |  | (9,267    | ) |  | (18,195   | ) |  | (8,783    | ) |  | (3,362    | )
|                                            |  |                                          |   |  |           |   |  |           |   |  |           |   |  |           |   |  |           |  
|Ending balance                              |  | 351,403                                  |   |  | 407,400   |   |  | 227,728   |   |  | 319,177   |   |  | 240,161   |   |  | 77,154    |  
|                                            |  |                                          |   |  |           |   |  |           |   |  |           |   |  |           |   |  |           |  
|Proved Developed Reserves                   |  |                                          |   |  |           |   |  |           |   |  |           |   |  |           |   |  |           |  
|Beginning balance                           |  | 124,822                                  |   |  | 235,070   |   |  | 127,415   |   |  | 53,317    |   |  | 119,248   |   |  | 59,101    |  
|                                            |  |                                          |   |  |           |   |  |           |   |  |           |   |  |           |   |  |           |  
|Ending balance                              |  | 233,707                                  |   |  | 305,009   |   |  | 124,822   |   |  | 235,070   |   |  | 127,415   |   |  | 53,317    |  
|                                            |  |                                          |   |  |           |   |  |           |   |  |           |   |  |           |   |  |           |  





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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, |           
|                                                         |  | 2004         |            |   | 2003 |   |            | 2002 | 
|Future cash inflows                                      |  | $            | 13,106,450 |   |      | $ | 8,190,872  |      |  | $ | 6,819,645  |  
|Future development costs                                 |  |              | (1,205,386 | ) |      |   | (529,920   | )    |  |   | (431,841   | )
|Future production expense                                |  |              | (4,991,280 | ) |      |   | (3,041,607 | )    |  |   | (2,528,065 | )
|Future income tax expense                                |  |              | (2,258,064 | ) |      |   | (1,579,078 | )    |  |   | (1,446,528 | )
|                                                         |  |              |            |   |      |   |            |      |  |   |            |  
|Future net cash flows                                    |  |              | 4,651,720  |   |      |   | 3,040,267  |      |  |   | 2,413,211  |  
|Discounted at 10% per year                               |  |              | (2,415,001 | ) |      |   | (1,783,464 | )    |  |   | (1,529,704 | )
|                                                         |  |              |            |   |      |   |            |      |  |   |            |  
|Standardized measure of discounted future net cash flows |  | $            | 2,236,719  |   |      | $ | 1,256,803  |      |  | $ | 883,507    |  
|                                                         |  |              |            |   |      |   |            |      |  |   |            |  



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 portion of our oil and
gas production. Arrangements in effect at December 31, 2004 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, 2004, 2003 and 2002
were $30.91, $28.22 and $26.91 per barrel of oil, respectively, and $5.40, $5.53 and $4.63 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 $3.3 billion, $2.0 billion and $1.5 billion at December 31, 2004, 2003 and 2002, 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.



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##### Table of Contents

The principal sources of changes in the Standardized Measure of the future net cash flows for the three years ended
December 31, 2004, are as follows (in thousands):



|                                                                    |  |                         |           |   |      |   |           |      |  |   |          |  
|------------------------------------------------------------------- |  | ----------------------- | --------- | - | ---- | - | --------- | ---- |  | - | -------- | -
|                                                                    |  | Year Ended December 31, |          
|                                                                    |  | 2004                    |           |   | 2003 |   |           | 2002 | 
|Balance, beginning of year                                          |  | $                       | 1,256,803 |   |      | $ | 883,507   |      |  | $ | 384,467  |  
|Sales, net of production expenses                                   |  |                         | (598,197  | ) |      |   | (235,948  | )    |  |   | (125,463 | )
|Net change in sales and transfer prices, net of production expenses |  |                         | 258,819   |   |      |   | (1,657    | )    |  |   | 979,042  |  
|Changes in estimated future development costs                       |  |                         | (39,759   | ) |      |   | (2,172    | )    |  |   | (62,801  | )
|Extensions, discoveries and improved recovery, net of costs         |  |                         | 414,055   |   |      |   | 107,922   |      |  |   | 98,969   |  
|Previously estimated development costs incurred during the year     |  |                         | 49,823    |   |      |   | 46,957    |      |  |   | 39,692   |  
|Purchase of reserves in-place                                       |  |                         | 1,481,958 |   |      |   | 635,604   |      |  |   | 16,583   |  
|Sale of reserves in-place                                           |  |                         | (370,620  | ) |      |   | (42,022   | )    |  |   | (2,959   | )
|Revision of quantity estimates and timing of estimated production   |  |                         | (13,020   | ) |      |   | (205,829  | )    |  |   | (133,618 | )
|Accretion of discount                                               |  |                         | 189,590   |   |      |   | 151,403   |      |  |   | 62,376   |  
|Net change in income taxes                                          |  |                         | (392,733  | ) |      |   | (80,962   | )    |  |   | (372,781 | )
|                                                                    |  |                         |           |   |      |   |           |      |  |   |          |  
|Balance, end of year                                                |  | $                       | 2,236,719 |   |      | $ | 1,256,803 |      |  | $ | 883,507  |  
|                                                                    |  |                         |           |   |      |   |           |      |  |   |          |  



F-38



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##### Table of Contents

Note 14Quarterly Financial Data (Unaudited)



The following table shows summary financial data for 2004 and 2003 (in thousands, except per share data):



|                                                     |  |              |        |               |   |              |  |   |               |   |      |   |         |  |   |        
|---------------------------------------------------- |  | ------------ | ------ | ------------- | - | ------------ |  | - | ------------- | - | ---- | - | ------- |  | - | -------
|                                                     |  | FirstQuarter |        | SecondQuarter |   | ThirdQuarter |  |   | FourthQuarter |   | Year
|2004                                                 |  |              |        |               |   |              |  |   |               |   |      |   |         |  |   |        
|Revenues                                             |  | $            | 92,961 |               | $ | 152,770      |  | $ | 210,361       |   |      | $ | 215,614 |  | $ | 671,706
|Operating profit                                     |  |              | 25,453 |               |   | 58,601       |  |   | 57,865        |   |      |   | 66,680  |  |   | 208,599
|Net income                                           |  |              | 10,398 |               |   | 18,893       |  |   | (47,978       | ) |      |   | 27,527  |  |   | 8,840  
|Basic earnings per share                             |  |              | 0.26   |               |   | 0.32         |  |   | (0.62         | ) |      |   | 0.36    |  |   | 0.14   
|Diluted earnings per share                           |  |              | 0.26   |               |   | 0.32         |  |   | (0.62         | ) |      |   | 0.35    |  |   | 0.14   
|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   



Note 15Consolidating Financial
Statements



We are the issuer of the 8.75% Notes and 7.125% Notes
discussed in Note 5. The 8.75% Notes and 7.125% Notes are jointly and severally guaranteed on a full and unconditional basis by our wholly-owned 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
| | - |  | ---------------------------------------------------------------------------------------



| |  |  | PXP on a consolidated basis.
| | - |  | ----------------------------



F-39



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##### Table of Contents

PLAINS EXPLORATION & PRODUCTION COMPANY



CONDENSED CONSOLIDATING BALANCE SHEET

DECEMBER 31, 2004

(in thousands)



|                                                            |  |        |           |   |                       |   |          |                          |  |   |              |   |  |   |           |  
|----------------------------------------------------------- |  | ------ | --------- | - | --------------------- | - | -------- | ------------------------ |  | - | ------------ | - |  | - | --------- | -
|                                                            |  | Issuer |           |   | GuarantorSubsidiaries |   |          | IntercompanyEliminations |  |   | Consolidated |  
|ASSETS                                                      |  |        |           |   |                       |   |          |                          |  |   |              |   |  |   |           |  
|Current Assets                                              |  |        |           |   |                       |   |          |                          |  |   |              |   |  |   |           |  
|Cash and cash equivalents                                   |  | $      | 876       |   |                       | $ | 669      |                          |  | $ |             |   |  | $ | 1,545     |  
|Accounts receivable and other current assets                |  |        | 215,668   |   |                       |   | 40,954   |                          |  |   |             |   |  |   | 256,622   |  
|                                                            |  |        |           |   |                       |   |          |                          |  |   |              |   |  |   |           |  
|                                                            |  |        | 216,544   |   |                       |   | 41,623   |                          |  |   |             |   |  |   | 258,167   |  
|                                                            |  |        |           |   |                       |   |          |                          |  |   |              |   |  |   |           |  
|Property and Equipment, at cost                             |  |        |           |   |                       |   |          |                          |  |   |              |   |  |   |           |  
|Oil and natural gas propertiesfull cost method             |  |        |           |   |                       |   |          |                          |  |   |              |   |  |   |           |  
|Subject to amortization                                     |  |        | 1,817,709 |   |                       |   | 584,470  |                          |  |   |             |   |  |   | 2,402,179 |  
|Not subject to amortization                                 |  |        | 39,707    |   |                       |   | 39,698   |                          |  |   |             |   |  |   | 79,405    |  
|Other property and equipment                                |  |        | 11,963    |   |                       |   | 583      |                          |  |   |             |   |  |   | 12,546    |  
|                                                            |  |        |           |   |                       |   |          |                          |  |   |              |   |  |   |           |  
|                                                            |  |        | 1,869,379 |   |                       |   | 624,751  |                          |  |   |             |   |  |   | 2,494,130 |  
|Less allowance for depreciation, depletion and amortization |  |        | (209,224  | ) |                       |   | (113,817 | )                        |  |   |             |   |  |   | (323,041  | )
|                                                            |  |        |           |   |                       |   |          |                          |  |   |              |   |  |   |           |  
|                                                            |  |        | 1,660,155 |   |                       |   | 510,934  |                          |  |   |             |   |  |   | 2,171,089 |  
|                                                            |  |        |           |   |                       |   |          |                          |  |   |              |   |  |   |           |  
|Investment in and Advances to Subsidiaries                  |  |        | 612,538   |   |                       |   |         |                          |  |   | (612,538     | ) |  |   |          |  
|                                                            |  |        |           |   |                       |   |          |                          |  |   |              |   |  |   |           |  
|Other Assets                                                |  |        | 54,227    |   |                       |   | 149,762  |                          |  |   |             |   |  |   | 203,989   |  
|                                                            |  |        |           |   |                       |   |          |                          |  |   |              |   |  |   |           |  
|                                                            |  | $      | 2,543,464 |   |                       | $ | 702,319  |                          |  | $ | (612,538     | ) |  | $ | 2,633,245 |  
|                                                            |  |        |           |   |                       |   |          |                          |  |   |              |   |  |   |           |  
|LIABILITIES AND STOCKHOLDERS EQUITY                        |  |        |           |   |                       |   |          |                          |  |   |              |   |  |   |           |  
|Current Liabilities                                         |  |        |           |   |                       |   |          |                          |  |   |              |   |  |   |           |  
|Accounts payable and other current liabilities              |  | $      | 210,366   |   |                       | $ | 40,556   |                          |  | $ |             |   |  | $ | 250,922   |  
|Commodity derivative contracts                              |  |        | 172,800   |   |                       |   | 2,673    |                          |  |   |             |   |  |   | 175,473   |  
|                                                            |  |        |           |   |                       |   |          |                          |  |   |              |   |  |   |           |  
|                                                            |  |        | 383,166   |   |                       |   | 43,229   |                          |  |   |             |   |  |   | 426,395   |  
|                                                            |  |        |           |   |                       |   |          |                          |  |   |              |   |  |   |           |  
|Long-Term Debt                                              |  |        | 635,468   |   |                       |   |         |                          |  |   |             |   |  |   | 635,468   |  
|                                                            |  |        |           |   |                       |   |          |                          |  |   |              |   |  |   |           |  
|Other Long-Term Liabilities                                 |  |        | 340,271   |   |                       |   | 41,253   |                          |  |   |             |   |  |   | 381,524   |  
|                                                            |  |        |           |   |                       |   |          |                          |  |   |              |   |  |   |           |  
|Payable to Parent                                           |  |        |          |   |                       |   | 307,820  |                          |  |   | (307,820     | ) |  |   |          |  
|                                                            |  |        |           |   |                       |   |          |                          |  |   |              |   |  |   |           |  
|Deferred Income Taxes                                       |  |        | 314,184   |   |                       |   | 5,299    |                          |  |   |             |   |  |   | 319,483   |  
|                                                            |  |        |           |   |                       |   |          |                          |  |   |              |   |  |   |           |  
|Stockholders Equity                                        |  |        |           |   |                       |   |          |                          |  |   |              |   |  |   |           |  
|Stockholders equity                                        |  |        | 994,249   |   |                       |   | 353,629  |                          |  |   | (353,629     | ) |  |   | 994,249   |  
|Accumulated other comprehensive income                      |  |        | (123,874  | ) |                       |   | (48,911  | )                        |  |   | 48,911       |   |  |   | (123,874  | )
|                                                            |  |        |           |   |                       |   |          |                          |  |   |              |   |  |   |           |  
|                                                            |  |        | 870,375   |   |                       |   | 304,718  |                          |  |   | (304,718     | ) |  |   | 870,375   |  
|                                                            |  |        |           |   |                       |   |          |                          |  |   |              |   |  |   |           |  
|                                                            |  | $      | 2,543,464 |   |                       | $ | 702,319  |                          |  | $ | (612,538     | ) |  | $ | 2,633,245 |  
|                                                            |  |        |           |   |                       |   |          |                          |  |   |              |   |  |   |           |  





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##### Table of Contents

PLAINS EXPLORATION & PRODUCTION COMPANY



CONDENSED CONSOLIDATING BALANCE SHEET

DECEMBER 31, 2003

(in thousands)



|                                                            |  |        |           |   |                       |   |          |                          |  |   |              |   |  |   |           |  
|----------------------------------------------------------- |  | ------ | --------- | - | --------------------- | - | -------- | ------------------------ |  | - | ------------ | - |  | - | --------- | -
|                                                            |  | Issuer |           |   | GuarantorSubsidiaries |   |          | IntercompanyEliminations |  |   | Consolidated |  
|ASSETS                                                      |  |        |           |   |                       |   |          |                          |  |   |              |   |  |   |           |  
|Current Assets                                              |  |        |           |   |                       |   |          |                          |  |   |              |   |  |   |           |  
|Cash and cash equivalents                                   |  | $      | 403       |   |                       | $ | 974      |                          |  | $ |             |   |  | $ | 1,377     |  
|Accounts receivable and other current assets                |  |        | 53,949    |   |                       |   | 33,155   |                          |  |   |             |   |  |   | 87,104    |  
|                                                            |  |        |           |   |                       |   |          |                          |  |   |              |   |  |   |           |  
|                                                            |  |        | 54,352    |   |                       |   | 34,129   |                          |  |   |             |   |  |   | 88,481    |  
|                                                            |  |        |           |   |                       |   |          |                          |  |   |              |   |  |   |           |  
|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   |  
|                                                            |  |        |           |   |                       |   |          |                          |  |   |              |   |  |   |           |  
|                                                            |  | $      | 1,137,655 |   |                       | $ | 605,755  |                          |  | $ | (531,142     | ) |  | $ | 1,212,268 |  
|                                                            |  |        |           |   |                       |   |          |                          |  |   |              |   |  |   |           |  
|LIABILITIES AND STOCKHOLDERS EQUITY                        |  |        |           |   |                       |   |          |                          |  |   |              |   |  |   |           |  
|Current Liabilities                                         |  |        |           |   |                       |   |          |                          |  |   |              |   |  |   |           |  
|Accounts payable and other current liabilities              |  | $      | 71,441    |   |                       | $ | 22,912   |                          |  | $ |             |   |  | $ | 94,353    |  
|Commodity derivative contracts                              |  |        | 34,881    |   |                       |   | 25,341   |                          |  |   |             |   |  |   | 60,222    |  
|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                                       |  |        | 145,343   |   |                       |   | 4,248    |                          |  |   |             |   |  |   | 149,591   |  
|                                                            |  |        |           |   |                       |   |          |                          |  |   |              |   |  |   |           |  
|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   |  
|                                                            |  |        |           |   |                       |   |          |                          |  |   |              |   |  |   |           |  
|                                                            |  | $      | 1,137,655 |   |                       | $ | 605,755  |                          |  | $ | (531,142     | ) |  | $ | 1,212,268 |  
|                                                            |  |        |           |   |                       |   |          |                          |  |   |              |   |  |   |           |  





F-41



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##### Table of Contents

PLAINS EXPLORATION & PRODUCTION COMPANY



CONDENSED CONSOLIDATING STATEMENT OF INCOME

YEAR ENDED DECEMBER 31, 2004

(in thousands)



|                                                                      |  |        |          |   |                       |   |         |                          |  |   |              |   |  |   |          |  
|--------------------------------------------------------------------- |  | ------ | -------- | - | --------------------- | - | ------- | ------------------------ |  | - | ------------ | - |  | - | -------- | -
|                                                                      |  | Parent |          |   | GuarantorSubsidiaries |   |         | IntercompanyEliminations |  |   | Consolidated |  
|Revenues                                                              |  |        |          |   |                       |   |         |                          |  |   |              |   |  |   |          |  
|Oil and liquids                                                       |  | $      | 386,060  |   |                       | $ | 61,996  |                          |  | $ |             |   |  | $ | 448,056  |  
|Natural gas                                                           |  |        | 41,908   |   |                       |   | 179,452 |                          |  |   |             |   |  |   | 221,360  |  
|Other operating revenues                                              |  |        | 1,211    |   |                       |   | 1,079   |                          |  |   |             |   |  |   | 2,290    |  
|                                                                      |  |        |          |   |                       |   |         |                          |  |   |              |   |  |   |          |  
|                                                                      |  |        | 429,179  |   |                       |   | 242,527 |                          |  |   |             |   |  |   | 671,706  |  
|                                                                      |  |        |          |   |                       |   |         |                          |  |   |              |   |  |   |          |  
|Costs and Expenses                                                    |  |        |          |   |                       |   |         |                          |  |   |              |   |  |   |          |  
|Production expenses                                                   |  |        | 159,129  |   |                       |   | 63,951  |                          |  |   |             |   |  |   | 223,080  |  
|General and administrative                                            |  |        | 80,452   |   |                       |   | 4,745   |                          |  |   |             |   |  |   | 85,197   |  
|Provision for legal and regulatory settlements                        |  |        | 1,520    |   |                       |   | 5,325   |                          |  |   |             |   |  |   | 6,845    |  
|Depreciation, depletion and amortization and accretion                |  |        | 74,951   |   |                       |   | 73,034  |                          |  |   |             |   |  |   | 147,985  |  
|                                                                      |  |        |          |   |                       |   |         |                          |  |   |              |   |  |   |          |  
|                                                                      |  |        | 316,052  |   |                       |   | 147,055 |                          |  |   |             |   |  |   | 463,107  |  
|                                                                      |  |        |          |   |                       |   |         |                          |  |   |              |   |  |   |          |  
|Income from Operations                                                |  |        | 113,127  |   |                       |   | 95,472  |                          |  |   |             |   |  |   | 208,599  |  
|Other Income (Expense)                                                |  |        |          |   |                       |   |         |                          |  |   |              |   |  |   |          |  
|Equity in earnings of subsidiaries                                    |  |        | 46,774   |   |                       |   |        |                          |  |   | (46,774      | ) |  |   |         |  
|Interest expense                                                      |  |        | (22,854  | ) |                       |   | (14,440 | )                        |  |   |             |   |  |   | (37,294  | )
|Gain (loss) on mark-to-market derivative contracts                    |  |        | (148,043 | ) |                       |   | (2,271  | )                        |  |   |             |   |  |   | (150,314 | )
|Debt extinguishment costs                                             |  |        | (19,691  | ) |                       |   |        |                          |  |   |             |   |  |   | (19,691  | )
|Interest and other income (expense)                                   |  |        | 797      |   |                       |   | (74     | )                        |  |   |             |   |  |   | 723      |  
|                                                                      |  |        |          |   |                       |   |         |                          |  |   |              |   |  |   |          |  
|Income Before Income Taxes and Cumulative Effect of Accounting Change |  |        | (29,890  | ) |                       |   | 78,687  |                          |  |   | (46,774      | ) |  |   | 2,023    |  
|Income tax benefit (expense)                                          |  |        |          |   |                       |   |         |                          |  |   |              |   |  |   |          |  
|Current                                                               |  |        | 19,032   |   |                       |   | (19,407 | )                        |  |   |             |   |  |   | (375     | )
|Deferred                                                              |  |        | 19,698   |   |                       |   | (12,506 | )                        |  |   |             |   |  |   | 7,192    |  
|                                                                      |  |        |          |   |                       |   |         |                          |  |   |              |   |  |   |          |  
|Net Income                                                            |  | $      | 8,840    |   |                       | $ | 46,774  |                          |  | $ | (46,774      | ) |  | $ | 8,840    |  
|                                                                      |  |        |          |   |                       |   |         |                          |  |   |              |   |  |   |          |  





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PLAINS EXPLORATION & PRODUCTION COMPANY



CONDENSED CONSOLIDATING STATEMENT OF INCOME

YEAR ENDED DECEMBER 31, 2003

(in thousands)



|                                                                      |  |        |         |   |                       |   |         |                          |  |   |              |   |  |   |         |  
|--------------------------------------------------------------------- |  | ------ | ------- | - | --------------------- | - | ------- | ------------------------ |  | - | ------------ | - |  | - | ------- | -
|                                                                      |  | Parent |         |   | GuarantorSubsidiaries |   |         | IntercompanyEliminations |  |   | 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 benefit (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-43



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##### Table of Contents

PLAINS EXPLORATION & PRODUCTION COMPANY



CONDENSED CONSOLIDATING STATEMENT OF INCOME

YEAR ENDED DECEMBER 31, 2002

(in thousands)



|                                                                      |  |        |         |   |                       |   |        |                          |  |   |              |   |  |   |         |  
|--------------------------------------------------------------------- |  | ------ | ------- | - | --------------------- | - | ------ | ------------------------ |  | - | ------------ | - |  | - | ------- | -
|                                                                      |  | Parent |         |   | GuarantorSubsidiaries |   |        | IntercompanyEliminations |  |   | 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 benefit (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-44



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##### Table of Contents

PLAINS EXPLORATION & PRODUCTION COMPANY



CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

YEAR ENDED DECEMBER 31, 2004

(in thousands)



|                                                                                          |  |        |          |   |                       |   |          |                          |  |   |              |   |  |   |          |  
|----------------------------------------------------------------------------------------- |  | ------ | -------- | - | --------------------- | - | -------- | ------------------------ |  | - | ------------ | - |  | - | -------- | -
|                                                                                          |  | Parent |          |   | GuarantorSubsidiaries |   |          | IntercompanyEliminations |  |   | Consolidated |  
|CASH FLOWS FROM OPERATING ACTIVITIES                                                      |  |        |          |   |                       |   |          |                          |  |   |              |   |  |   |          |  
|Net income                                                                                |  | $      | 8,840    |   |                       | $ | 46,774   |                          |  | $ | (46,774      | ) |  | $ | 8,840    |  
|Items not affecting cash flows from operating activities                                  |  |        |          |   |                       |   |          |                          |  |   |              |   |  |   |          |  
|Depreciation, depletion, amortization and accretion                                       |  |        | 74,951   |   |                       |   | 73,034   |                          |  |   |             |   |  |   | 147,985  |  
|Equity in earnings of subsidiaries                                                        |  |        | (46,774  | ) |                       |   |         |                          |  |   | 46,774       |   |  |   |         |  
|Deferred income taxes                                                                     |  |        | (19,698  | ) |                       |   | 12,506   |                          |  |   |             |   |  |   | (7,192   | )
|Debt extinguishment costs                                                                 |  |        | (4,453   | ) |                       |   |         |                          |  |   |             |   |  |   | (4,453   | )
|Commodity derivative contracts                                                            |  |        |          |   |                       |   |          |                          |  |   |              |   |  |   |          |  
|Loss (gain) on derivatives                                                                |  |        | 64,395   |   |                       |   | (14,554  | )                        |  |   |             |   |  |   | 49,841   |  
|Reclassify financing derivative settlements                                               |  |        | 103,521  |   |                       |   |         |                          |  |   |             |   |  |   | 103,521  |  
|Non-cash compensation                                                                     |  |        |          |   |                       |   |          |                          |  |   |              |   |  |   |          |  
|Stock appreciation rights                                                                 |  |        | 20,268   |   |                       |   |         |                          |  |   |             |   |  |   | 20,268   |  
|Other                                                                                     |  |        | 8,092    |   |                       |   |         |                          |  |   |             |   |  |   | 8,092    |  
|Other noncash items                                                                       |  |        | (144     | ) |                       |   |         |                          |  |   |             |   |  |   | (144     | )
|Change in assets and liabilities from operating activities, net of effect of acquisitions |  |        |          |   |                       |   |          |                          |  |   |              |   |  |   |          |  
|Accounts receivable and other assets                                                      |  |        | 804      |   |                       |   | (18,733  | )                        |  |   |             |   |  |   | (17,929  | )
|Accounts payable and other liabilities                                                    |  |        | 32,399   |   |                       |   | 21,991   |                          |  |   |              |   |  |   | 54,390   |  
|                                                                                          |  |        |          |   |                       |   |          |                          |  |   |              |   |  |   |          |  
|Net cash provided by operating activities                                                 |  |        | 242,201  |   |                       |   | 121,018  |                          |  |   |             |   |  |   | 363,219  |  
|                                                                                          |  |        |          |   |                       |   |          |                          |  |   |              |   |  |   |          |  
|CASH FLOWS FROM INVESTING ACTIVITIES                                                      |  |        |          |   |                       |   |          |                          |  |   |              |   |  |   |          |  
|Additions to oil and gas properties                                                       |  |        | (99,522  | ) |                       |   | (111,865 | )                        |  |   |             |   |  |   | (211,387 | )
|Acquisition of Nuevo Energy Company, net of cash acquired                                 |  |        | (14,156  | ) |                       |   |         |                          |  |   |             |   |  |   | (14,156  | )
|Proceeds from sales of properties                                                         |  |        | 211,173  |   |                       |   | 27,816   |                          |  |   |             |   |  |   | 238,989  |  
|Other property and equipment                                                              |  |        | (7,633   | ) |                       |   | (399     | )                        |  |   |             |   |  |   | (8,032   | )
|                                                                                          |  |        |          |   |                       |   |          |                          |  |   |              |   |  |   |          |  
|Net cash (used in) provided by investing activities                                       |  |        | 89,862   |   |                       |   | (84,448  | )                        |  |   |             |   |  |   | 5,414    |  
|                                                                                          |  |        |          |   |                       |   |          |                          |  |   |              |   |  |   |          |  
|CASH FLOWS FROM FINANCING ACTIVITIES                                                      |  |        |          |   |                       |   |          |                          |  |   |              |   |  |   |          |  
|Principal payments of long-term debt                                                      |  |        | (405,000 | ) |                       |   |         |                          |  |   |             |   |  |   | (405,000 | )
|Change in revolving credit facility                                                       |  |        | (101,000 | ) |                       |   |         |                          |  |   |             |   |  |   | (101,000 | )
|Proceeds from debt issuance                                                               |  |        | 248,695  |   |                       |   |         |                          |  |   |             |   |  |   | 248,695  |  
|Debt issuance costs                                                                       |  |        | (9,325   | ) |                       |   |         |                          |  |   |             |   |  |   | (9,325   | )
|Derivative settlements                                                                    |  |        | (103,521 | ) |                       |   |         |                          |  |   |             |   |  |   | (103,521 | )
|Investment in and advances to affiliates                                                  |  |        | 36,875   |   |                       |   | (36,875  | )                        |  |   |             |   |  |   |         |  
|Other                                                                                     |  |        | 1,686    |   |                       |   |         |                          |  |   |             |   |  |   | 1,686    |  
|                                                                                          |  |        |          |   |                       |   |          |                          |  |   |              |   |  |   |          |  
|Net cash provided by (used in) financing activities                                       |  |        | (331,590 | ) |                       |   | (36,875  | )                        |  |   |             |   |  |   | (368,465 | )
|                                                                                          |  |        |          |   |                       |   |          |                          |  |   |              |   |  |   |          |  
|Net increase (decrease) in cash and cash equivalents                                      |  |        | 473      |   |                       |   | (305     | )                        |  |   |             |   |  |   | 168      |  
|Cash and cash equivalents, beginning of year                                              |  |        | 403      |   |                       |   | 974      |                          |  |   |             |   |  |   | 1,377    |  
|                                                                                          |  |        |          |   |                       |   |          |                          |  |   |              |   |  |   |          |  
|Cash and cash equivalents, end of year                                                    |  | $      | 876      |   |                       | $ | 669      |                          |  | $ |             |   |  | $ | 1,545    |  
|                                                                                          |  |        |          |   |                       |   |          |                          |  |   |              |   |  |   |          |  



F-45



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##### 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                                       |  |        |          |   |                       |   |          |                          |  |   |              |   |  |   |          |  
|Stock appreciation rights                                   |  |        | 15,895   |   |                       |   |         |                          |  |   |             |   |  |   | 15,895   |  
|Other                                                       |  |        | 1,190    |   |                       |   |         |                          |  |   |             |   |  |   | 1,190    |  
|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                      |  |        | 12,923   |   |                       |   | (37,913  | )                        |  |   |             |   |  |   | (24,990  | )
|                                                            |  |        |          |   |                       |   |          |                          |  |   |              |   |  |   |          |  
|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-46



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##### Table of Contents

PLAINS EXPLORATION & PRODUCTION COMPANY



CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

YEAR ENDED DECEMBER 31, 2002

(in thousands)



|                                                            |  |        |          |   |                       |   |        |                          |  |   |              |   |  |   |          |  
|----------------------------------------------------------- |  | ------ | -------- | - | --------------------- | - | ------ | ------------------------ |  | - | ------------ | - |  | - | -------- | -
|                                                            |  | Parent |          |   | GuarantorSubsidiaries |   |        | IntercompanyEliminations |  |   | 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-47



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##### Table of Contents

(16) Subsequent Event (unaudited)



On March 15, 2005 we announced we had entered into an agreement to acquire certain California producing oil and gas properties from a private company for $119
million. The properties are primarily located in the Los Angeles Basin of onshore California with some smaller properties located in adjacent Ventura County. The transaction is expected to close in the second quarter of 2005, subject to customary
closing conditions. The acquisition will be financed under our existing credit facility.



F-48