Filed Pursuant to Rule 424(b)(3)

Registration No. 333-108407

333-108407-01

333-108407-02

333-108407-03

333-108407-04

333-108407-05

333-108407-06

PXP

PLAINS EXPLORATION & PRODUCTION COMPANY

PLAINS E&P COMPANY

$75,000,000

Offer to Exchange

8 ³/4% Series B Senior Subordinated Notes Due 2012

for any and all

outstanding 8 ³/4% Series A Senior Subordinated Notes due 2012

CUSIP: 726507AD8, 726507AE6 and U72597AB0

The exchange offer expires at 5:00 p.m., New York City time, on October 17, 2003 unless we extend the offer. We do not currently intend to extend the exchange offer.

• We are offering to exchange up to $75,000,000 aggregate principal amount of new 8 ³/4% Series B senior subordinated notes due 2012, which we call the Series B notes and which will be freely transferable, for any and all outstanding 8 ³/4% Series A senior subordinated notes due 2012, which we call the Series A notes, issued in a private offering on May 30, 2003 and which have certain transfer restrictions. In this prospectus, we sometimes refer to the Series A notes and the Series B notes collectively as the notes.

• The terms of the Series B notes are substantially identical to the terms of the Series A notes, except that the Series B notes will be freely transferable and issued free of any covenants regarding exchange and registration rights.

• We will exchange all Series A notes that are validly tendered and not validly withdrawn prior to the closing of the exchange offer for an equal principal amount of the Series B notes that have been registered.

• You may withdraw tenders of Series A notes at any time prior to expiration of the exchange offer.

• We will not receive any proceeds from the exchange offer.

• The exchange of Series A notes for Series B notes will not be a taxable event for United States federal income tax purposes.

• Holders of Series A notes do not have any appraisal or dissenters’ rights in connection with the exchange offer.

• Series A notes not exchanged in the exchange offer will remain outstanding and be entitled to the benefits of the Indenture, but except under certain circumstances will have no further exchange or registration rights.

• The Series B notes, together with any Series A notes not exchanged in the exchange offer and any other notes previously issued under the indenture that are currently outstanding, will constitute a single class of debt securities under the indenture.

• No public market exists for the Series A notes. We do not intend to list the Series B notes on any securities exchange and, therefore, no public market is anticipated.

Please see “ Risk Factors” beginning on page 17 for a discussion of factors you should consider in connection with the exchange offer.

Neither the Securities and Exchange Commission nor any other state securities commission has approved or disapproved of the notes or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

We may amend or supplement this prospectus from time to time by filing amendments or supplements as required. You should read this entire prospectus, the accompanying letter of transmittal and related documents and any amendments or supplements to this prospectus carefully before making your investment decision.

The date of this prospectus is September 12, 2003.

In making your investment decision, you should rely only on the information contained in this prospectus. We have not authorized anyone to provide you with any other information. If you receive any other information, you should not rely on it. We are offering to exchange the Series B notes for all outstanding Series A notes only in places where offers and sales are permitted. You should not assume that the information contained in this prospectus is accurate as of any date other than the date on the front cover of this prospectus.

Table of Contents

Statement Regarding Forward-Looking Statements	ii
Market Data	iii
Glossary of Oil and Gas Terms	iii
Summary	1
Risk Factors	17
The Exchange Offer	30
Use of Proceeds	41
Capitalization	42
Selected Historical Consolidated Financial and Other Data	43
Unaudited Pro Forma Consolidated Financial Statements	44
Management’s Discussion and Analysis of Financial Condition and Results of Operations	51
Business	69
Management	89

Compensation	92
Principal Stockholders	96
Certain Transactions	97
Description of Certain Other Indebtedness	99
Description of Notes	100
United States Federal Income and Estate Tax Considerations	149
Certain ERISA Considerations	153
Plan of Distribution	155
Validity of the Series B Notes	156
Experts	156
Where You Can Find More Information	156
Index to Financial Statements	F-1

Plains Exploration & Production Company is a Delaware corporation. Our principal executive offices are located at 700 Milam, Suite 3100, Houston, Texas 77002, and our telephone number at that address is (832) 239-6000.

Prior to our conversion to a Delaware corporation on September 18, 2002, Plains Exploration & Production Company was a California limited partnership. Accordingly, when the initial Series A notes were issued in July 2002, Plains E&P Company, a wholly owned subsidiary that has no material assets, was formed for the sole purpose of being a corporate co-issuer of some of our indebtedness, including the notes.

In this prospectus, unless otherwise indicated or the context otherwise requires, “Plains,” “Plains Exploration & Production,” “we,” “us” and “our” refer to Plains Exploration & Production Company and its subsidiaries, including Plains E&P Company. Unless otherwise indicated, financial information included in this prospectus is presented on a historical basis.

Notice to New Hampshire Residents

Neither the fact that a registration statement or an application for a license has been filed under RSA 421-B with the State of New Hampshire nor the fact that a security is effectively registered or a person is licensed in the State of New Hampshire constitutes a finding by the Secretary of State that any document filed under RSA 421-B is true, complete and not misleading. Neither any such fact nor the fact that an exemption or exception is available for a security or a transaction means that the Secretary of State has passed in any way upon the merits or qualifications of, or recommended or given approval to, any person, security or transaction. It is unlawful to make, or cause to be made, to any prospective purchaser, customer or client any representation inconsistent with the provisions of this paragraph.

i

Statement Regarding Forward-Looking Statements

This document includes forward-looking statements within the meaning of Section 27A of the Securities Act, Section 21E of the Exchange Act, and the Private Securities Litigation Reform Act of 1995 about us that are subject to risks and uncertainties. All statements other than statements of historical fact included in this document are forward-looking statements. 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, those matters discussed under the caption “Risk Factors,” as well as the following:

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

• unexpected difficulties in integrating our operations and 3TEC Energy Corporation’s, or 3TEC’s, operations as a result of our recent merger;

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

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

• the 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 or business conditions.

All forward-looking statements in this document are made as of the date hereof, and you should not rely on these statements without also considering the risks and uncertainties associated with these statements and our business that are addressed in this document. 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.

ii

Market Data

The market data and other statistical information used throughout this document are based on independent industry publications, government publications, reports by market research firms or other published independent sources. Some data are also based on our good faith estimates, which are derived from our review of internal surveys, as well as the independent sources listed above. Although we believe these sources are reliable, we have not independently verified the information and cannot guarantee its accuracy and completeness.

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.

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

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

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

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

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

Gas.    Natural gas.

Gross acres.    The total acres in which a person or entity has a working interest.

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

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

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

iii

MBOE.    One thousand BOE.

Mcf.    One thousand cubic feet of gas.

Mcfe.    One thousand cubic feet of gas equivalent.

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

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

MMBOE.    One million BOE.

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 one degree Fahrenheit.

MMcf.    One million cubic feet of gas.

MMcfe.    One million cubic feet of gas equivalent.

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

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

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

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

NYMEX.    New York Mercantile Exchange.

Oil.    Crude oil, condensate and natural gas liquids.

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

PV-10.    The pre-tax present value, discounted at 10% per year, of estimated future net revenues from the production of proved reserves, computed by applying sales prices in effect as of the dates of such estimates and held constant throughout the productive life of the reserves (except for consideration of price changes to the extent provided by contractual arrangements), and deducting the estimated future costs to be incurred in developing, producing and abandoning the proved reserves (computed based on current costs and assuming continuation of existing economic conditions).

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

iv

Proved reserves.    Per Article 4-10(a)(2) of Regulation S-X, the SEC defines proved oil and gas reserves as the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based on future considerations.

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) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors; (iii) 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 are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

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

Reserve replacement cost.    The cost per BOE of reserves added during a period calculated by using a fraction, the numerator of which equals the costs incurred for the relevant property acquisition, exploration, exploitation and development and the denominator of which equals changes in proved reserves due to revisions of previous estimates, extensions, discoveries, improved recovery and other additions and purchases of reserves in-place.

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

v

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

Standardized measure.    The present value, discounted at 10% per year, of estimated future net revenues from the production of proved reserves, computed by applying sales prices in effect as of the dates of such estimates and held constant throughout the productive life of the reserves (except for consideration of price changes to the extent provided by contractual arrangements), and deducting the estimated future costs to be incurred in developing, producing and abandoning the proved reserves (computed based on current costs and assuming continuation of existing economic conditions). Future income taxes are calculated by applying the statutory federal and state income tax rate to pre-tax future net cash flows, net of the tax basis of the properties involved and utilization of available tax carryforwards related to oil and gas operations.

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

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

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

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

vi

SUMMARY

This summary highlights information contained elsewhere in this prospectus. Although this discussion summarizes the material information contained in this prospectus, it does not contain all of the information you should consider before exchanging your notes. You should read this entire prospectus carefully, especially the risks relating to the exchange offer and the risk of owning the notes discussed under “Risk Factors” beginning on page 17 and the historical combined financial statements and notes included in this prospectus before making an investment decision. Please see page iii for a glossary of oil and gas terms we use in this document.

On June 4, 2003, Old Plains acquired 3TEC Energy Corporation, or 3TEC, through the issuance of Old Plains’ common stock and the payment of cash to 3TEC’s stockholders. In this document, unless the context requires otherwise, “Old Plains” refers to Plains Exploration & Production Company, a Delaware corporation, and its subsidiaries before the merger with 3TEC and “3TEC” refers to 3TEC Energy Corporation, a Delaware corporation, before the merger. “Plains” “we,” “us,” “our,” and the “combined company” refer to the combined company resulting from the merger of PXP and 3TEC, and its subsidiaries, subsequent to the merger.

On December 18, 2002, Plains Resources Inc. distributed all of Old Plains’ common stock to its stockholders in a spin-off. Plains Resources owns 44% of the general partner of Plains All American Pipeline, L.P., or PAA, and 12.4 million limited partner units of PAA, which represents approximately 24% aggregate ownership of PAA. In addition, Plains Resources owns certain upstream assets in Florida for which we provide management and technical services. PAA is a publicly traded master limited partnership actively engaged in the midstream energy markets. We market substantially all of our oil production through PAA. Although Plains Resources has historically owned and operated Old Plains’ offshore California and Illinois properties through Old Plains and its subsidiaries, the discussion in this document assumes Old Plains owned and operated these properties since the time Plains Resources acquired them. For example, if Plains Resources through Old Plains and its subsidiaries drilled a well in 1999 on an Illinois property, this prospectus will state that Old Plains drilled the well in 1999.

Our Company

We are an independent oil and gas company primarily engaged in the upstream activities of exploring for, acquiring, exploiting, developing and producing oil and gas in the United States. Our core operating areas are:

• California;

• Gulf Coast; and

• East Texas.

Our onshore California reserves are generally mature but underdeveloped, have produced significant volumes since initial discovery and have significant long-lived estimated remaining reserves. Our East Texas and Gulf Coast properties generally have higher initial production rates. We opportunistically hedge portions of our oil and gas production to manage our exposure to commodity price risk.

1

Recent Developments

Merger with 3TEC

On June 4, 2003 we acquired 3TEC for approximately $312.9 million in cash and common stock plus $90.1 million to retire outstanding debt. Prior to the merger, 3TEC was engaged in the acquisition, development, production and exploration of oil and gas. 3TEC’s properties were concentrated in East Texas and the Gulf Coast region, both onshore and in the shallow waters of the Gulf of Mexico. As of December 31, 2002, 3TEC had estimated total net proved reserves of 49 MMBOE, of which approximately 87% was gas and approximately 81% was proved developed. During 2002, 3TEC produced approximately 5,100 MBOE of oil and gas of which 84% was gas.

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 common stockholders of approximately $152.4 million and issued 15.3 million common shares. In addition, we paid $90.1 million to retire 3TEC’s outstanding debt and paid cash consideration of $8.3 million and issued 0.8 million common shares to redeem outstanding warrants. Prior to the merger, 3TEC redeemed all outstanding shares of its Series D preferred stock for $14.7 million. The cash portion of the merger consideration was funded through borrowings under our $500.0 million credit facility and the proceeds of the Series A notes offering.

Our Competitive Strengths

The combination of Old Plains and 3TEC has created an independent oil and gas company with a pro forma aggregate of 302.4 MMBOE of proved reserves at December 31, 2002 and pro forma 2002 production of 39.6 MBOE per day. The following table sets forth information with respect to the combined company’s pro forma oil and gas reserves as of and for the year ended December 31, 2002:

	California			Gulf Coast			East Texas			Other			Total
	(Dollars in millions)
Proved reserves
MMBOE		227.4			6.3			29.5			39.2			302.4
Percent oil		94	%		24	%		5	%		74	%		81	%
Proved Developed Reserves—MMBOE		120.4			5.4			22.4			27.9			176.1
2002 Production—MMBOE		8.4			1.5			2.4			2.1			14.4
PV-10(1)	$	1,408.5		$	119.2		$	270.7		$	204.6		$	2,003.0
Standardized measure(2)													$	1,232.9

(1) Based on year-end 2002 spot market prices of $31.20 per Bbl of oil and $4.79 per MMBtu of gas. 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.

2

We believe the combined company has the following strengths as a result of the merger:

Larger and More Diversified, Long-Lived Asset Base.    The merger has increased and diversified our oil and gas production and reserves. Pro forma for the acquisition of 3TEC, our 2002 production would have increased by over 50% compared to Old Plains and would have been comprised of approximately 33% gas and 67% oil. In addition, our asset base is more geographically diversified. The combined company has a proved reserve life of over 20.0 years and a proved developed reserve life of over 12.0 years. We believe that our long-lived reserve base in East Texas and onshore California combined with the continuation of our active hedging strategy should provide us with relatively stable and recurring cash flow. Such cash flows and operations will support our higher impact operations in the Gulf Coast via exploitation and exploratory drilling activities. Our pro forma 2002 proved reserve and production volumes were concentrated in the following core areas:

Region	Reserves	Production
California	75%	58%
East Texas	10%	16%
Gulf Coast	2%	12%
Other	13%	14%
Total Company	100%	100%

Large Exploration, Exploitation and Development Project Inventory with High Operatorship Levels.    We have a large inventory of projects in our core areas that we believe will support at least three years of development and exploitation activity at historical levels of capital investment. In addition, we have exploration projects at various levels of maturity including a recently acquired 102 square mile 3-D seismic survey in South Louisiana where we operate. On a pro forma basis, we operated approximately 83% of our 2002 production. The combined company continues to have a 100% operating interest in its onshore properties in California and in Illinois. We believe our high operatorship levels provide us with more flexibility than many of our peers to opportunistically pursue exploitation and development projects relating to our properties.

Experienced and Proven Management and Technical Team.    Our executive management team has an average of over 20 years of experience in the oil and gas industry. Our Chief Executive Officer is James C. Flores, who founded Flores & Rucks Incorporated, a predecessor of Ocean Energy, Inc., was President and Chief Executive Officer of Ocean Energy from July 1995 until March 1999. Mr. Flores served as Chairman of the Board of Ocean Energy from March 1999 until January 2000, and as Vice Chairman from January 2000 until January 2001. Our executive management is supported by a core team of technical and operating managers who have many years of experience in the oil and gas industry.

Greater Human and Technological Resources.    We have significant expertise with regard to various energy technologies, including 3-D seismic interpretation capabilities, enhanced oil recovery, offshore drilling, deep onshore drilling, and other exploration, production and processing technologies. The addition of 3TEC employees, who have significant expertise in the oil and gas industry in regions outside the specific expertise of Old Plains’ employees, complements our existing operations team. In addition to 3TEC employees, we have hired 18 industry experienced drilling, engineering, geology/geophysical, land and environmental professional personnel. As a result, we have an enhanced ability to acquire, explore for, develop and exploit oil and gas reserves domestically, both onshore and offshore.

3

Improved Capital Efficiencies.    We have a balanced profile of lower risk exploitation properties in California and East Texas and properties with higher potential returns in the Gulf Coast. Accordingly, we have an enhanced ability to finance our exploration opportunities internally through the significant free cash flow generation from our exploitation assets. In addition, we should have greater flexibility to fund our internal growth initiatives across varying commodity price and capital markets cycles.

Enhanced Platform for Industry Consolidation.    Our management believes that independent exploration and production companies will likely continue to merge and consolidate in the future and attractive property acquisition opportunities should become available in our core areas. Our larger, more efficient and scaleable growth platform has investment characteristics more attractive to growth capital providers. In addition, we believe we have opportunities for operational efficiencies and development opportunities when evaluating acquisitions in the East Texas and Gulf Coast regions.

Strategy

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

Continue Exploitation and Development of Current Asset Base.    We believe the combined company can continue its strong reserve and production growth through the exploitation and development of its existing inventory of projects relating to its properties. The combined company will focus on implementing improved production practices and recovery techniques and relatively low-risk development drilling in its onshore California and East Texas properties.

Engage in a Higher Impact Exploration Program.    We believe there are many opportunities for us to continue to expand on 3TEC’s success in exploratory drilling primarily in the Gulf Coast region by taking advantage of 3TEC’s existing inventory of exploratory projects and by carefully evaluating and prudently allocating capital to additional exploratory projects.

Pursue Selective Acquisition Opportunities.    We intend to be opportunistic in pursuing selective acquisitions of oil or gas properties or exploration projects, for example, during periods of weak commodity prices. We will consider opportunities located in our current core areas of operation as well as projects in other areas in North America that meet our investment criteria.

Maintain Long-Term Hedging Program.    We plan to continue managing our exposure to commodity price fluctuations by actively hedging significant portions of our oil and gas production through the use of swaps, collars and purchased puts and calls. The level of hedging activity depends on our view of market conditions, available hedge prices and our operating strategy. Under our hedging program, we typically hedge approximately 70-75% of our production for the current year, 40-50% of our production for the next year and up to 25% of our production for the following year. For example, on a pro forma basis for the merger, and assuming a constant production level of 39.6 MBOE per day, as of July 31, 2003 our hedge positions would have resulted in us having hedged approximately 72% of production for 2003, approximately 64% of production for 2004 and approximately 19% of production for 2005.

4

Risk Factors

You should carefully consider, along with the other information contained in this prospectus, the specific factors set forth under “Risk Factors” for risks involved with exchanging the notes.

Our Executive Offices

Our principal executive offices are located at 700 Milam, Suite 3100, Houston, Texas 77002, and our telephone number at that address is (832) 239-6000.

5

THE EXCHANGE OFFER

You are entitled to exchange in the exchange offer your outstanding Series A notes for Series B notes with substantially identical terms. You should read the discussion under the heading “Description of Notes” beginning on page 100 for further information regarding the Series B notes.

Registration Rights Agreement On May 30, 2003 Old Plains sold $75.0 million in aggregate principal amount of Series A notes to J.P. Morgan Securities Inc. as initial purchaser in a transaction exempt from the registration requirements of the Securities Act. Simultaneously with the sale of the Series A notes, Old Plains entered into a registration rights agreement with the initial purchaser which grants the holders of the Series A notes exchange and registration rights. This exchange offer satisfies those exchange rights.

The Exchange Offer We are offering to exchange $1,000 principal amount of Series B notes for each $1,000 principal amount of Series A notes. As of the date of this prospectus, $75.0 million aggregate principal amount of the Series A notes are outstanding. We will issue Series B notes to holders promptly following the Expiration Date.

Expiration Date The exchange offer expires at 5:00 p.m., New York City time on October 17, 2003 unless we extend the exchange offer in our sole discretion, in which case the term “Expiration Date” means the latest date and time to which the exchange offer is extended. We do not currently intend to extend the exchange offer.

Withdrawal Rights Tenders of Series A notes pursuant to the exchange offer may be withdrawn at any time prior to the Expiration Date.

Resales of the Series B Notes Based on interpretations by the staff of the SEC set forth in no-action letters issued to third parties, we believe that, except as described below, the Series B notes issued in the exchange offer may be offered for resale, resold and otherwise transferred by holders of the Series B notes, other than a holder that is an “affiliate” of ours within the meaning of Rule 405 under the Securities Act, without compliance with the registration and prospectus delivery provisions of the Securities Act, so long as you are acquiring the Series B notes in the ordinary course of your business and you have not engaged in, and have no arrangement or understanding with any person to participate in, the distribution of the Series B notes.

Each broker-dealer that receives Series B notes pursuant to the exchange offer in exchange for Series A notes that the broker-dealer acquired for its own account as a result of market-making activities or other trading activities, other than Series A notes acquired directly from us or our affiliates, must

6

acknowledge that it will deliver a prospectus in connection with any resale of the Series B notes. The letter of transmittal states that by acknowledging and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an “underwriter” within the meaning of the Securities Act.

If we receive notices in the letter of transmittal, this prospectus, as it may be amended or supplemented from time to time, may be used for the period described below by a broker-dealer in connection with resales of Series B notes received in exchange for Series A notes where the Series A notes were acquired by the broker-dealer as a result of market making activities or other trading activities and not acquired directly from us.

The letter of transmittal requires broker-dealers tendering Series A notes in the exchange offer to indicate whether the broker-dealer acquired the Series A notes for its own account as a result of market-making activities or other trading activities, other than Series A notes acquired directly from us or any of our affiliates. If no broker-dealer indicates that the Series A notes were so acquired, we have no obligation under the registration rights agreement to maintain the effectiveness of the registration statement past the consummation of the exchange offer or to allow the use of this prospectus for such resales. See “The Exchange Offer—Registration Rights” and “—Resale of the Series B Notes; Plan of Distribution.”

Any holder of Series A notes who:

•   is our affiliate;

• does not acquire the Series B notes in the ordinary course of its business; or

• exchanges the Series A notes in the exchange offer with the intention to participate, or for the purpose of participating, in a distribution of the Series B notes

must, in the absence of an exemption, comply with the registration and prospectus delivery requirements of the Securities Act in connection with the resale of the Series B notes.

Conditions to the Exchange Offer The exchange offer is subject to certain conditions which we may waive. See “The Exchange Offer—Conditions to the Exchange Offer.”

Procedures for Tendering the Series A Notes If you are a holder of Series A notes wishing to accept the exchange offer, you must

• complete, sign and date the accompanying letter of transmittal in accordance with the instructions, and mail or

7

otherwise deliver the letter of transmittal together with the Series A notes and any other required documentation to the exchange agent identified below under “Exchange Agent” at the address set forth in this prospectus; or

• arrange for the Depositary Trust Company to transmit certain required information, including an agent’s message forming part of a book-entry transfer in which you agree to be bound by the terms of the letter of transmittal, to the exchange agent in connection with a book-entry transfer.

By executing the letter of transmittal, you will make certain representations to us. See “The Exchange Offer—Registration Rights” and “—Procedures for Tendering Series A Notes.”

Special Procedures for Beneficial Owners If you are a beneficial owner whose Series A notes are registered in the name of a broker, dealer, commercial bank, trust company or other nominee and you wish to tender, you should contact the registered holder promptly and instruct the registered holder to tender on your behalf. See “The Exchange Offer—Procedures for Tendering Series A Notes.”

Guaranteed Delivery Procedures If you are a holder of Series A notes and wish to tender them when those securities are not immediately available or you cannot deliver your Series A notes, the letter of transmittal or any other documents required by the letter of transmittal to the exchange agent prior to the Expiration Date, you must tender your Series A notes according to the guaranteed delivery procedures set forth in “The Exchange Offer—Procedures for Tendering Series A Notes—Guaranteed Delivery.”

Acceptance of Series A Notes and Delivery of Series B Notes We will accept for exchange any and all Series A notes that are properly tendered in the exchange offer and not withdrawn prior to the Expiration Date. The Series B notes issued in the exchange offer will be issued on the earliest practicable date following our acceptance for exchange of the Series A notes. See “The Exchange Offer—Terms of the Exchange Offer.”

United States Federal Income Tax Consequences Your exchange of Series A notes for Series B notes in the exchange offer will not result in any gain or loss to you for United States federal income tax purposes. See “Certain United States Federal Income Tax Considerations” for a more detailed description of the tax consequences of the exchange offer associated with the exchange of Series A notes for Series B notes to be issued in the exchange offer and the ownership and disposition of the Series B notes.

8

Use of Proceeds We will not receive any cash proceeds from the issuance of the Series B notes pursuant to the exchange offer.

Exchange Agent JPMorgan Chase Bank is serving as exchange agent in connection with the exchange offer. See “The Exchange Offer—Exchange Agent.”

Consequences of Failure to Exchange Your Series A Notes Series A notes not exchanged in the exchange offer will continue to be subject to the restrictions on transfer that are described in the legend on the Series A notes. In general, you may offer or sell your Series A notes only if they are registered under, or offered or sold under an exemption from, the Securities Act and applicable state securities laws. We do not currently intend to register the Series A notes under the Securities Act. If your Series A notes are not tendered and accepted in the exchange offer, it may become more difficult for you to sell or transfer your Series A notes.

Ratio of Earnings to Fixed Charges

The ratio of earnings to fixed charges for each of the periods indicated is as follows:

Six Months Ended       June 30, 2003	Year Ended December 31,
	2002	2001	2000	1999	1998
3.3	2.9	5.2	3.1	2.1	—	(1)

(1) In 1998 earnings were insufficient to cover fixed charges by $29.2 million.

We have computed the ratio of earnings to fixed charges by dividing earnings by fixed charges. For this purpose, “earnings” consists of income before income taxes and the cumulative effect of accounting charges and fixed charges. “Fixed Charges” consist of interest expense, capitalized interest and that portion of annual rental expense we have deemed to represent the interest factor.

9

SUMMARY FINANCIAL INFORMATION

Plains

The following table sets forth Plains’ summary consolidated historical financial information that has been derived from (i) the audited consolidated statements of income and cash flows for each of the years ended December 31, 2002, 2001 and 2000, (ii) the unaudited consolidated statements of income and cash flows for the six months ended June 30, 2003 and 2002 and (iii) the unaudited consolidated balance sheet as of June 30, 2003. You should read this financial information in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the historical financial statements and notes included in this document. The information set forth below is not necessarily indicative of our future results.

	Six Months Ended June 30,						Year Ended December 31,
	2003(1)			2002			2002			2001			2000
	(Amounts in thousands)
Statement of Income Data:
Revenues:
Oil sales to Plains All American Pipeline, L.P.	$	119,593		$	81,676		$	193,615		$	174,613		$	199,233
Other oil sales and oil hedging		(24,619	)		(454	)		(15,577	)		282			(72,799	)
Gas sales		18,781			4,578			10,299			28,771			16,017
Other operating revenues		407			13			226			473			—
		114,162			85,813			188,563			204,139			142,451
Costs and Expenses:
Production expenses		45,534			35,082			78,451			63,795			56,228
General and administrative(2)
G & A excluding items below		8,757			4,726			10,756			10,210			6,308
Stock appreciation rights		2,647			—			3,653			—			—
Merger related costs		1,097			—			—			—			—
Spin-off costs		—			—			777			—			—
Depreciation, depletion and amortization		17,868			13,507			30,359			24,105			18,859
Accretion of asset retirement obligation		1,176			—			—			—			—
		77,079			53,315			123,996			98,110			81,395
Income from operations		37,083			32,498			64,567			106,029			61,056
Other income (expense)
Expenses of terminated public equity offering(3)		—			—			(2,395	)		—			—
Interest expense(4)		(10,194	)		(9,418	)		(19,377	)		(17,411	)		(15,885	)
Interest and other income (expense)		(167	)		36			174			463			343
Income before income taxes and cumulative effect of accounting change		26,722			23,116			42,969			89,081			45,514
Income tax expense		(10,889	)		(9,034	)		(16,732	)		(34,388	)		(16,765	)
Income before cumulative effect of accounting change		15,833			14,082			26,237			54,693			28,749
Cumulative effect of accounting change, net of tax benefit		12,324			—			—			(1,522	)		—
Net income	$	28,157		$	14,082		$	26,237		$	53,171		$	28,749
Other Financial Data:
Net cash provided by operating activities	$	27,914		$	19,776		$	78,826		$	116,808		$	79,464
Oil and gas capital expenditures(5)		54,293			42,341			64,497			125,753			70,505

(footnotes on following page)

10

	As of June 30, 2003
	(Amounts in thousands)
Balance Sheet Data:
Cash and cash equivalents	$	3,466
Working capital(6)		(75,468	)
Total assets		1,138,561
Total debt		511,013
Stockholders’ equity		340,033

(1) Reflects the acquisition of 3TEC effective June 1, 2003.

(2) Prior to December 18, 2002, general and administrative expenses consist of Old Plains’ direct expenses plus amounts allocated from Plains Resources for various operational, financial, accounting and administrative services provided to Old Plains. We estimate that Old Plains’ annual general and administrative expenses will increase by approximately $4.1 million over the amount for the year ended December 31, 2002 in connection with the reorganization (excluding expenses related to stock appreciation rights, spin-off costs and the effect of acquiring 3TEC).

Stock appreciation rights, or SARs, are subject to variable accounting treatment. As a result, Plains’ results of operations could be adversely or positively affected by fluctuations in the price of our common stock in subsequent periods.

In connection with the issuance of SARs to Plains Resources’ employees, officers and directors as part of and at the time of the spin-off, Old Plains was required to record a pre-tax charge to earnings equal to the aggregate in-the-money value of the SARs deemed vested at that time. Old Plains incurred $2.7 million as an initial pre-tax charge in connection with the spin-off. In addition, Old Plains recognized a $1.0 million pre-tax charge to reflect the movement in its common stock price and the vesting deemed to have occurred from the spin-off date to December 31, 2002. In the first six months of 2003, we recognized a $2.6 million pre-tax charge to income to reflect the increase in the in-the-money value of our deemed vested SARs.

(3) Before its spin-off from Plains Resources, Old Plains attempted to complete an initial public offering of its common stock that was terminated due to market conditions.

(4) Net of capitalized interest of $0.9 million and $1.4 million for the six months ended June 30, 2003 and 2002, respectively, and $2.4 million, $3.1 million and $3.8 million for the years ended December 31, 2002, 2001 and 2000, respectively.

(5) The amounts presented exclude the 3TEC acquisition.

(6) Approximately $38.1 million of the working capital deficit is attributable to our hedge position and its relationship to the current market prices for hydrocarbons.

11

Summary Reserve and Production Data

The following table sets forth certain of Plains’ and 3TEC’s information with respect to their oil and gas reserve and production data. You should read the historical data in conjunction with the historical financial statements and notes included in this prospectus. The information set forth below is not necessarily indicative of future results.

	Six Months Ended June 30,						Year Ended December 31,
	Pro Forma 2003(1)		2003(2)		2002		2002			2001			2000
			(Amounts in thousands, except as indicated and per unit amounts)
Plains:
Estimated proved reserves (at end of period):
Oil (MBbl)(3)								240,161			223,293			204,387
Gas (MMcf)								77,154			96,217			93,486
Total (MBOE)								253,020			239,329			219,968
Percent oil								95	%		93	%		93	%
Percent proved developed								54	%		54	%		52	%
PV-10 (at end of period)(4)							$	1,515,044		$	643,220		$	1,304,182
Standardized measure (at end of period)(4)(5)								883,507			384,467			789,438
Reserve additions (MBOE)								24,387			28,140			17,770
Reserve life (years)								27.1			27.3			27.0
Production:
Oil (MBbl)		4,810		4,468		4,113		8,783			8,219			7,654
Gas (MMcf)		13,855		3,474		1,719		3,362			3,355			3,042
Total (MBOE)		7,119		5,047		4,400		9,343			8,778			8,161
Oil and gas capital expenditures(6):
Exploitation and development(7)			$	48,721	$	40,656	$	68,346		$	123,778		$	68,186
Exploration				5,094		—		602			286			293
Acquisition				478		1,685		(4,451	)		1,689			2,026
Total cost incurred				54,293		42,341		64,497			125,753			70,505
Reserve replacement ratio								261	%		321	%		218	%
Average realized price per unit:
Oil ($/Bbl)(8)	$	21.91	$	21.26	$	19.75	$	20.27		$	21.28		$	16.52
Gas ($/Mcf)(9)		4.79		5.41		2.66		3.06			8.58			5.26
BOE		24.12		22.54		19.50		20.16			23.20			17.46
Expense per BOE:
Production expenses	$	8.19	$	9.02	$	7.97	$	8.40		$	7.27		$	6.89
General and administrative(6)
G&A excluding items below	$	1.81	$	1.74	$	1.07	$	1.16		$	1.16		$	0.77
Stock appreciation rights		0.37		0.52		—		0.39			—			—
Merger related costs		0.15		0.22		—		—			—			—
Spin-off costs		—		—		—		0.08			—			—
3TEC:
Estimated proved reserves (at end of period):
Oil (MBbl)(3)								6,208			5,337			10,672
Gas (MMcf)								259,026			231,266			237,693
Total (MBOE)								49,379			43,881			50,288
Percent oil								13	%		12	%		21	%
Percent proved developed								81	%		77	%		78	%
PV-10 (at end of period)(4)								487,973			212,349			1,047,364
Standardized measure (at end of period)(4)(5)								349,440			181,599			692,674
Reserve additions (MBOE)								10,723			3,405			18,830
Reserve life (years)								9.7			9.4			12.3
Production:
Oil (MBbl)								828			952			1,139
Gas (MMcf)								25,647			22,352			17,764
Total (MBOE)								5,103			4,678			4,100
Costs incurred(6):
Exploitation and development(7)							$	37,510		$	62,668		$	25,346
Exploration								21,531			11,059			695
Acquisition								302			84,326	(12)		79,865
Total cost incurred								59,343			158,053			105,906

12

	Six Months Ended June 30,			Year Ended December 31,
	Pro Forma 2003(1)	2003(2)	2002	2002			2001			2000
		(Amounts in thousands, except as indicated and per unit amounts)
Reserve replacement ratio					210	%		73	%		459	%
Average sales price per unit:
Oil ($/Bbl)				$	23.01		$	23.95		$	25.11	(11)
Gas ($/Mcf)					3.25	(10)		4.15	(10)		4.12
BOE					20.10			24.72			25.20	(11)
Expense per BOE:
Production expenses				$	4.96		$	5.70		$	5.64
General and administrative(6)					1.80			1.50			1.50

(1) Pro forma information shows the pro forma effects of the acquisition of 3TEC Energy Corporation as if the acquisition took place on January 1, 2003. 3TEC held certain derivative instruments that they elected not to qualify for hedge accounting under the provisions of SFAS 133. Accordingly, the realized and unrealized gains and losses with respect to such derivatives were recognized currently in 3TEC’s results of operations. At the time of the acquisition, the derivative instruments were assigned to us and were qualified for hedge accounting. The pro forma realized prices presented include the realized gains or losses related to the 3TEC derivatives as if they had been qualified for hedge accounting. The realized price per Mcf and BOE includes losses of $1.12 and $2.18, respectively, related to such derivatives.

(2) Reflects the acquisition of 3TEC Energy Corporation effective June 1, 2003.

(3) Includes oil, condensate and plant product barrels.

(4) For Old Plains, based on year-end spot market prices of: (a) $31.20 per Bbl of oil and $4.79 per MMBtu of gas for 2002; (b) $19.84 per Bbl of oil and $2.58 per Mcf of gas for 2001; and (c) $26.80 per Bbl of oil and $13.70 per Mcf of gas for 2000. For 3TEC, based on year-end spot market prices of (a) $31.20 per Bbl of oil and $4.79 per MMBtu of gas for 2002; (b) $19.84 per Bbl of oil and $2.57 per MMBtu of gas for 2001; and (c) $25.31 per Bbl of oil and $9.40 per MMBtu of gas for 2000. PV-10 represents the standardized measure before deducting estimated future income taxes. Future development costs included in PV-10 and standardized measure amounts do not include any amounts for capitalized general and administrative costs or capitalized interest.

(5)   For Old Plains, year-end 2002 standardized measure includes future development costs related to proved undeveloped reserves of $43.7 million in 2003, $55.6 million in 2004 and $46.6 million in 2005. For 3TEC, year-end 2002 standardized measure includes future development costs related to proved undeveloped reserves of $30.3 million in 2003, $12.2 million in 2004 and $5.5 million in 2005.

(6)   Amounts for Plains and 3TEC are not comparable because Plains follows the full cost method of accounting for oil and gas properties while 3TEC follows the successful efforts method of accounting. Certain costs that are capitalized under the full cost method are expensed under the successful efforts method. These costs consist primarily of costs associated with unsuccessful exploration drilling geological and geophysical costs, costs of carrying and retaining unevaluated properties and general and administrative costs associated with acquisition, exploration, exploitation and development activities. For Plains, amounts include capitalized general and administrative expense of $4.6 million and $3.0 million for the six months ended June 30, 2003 and 2002, respectively, and $6.0 million, $6.2 million and $5.2 million in 2002, 2001 and 2000, respectively, and capitalized interest expense of $0.9 million and $1.4 million for the six months ended June 30, 2003 and 2002, respectively, and $2.4 million, $3.1 million and $3.8 million in 2002, 2001 and 2000, respectively. The amounts presented exclude the acquisition of 3TEC.

(7)   For Old Plains, exploitation and development costs include expenditures of $27.3 million in 2002, $58.5 million in 2001 and $20.6 million in 2000 related to the development of proved undeveloped reserves included in Old Plains’ proved oil and gas reserves at the beginning of each year. For 3TEC, exploitation and development costs include expenditures of $14.0 million in 2002, $8.7 million in 2001 and $5.1 million in 2000 related to the development of proved undeveloped reserves included in 3TEC’s proved oil and gas reserves at the beginning of each year.

(8)   Includes the effect of hedges, which was $(5.88)/Bbl and $(0.11)/Bbl in the six months ended June 30, 2003 and 2002, respectively, and $(1.77)/Bbl in 2002, $0.03/Bbl in 2001, and $(9.51)/Bbl in 2002.

(9) Includes the effect of hedges which was $(0.42)/mcf in the six months ended June 30, 2003.

(10) Excludes the effect of 3TEC’s derivatives activities, which were not designated as hedges pursuant to SFAS 133 and comprised approximately $162,000 of cash settlements during 2001.

(11) Includes the effect of 3TEC’s hedging activities.

(12) Excludes a $29.0 million deferred tax liability.

13

SUMMARY UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL DATA

OF THE COMBINED COMPANY

The following table sets forth summary unaudited pro forma consolidated financial and operating data which are presented to give effect to the following pro forma adjustments:

• Old Plains’ reorganization in July 2002;

• Old Plains’ issuance of the Initial Notes in July 2002;

• Old Plains’ entry into a $300.0 million revolving credit facility and initial borrowings thereunder in July 2002;

• the receipt by Old Plains of $47.2 million in capital contributions from Plains Resources between July and December 2002;

• the distribution by Old Plains of the net proceeds of the Initial Notes offering and the initial borrowings under the credit facility to Plains Resources;

• the transfer from Plains Resources to Old Plains of certain assets and liabilities;

• Old Plains’ issuance of the new notes and the use of proceeds therefrom to pay a portion of the cash portion of the purchase price of the merger with 3TEC.

14

The unaudited pro forma consolidated financial data is not necessarily indicative of the results of operations or the financial position that would have occurred had the above transactions been consummated at January 1, 2002 nor is it necessarily indicative of future results of operations or financial position. The unaudited pro forma combined financial data should be read together with the historical financial statements included in this document.

	Six Months Ended June 30, 2003			Year Ended December 31, 2002
	Pro forma (Offering and Merger)			Pro forma (Offering and Merger)
	(Amounts in thousands)
Statement of Income Data:
Revenues:
Oil, gas and plant revenues	$	187,350		$	291,235
Other operating revenues		407			226
		187,757			291,461
Costs and Expenses:
Production expenses		58,508			103,965
General and administrative(1)		16,627			24,650
Depreciation, depletion and amortization		29,882			57,523
Accretion of asset retirement obligation		1,260			—
		106,277			186,138
Income from operations		81,480			105,323
Other income (expense)
Expenses of terminated public equity offering		—			(2,395	)
Interest expense		(13,491	)		(26,167	)
Derivative fair value gain (loss)		(22,385	)		(6,632	)
Derivative settlement gain (loss)		(15,546	)		(5,644	)
Interest and other income		(108	)		458
Income before income taxes and minority interest		29,950			64,943
Income tax expense		(12,179	)		(25,977	)
Income before cumulative effect of accounting change	$	17,771		$	38,966

(1) Prior to December 18, 2002, general and administrative expenses consist of Old Plains’ direct expenses plus amounts allocated from Plains Resources for various operational, financial, accounting and administrative services provided to Old Plains. We estimate that Old Plains’ annual general and administrative expenses will increase by approximately $4.1 million over the amount for the year ended December 31, 2002 in connection with the reorganization (excluding expenses related to stock appreciation rights, spin-off costs and the effect of acquiring 3TEC).

Stock appreciation rights, or SARs, are subject to variable accounting treatment. As a result, Plains’ results of operations could be adversely or positively affected by fluctuations in the price of our common stock in subsequent periods.

In connection with the issuance of SARs to Plains Resources’ employees, officers and directors as part of and at the time of the spin-off, Old Plains was required to record a pre-tax charge to earnings equal to the aggregate in-the-money value of the SARs deemed vested at that time. Old Plains incurred $2.7 million as an initial pre-tax charge in connection with the spin-off. In addition, Old Plains recognized a $1.0 million pre-tax charge to reflect the movement in its common stock price and the vesting deemed to have occurred from the spin-off date to December 31, 2002. In the first six months of 2003, we recognized a $2.6 million pre-tax charge to income to reflect the increase in the in-the-money value of our deemed vested SARs.

15

SUMMARY PRO FORMA OIL AND GAS RESERVE

AND OPERATING DATA OF THE COMBINED COMPANY

The following table sets forth summary pro forma information with respect to Plains’ and 3TEC’s combined estimated net proved oil and gas reserves and operating data.

	Six Months Ended June 30, 2003(1)		Year Ended December 31, 2002
	(Amounts in thousands, except as indicated and per unit amounts)
Estimated proved reserves (at end of period):
Oil (MBbl)(2)				246,369
Gas (MMcf)				336,180
Total (MBOE)				302,399
Percent oil				81	%
Percent proved developed				58	%
PV-10 (at end of period)(3)			$	2,003,017
Standardized measure (at end of period)(3)				1,232,947
Reserve additions (MBOE)				35,110
Reserve life (years)				20.9
Production:
Oil (MBbl)		4,810		9,611
Gas (MMcf)		13,855		29,009
Total (MBOE)		7,119		14,446
Average sales price per unit:
Oil ($/Bbl)(4)	$	21.91	$	20.55
Gas ($/Mcf)(5)(6)		4.79		3.04
BOE ($/BOE)(6)		24.12		19.77
Expense ($/BOE):
Production	$	8.19	$	7.20
General and administrative
G&A excluding items below		1.81		1.46
Stock appreciation rights		0.37		0.25
Merger related costs		0.15		—

(1) Reflects the acquisition of 3TEC effective June 1, 2003.

(2) Includes oil, condensate and plant product barrels.

(3) Based on year-end spot market prices of $31.20 per Bbl of oil and $4.79 per MMBtu of gas. PV-10 represents the standardized measure before deducting estimated future income taxes. Future development costs included in PV-10 and standardized measure amounts do not include any amounts for capitalized general and administrative expense or capitalized interest.

(4) Includes the effect of hedges, which reduced the realized oil price by $5.46 per barrel and $1.62 per barrel for the six months ended June 30, 2003 and the year ended December 31, 2002, respectively.

(5) Includes the effect of hedges, which reduced the realized gas price by $1.23 per mcf and $0.19 per Mcf for the six months ended June 30, 2003 and the year ended December 31, 2003, respectively.

(6) 3TEC held certain derivative instruments that they elected not to qualify for hedge accounting under the provisions of SFAS 133. Accordingly, the realized and unrealized gains and losses with respect to such derivatives were recognized currently in 3TEC’s results of operations. At the time of the acquisition, the derivative instruments were assigned to us and were qualified for hedge accounting. The pro forma realized prices presented include the realized gains or losses related to the 3TEC derivatives as if they had been qualified for hedge accounting. The realized price per Mcf for the six months ended June 30, 2003 and the year ended December 31, 2002, includes ($1.12) per Mcf and ($0.19) per Mcf, respectively, related to such derivatives. The realized prices per BOE for the six months ended June 30, 2003 and the year ended December 31, 2002 includes $(2.18) per BOE and ($0.39) per BOE, respectively, related to such derivatives.

16

RISK FACTORS

You should carefully consider the risks described below in addition to other information contained in this prospectus before making an investment decision. Realization of any of the following risks could have a material adverse effect on our business, financial condition, cash flow and results of operations.

Risks Relating to the Exchange Offer

If you do not tender your Series A notes for exchange, your ability to transfer your Series A notes will be limited.

Old Plains issued the Series A notes in a private offering. As a result, the Series A notes have not been registered under the Securities Act and may not be resold by purchasers thereof unless the Series A notes are subsequently registered or an exemption from the registration requirements of the Securities Act is available. The Series A notes that are not tendered in the exchange offer will continue to be subject to the existing restrictions upon their transfer. We will have no obligation to provide for the registration under the Securities Act of unexchanged Series A notes.

Your ability to transfer the notes may be limited by the absence of an active trading market, and there is no assurance that any active trading market will develop for the notes.

The notes are a new issue of securities for which there is no established public market. At the time of the private placement of the Series A notes, the initial purchaser advised Old Plains that it intended to make a market in the Series A notes and the Series B notes, if issued, as permitted by applicable laws and regulations. The Series A notes that were sold to institutional buyers are currently eligible for trading in The PORTAL Market. However, the initial purchaser is not obligated to make a market in the notes, and it may discontinue its market-making activities at any time without notice. Therefore, an active market for the notes may not develop or, if developed, may not continue. Historically, the market for non-investment grade debt has been subject to disruptions that have caused substantial volatility in the prices of securities similar to the notes. The market, if any, for the notes may not be free from similar disruptions and any such disruptions may adversely affect the prices at which you may sell your notes. In addition, subsequent to their initial issuance, the notes may trade at a discount from their initial offering price, depending upon prevailing interest rates, the market for similar notes, our performance and other factors.

Risks Relating to the Notes

We may not be able to generate enough cash flow to meet our debt obligations.

We expect our earnings and cash flow to vary significantly from year to year due to the cyclical nature of our industry. As a result, the amount of debt that we can manage in some periods may not be appropriate for us in other periods. Additionally, our future cash flow may be insufficient to meet our debt obligations and commitments, including the Notes. Any insufficiency could negatively impact our business. A range of economic, competitive, business and industry factors will affect our future financial performance, and, as a result, our ability to generate cash flow from operations and to pay our debt, including the Notes. Many of these factors, such as oil and gas prices, economic and financial conditions in our industry and the global economy or competitive initiatives of our competitors, are beyond our control.

As of June 30, 2003 our total indebtedness was approximately $511.0 million (including a $2.0 million premium and excluding $5.2 million in letters of credit outstanding under our credit facility), $234.0 million of which was senior in right of payment to the Notes and $200.0 million of Initial Notes which were senior subordinated debt that was equal in right of payment to the New Notes. Additionally,

17

at that date we had $169.5 million in additional borrowing capacity under our credit facility (excluding $5.2 million in letters of credit outstanding), which if borrowed would be secured debt senior in right of payment to the Notes.

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

If we do not generate enough cash flow from operations to satisfy our debt obligations, we may have to undertake alternative financing plans, such as:

• refinancing or restructuring our debt;

• selling assets;

• reducing or delaying capital investments; or

• seeking to raise additional capital.

However, we cannot assure you that undertaking alternative financing plans, if necessary, would allow us to meet our debt obligations. Our inability to generate sufficient cash flow to satisfy our debt obligations, including our obligations under the notes, or to obtain alternative financing, could materially and adversely affect our business, financial condition, results of operations and prospects.

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

• increase our vulnerability to general adverse economic and industry conditions;

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

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

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

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

We might incur substantial additional debt in the future, which may restrict our ability to operate and prevent us from fulfilling our obligations under the Notes.

The Note indenture allows us to incur more indebtedness in the future, including initially $300.0 million of secured debt under credit facilities. In addition, we may borrow other funds to finance our business operations. Our level of indebtedness may prevent us from engaging in certain transactions which might otherwise be beneficial to us by limiting our ability to obtain additional financing, limiting our flexibility in operating our business or otherwise. In addition, we could be at a competitive disadvantage against other less leveraged competitors that have more cash flow to devote to their business. Any of these factors could result in a material adverse effect on our business,

18

financial condition, results of operations, business prospects and ability to satisfy our obligations under the Notes.

Your right to receive payments on the Notes is junior to all of our and the subsidiary guarantors’ existing senior indebtedness and any additional senior indebtedness we and the subsidiary guarantors may incur.

The Notes rank behind all of our existing and future senior indebtedness (which excludes trade payables and certain other indebtedness), except any future indebtedness that expressly provides that it ranks equal with, or is subordinated in right of payment to, the Notes. The subsidiary guarantees are similarly subordinated. As a result, upon any distribution to our creditors or the creditors of any subsidiary guarantors in a bankruptcy or similar proceeding relating to us or any subsidiary guarantors, the holders of our senior debt and the senior debt of any subsidiary guarantors will be entitled to be paid in full in cash before any payment may be made with respect to the Notes or any subsidiary guarantees.

In the event of a bankruptcy, liquidation or reorganization or similar proceeding relating to us or any subsidiary guarantor, holders of the Notes will participate with all other holders of our senior subordinated indebtedness and that of any subsidiary guarantors in the assets remaining after we and the subsidiary guarantors have paid all of our senior debt. In any of these cases, we and the subsidiary guarantors may not have sufficient funds to pay all of our creditors and holders of the Notes would receive ratably less than senior creditors.

Restrictions in our existing and future debt agreements could limit our growth and our ability to respond to changing conditions.

The Note indenture and our credit facility contain a number of significant covenants in addition to covenants restricting the incurrence of additional debt. These covenants limit our ability and the ability of our restricted subsidiaries, among other things:

• to pay dividends or distributions on our capital stock or to repurchase our capital stock;

• to repurchase subordinated debt;

• to make certain investments;

• to create certain liens on our assets to secure debt;

• to merge or to enter into other business combination transactions;

• to issue and sell capital stock of our subsidiaries;

• to enter into certain transactions with affiliates; and

• to transfer and sell assets.

Our credit facility requires us to among other things, maintain certain financial ratios, satisfy certain financial condition tests, or reduce our debt. These restrictions will also limit our ability to obtain future financings, withstand a future downturn in our business or the economy in general, or otherwise conduct necessary corporate activities. We may also be prevented from taking advantage of business opportunities that arise because of the limitations that the restrictive covenants under the Note indenture and our credit facility impose on us.

A breach of any covenant in the Note indenture or our credit facility would result in a default under that agreement after any applicable grace periods. A default, if not waived, could result in acceleration of the debt outstanding under the agreement and in a default with respect to, and acceleration of, the debt outstanding under any other debt agreements. The accelerated debt would become immediately

19

due and payable. If that should occur, we may not be able to make all of the required payments or borrow sufficient funds to refinance it. Even if new financing were then available, it may not be on terms that are acceptable to us. Please read “Description of Certain Other Indebtedness” and “Description of Notes—Events of Default.”

We may not be able to repurchase the Notes upon a change of control.

Upon the occurrence of certain change of control events, we would be required to offer to repurchase all or any part of the Notes then outstanding for cash at 101% of the principal amount. The source of funds for any repurchase required as a result of any change of control will be our available cash or cash generated from our oil and gas operations or other sources, including:

• borrowings under our credit facilities or other sources;

• sales of assets; or

• sales of equity.

We cannot assure you that sufficient funds would be available at the time of any change of control to repurchase your Notes after first repaying any of our senior debt that may exist at the time. In addition, restrictions under our credit facility or any future credit facilities will not allow such repurchases. Additionally, a “change of control” (as defined in the indenture) will be an event of default under our credit facility that would permit the lenders to accelerate the debt outstanding under the credit facility. Finally, using available cash to fund the potential consequences of a change of control may impair our ability to obtain additional financing in the future, which could negatively impact our ability to conduct our business operations.

A financial failure by us or our subsidiaries may result in the assets of any or all of those entities becoming subject to the claims of all creditors of those entities.

A financial failure by us or our subsidiaries could affect payment of the Notes if a bankruptcy court were to substantively consolidate us and our subsidiaries. If a bankruptcy court substantively consolidated us and our subsidiaries, the assets of each entity would be subject to the claims of creditors of all entities. This would expose you not only to the usual impairments arising from bankruptcy, but also to potential dilution of the amount ultimately recoverable because of the larger creditor base. Furthermore, forced restructuring of the Notes could occur through the cram-down provision of the bankruptcy code. Under this provision, the Notes could be restructured over your objections as to their general terms, primarily interest rate and maturity.

If the subsidiary guarantees are deemed fraudulent conveyances or preferential transfers, a court may subordinate or void them.

Under various fraudulent conveyance or fraudulent transfer laws, a court could subordinate or void our subsidiary guarantees. Generally, a United States court may void or subordinate a subsidiary guarantee in favor of the subsidiary’s other obligations if it finds that at the time the subsidiary entered into a subsidiary guarantee it:

• intended to hinder, delay or defraud any present or future creditor or contemplated insolvency with a design to favor one or more creditors to the exclusion of others; or

• did not receive fair consideration or reasonably equivalent value for issuing the subsidiary guarantee; or

• at the time it issued the subsidiary guarantee, the subsidiary

• was insolvent or became insolvent as a result of issuing the subsidiary guarantee,

20

• was engaged or about to engage in a business or transaction for which the remaining assets of the subsidiary constituted unreasonably small capital, or

• intended to incur, or believed that it would incur, debts beyond its ability to pay those debts as they matured.

In addition, a guarantee may be voided based on the level of benefits the guarantor received compared to the amount of the subsidiary guarantee. If a subsidiary guarantee is voided or held unenforceable, you would not have any claim against that subsidiary and would be creditors solely of us and Plains E&P Company and any subsidiary guarantors whose guarantees are not held unenforceable. We cannot assure you that, after providing for all prior claims, there would be sufficient assets to satisfy claims of holders of Notes relating to any voided portions of any of the subsidiary guarantees.

There is a risk of a preferential transfer if:

• a subsidiary guarantor declares bankruptcy or its creditors force it to declare bankruptcy within 90 days (or in certain cases, one year) after a payment on the guarantee; or

• a subsidiary guarantee was made in contemplation of insolvency.

The subsidiary guarantee could be voided by a court as a preferential transfer. In addition, a court could require holders of Notes to return any payments made on the Notes during the 90-day (or one-year) period.

Risks Relating to the Merger with 3TEC

We may not realize the benefits of integrating our companies.

We need to combine and integrate the operations of Old Plains and 3TEC into one company. Integration will require substantial management attention and could detract attention away from the day-to-day business of the combined company. We could encounter difficulties in the integration process, such as the loss of key employees or suppliers. If we cannot integrate our businesses successfully, we may fail to realize the benefits we expect to realize from the merger.

Risks Relating to our Business

We will incur significant charges and expenses as a result of the merger with 3TEC which will reduce the amount of capital available to fund our operations.

We expect to incur merger related costs of $4.0 million to $5.0 million during the second half of 2003. Such costs include certain compensation items related to the acquisition of 3TEC, accounting system integration, moving and relocation related to consolidation of office locations and certain severance and relocation costs. We may also incur unanticipated costs in the merger. As a result, we will have less capital available to fund our exploitation, exploration and development activities.

Volatile oil and gas prices could adversely affect our financial condition and results of operations.

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

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

• weather;

21

• 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;

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

• governmental regulations.

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

• our revenues, cash flows and earnings;

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

• the amount that we are allowed to borrow; and

• the value of our oil and gas properties.

Any prolonged, substantial reduction in the demand for oil and gas, or distribution problems in meeting this demand, could adversely affect our business.

Our success is materially dependent upon the demand for oil and gas. The availability of a ready market for our oil and gas production depends on a number of factors beyond our control, including the demand for and supply of oil and gas, the availability of alternative energy sources, the proximity of reserves to, and the capacity of, oil and gas gathering systems, pipelines or trucking and terminal facilities. We may also have to shut-in some of our wells temporarily due to a lack of market or adverse weather conditions including hurricanes. If the demand for oil and gas diminishes, our financial results would be negatively impacted.

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

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

The United States has been at war with Iraq and is currently leading reconstruction efforts in Iraq. Additionally, on September 11, 2001, the United States was the target of terrorist attacks of unprecedented scope, and the United States and other countries instituted military action in response. These conditions have caused instability in the world financial markets and may generate global economic instability. The continued threat of terrorism and the impact of military or other action have led to and will likely lead to increased volatility in prices for oil and gas and could affect the markets for our operations. Further, the United States government has issued public warnings that indicate that energy assets might be specific targets of terrorist organizations. These developments have subjected our operations to increased risk and, depending on the ultimate magnitude, could have a material adverse effect on our business.

Our oil production in California and Illinois is dedicated to a single customer and, as a result, our credit exposure to that customer is significant.

We have entered into an oil marketing agreement with Plains All American Pipeline, L.P., or PAA, under which PAA is the exclusive purchaser of all of our net oil production in California and Illinois. We

22

generally do not require letters of credit or other collateral from PAA to support our trade receivables. Accordingly, a material adverse change in PAA’s financial condition could adversely impact our ability to collect our receivables from PAA and thereby affect our financial condition.

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

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

We may not be successful in acquiring, exploiting, developing or exploring for oil and gas properties.

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

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

• weather;

• compliance with governmental regulations or price controls;

• mechanical difficulties; or

• shortages or delays in the delivery of equipment.

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

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

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

The proved oil and gas reserve information included in this document represents only estimates. These estimates are based on reports prepared by independent petroleum engineers. The estimates were calculated using oil and gas prices in effect on the date indicated in the reports. Any significant price changes will have a material effect on the quantity and present value of our reserves.

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

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

23

• the assumed effects of regulations by governmental agencies;

• assumptions concerning future oil and gas prices; and

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

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

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

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

• the production and operating costs incurred; and

• the amount and timing of future development expenditures.

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

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

Our California oil reserves average 23 degrees API gravity, which is heavier than premium grade light oil. Due to the processes required to refine this type of oil and the transportation requirements, it is difficult to market our oil outside California.

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;

24

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

Consistent with insurance coverage generally available to the industry, our insurance policies provide limited coverage for losses or liabilities. The insurance market in general and the energy insurance market in particular have been difficult markets over the past several years. Upon renewal in June 2002, our cost of insurance increased substantially over the prior year’s amount. In addition, we increased deductibles and decreased or eliminated certain types of coverages to mitigate the cost increase. Insurance costs may continue to increase over the next few years and we may decrease coverage and retain more risk to mitigate future cost increases. If we incur substantial liability and the damages are not covered by insurance or are in excess of policy limits, or if we incur liability at a time when we are not able to obtain liability insurance, then our business, results of operations and financial condition could be materially adversely affected.

Governmental agencies and other bodies, including those in California, might impose regulations that increase our costs and may terminate or suspend our operations.

Our business is subject to federal, state and local laws and regulations as interpreted by governmental agencies and other bodies, including those in California, vested with much authority relating to the exploration for, and the development, production and transportation of, oil and gas, as well as environmental and safety matters. Existing laws and regulations could be changed, and any changes could increase costs of compliance and costs of operating drilling equipment or significantly limit drilling activity.

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.

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:

• weather;

• oil field service costs and availability;

25

• compliance with environmental and other laws and regulations;

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

• failure of equipment or facilities.

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

Environmental liabilities could adversely affect our financial condition.

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

• well drilling or workover, operation and abandonment;

• waste management;

• land reclamation;

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

• controlling air, water and waste emissions.

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

In addition, environmental laws may, in the future, cause a decrease in our production or cause an increase in our costs of production, development or exploration. Pollution and similar environmental risks generally are not fully insurable.

Some fields in our onshore California and Illinois Basin properties have been in operation for more than 90 years, and current or future local, state and federal environmental and other laws and regulations may require substantial expenditures to remediate the properties or to otherwise comply with these laws and regulations. In addition, approximately 183 acres of our 450 acres in the Montebello field have been designated as California Coastal Sage Scrub, a known habitat for the gnatcatcher, which is a species of bird designated as a federal threatened species under the Endangered Species Act. A variety of existing laws, rules and guidelines govern activities that can be conducted on properties that contain coastal sage scrub and gnatcatchers and generally limit the scope of operations that we can conduct on this property. The presence of coastal sage scrub and gnatcatchers in the Montebello field and other existing or future laws, rules and guidelines could prohibit or limit our operations and our planned activities for this property.

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;

26

• the need to integrate acquired operations;

• potential loss of key employees of the acquired companies;

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

• an increase in our expenses and working capital requirements.

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

We intend to continue hedging a portion of our production, which may result in our making cash payments or prevent us from receiving the full benefit of increases in prices for oil and gas.

We reduce our exposure to the volatility of oil and gas prices by actively hedging a portion of our production. Hedging also prevents us from receiving the full advantage of increases in oil or gas prices above the fixed amount specified in the hedge agreement. In a typical hedge transaction, we have the right to receive from the hedge counterparty the excess of the fixed price specified in the hedge agreement over a floating price based on a market index, multiplied by the quantity hedged. If the floating price exceeds the fixed price, we must pay the counterparty this difference multiplied by the quantity hedged even if we had insufficient production to cover the quantities specified in the hedge agreement. Accordingly, if we have less production than we have hedged when the floating price exceeds the fixed price, we must make payments against which there are no offsetting sales of production. If these payments become too large, the remainder of our business may be adversely affected. In addition, our hedging agreements expose us to risk of financial loss if the counterparty to a hedging contract defaults on its contract obligations.

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

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

We do not have key man insurance. For information on our executive officers and our key employees, see “Management.”

We and Plains Resources share and, therefore will compete for, the time and effort of our personnel who provide services to Plains Resources, including directors and officers.

Because certain of our officers and directors provide services to Plains Resources, conflicts of interest could arise between Plains Resources, on the one hand, and us or you, on the other. Additionally, some of these officers and directors own and are awarded from time to time shares, or options to purchase shares, of Plains Resources. Accordingly, their financial interests may not always be aligned with ours or yours and could create, or appear to create, potential conflicts of interest when these officers and directors are faced with decisions that could have different implications for us and Plains Resources.

27

Risks Relating to the Reorganization and Spin-off

Old Plains’ historical financial results as a subsidiary of Plains Resources may not be representative of our results as a separate company.

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

Under our tax allocation agreement with our former parent Plains Resources, if we take actions that cause the distribution of our stock by Plains Resources to its stockholders to fail to qualify as a tax-free transaction, we will be required to indemnify Plains Resources for the resulting tax liability and may not have sufficient financial resources to achieve our growth strategy or ability to repay debt or may prevent a change in control of us.

We have agreed with Plains Resources that we will not take any action inconsistent with any information, covenant or representation provided to the Internal Revenue Service in connection with obtaining the tax ruling stating that the spin-off will generally be tax-free to Plains Resources and its stockholders and we further agreed to be liable for any taxes arising from a breach of that agreement. In addition, we have agreed that, for three years following the spin-off, we will not engage in any transaction that could adversely affect the tax treatment of the spin-off without the prior written consent of Plains Resources, unless we obtains a supplemental tax ruling from the Internal Revenue Service or a tax opinion acceptable to Plains Resources of nationally recognized tax counsel to the effect that the proposed transaction would not adversely affect the tax treatment of the spin-off. Moreover, we will be liable to Plains Resources for any corporate level taxes incurred by Plains Resources as a result of the spin-off or to specified transactions involving us following the spin-off including the acquisition of 50% of our common stock by any person or persons. To the extent the taxes arise as a result of a change of control of Plains Resources, failure of Plains Resources to continue the active conduct of its trade or business or failure of Plains Resources to comply with the representations underlying its tax ruling or a supplemental tax ruling relating to the spin-off, Plains Resources will be solely responsible for the taxes resulting from the spin-off. If there are any corporate level taxes incurred by Plains Resources as a result of the spin-off and not due to any of the factors discussed in the two preceding sentences, we would be responsible for 50% of any such liability. The amount of any indemnification payments would be substantial and would likely result in events of default under all of our credit arrangements. As a result, we likely would not have sufficient financial resources to achieve our growth strategy or, possibly, repay our indebtedness after making these payments.

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

• issue equity in public or private offerings;

• issue equity as part of the consideration in acquisitions of additional assets; or

• undergo a change of control.

28

Our net income could be adversely affected by and we could be required to make substantial cash payments under our stock appreciation rights.

As part of the spin-off, all outstanding options to acquire Plains Resources common stock at the time of the spin-off were “split” between Plains Resources stock options and Plains stock appreciation rights, or SARs.

SARs are subject to variable accounting treatment. As a result, at the end of each quarter, we will 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 legally occurs until December 31. To the extent the closing price at the end of each quarter exceeds the exercise price of each SAR, we will recognize such excess as an accounting charge for the SARs deemed vested to the extent such excess has not previously been recognized as expense. If the quarter-end closing price decreases compared to prior periods, we will recognize credits to income, to the extent we have previously recognized expense. These quarterly charges and credits will make our results of operations depend, in part, on fluctuations in the price of our common stock and could have a material adverse effect on our results of operations. We will incur cash expenditures as SARs are exercised, but our common share count will not increase.

We recognized compensation expense of $2.7 million, representing the difference in our common stock price on December 18, 2002, the date of the spin-off, and the exercise price of each SAR deemed vested on that date. In addition, we recognized compensation expense of $1.0 million, representing the increase in our stock price and the vesting deemed to have occurred from the spin-off date to December 31, 2002. For the six months ended June 30, 2003 we recognized $2.6 million of expense due to the increase in our stock price from $9.75 on December 31, 2002 to $10.81 on June 30, 2003.

At June 30, 2003 we had approximately 3.7 million SARs outstanding of which 1.5 million were vested. If all of the vested SARs were exercised, based on $10.81, the closing price of our common stock as of June 30, 2003, we would pay $3.5 million to holders of the SARs.

29

THE EXCHANGE OFFER

This section of the prospectus describes the proposed exchange offer. While we believe that the description covers the material terms of the exchange offer, this summary may not contain all of the information that is important to you. You should carefully read this entire document for a complete understanding of the exchange offer.

Registration Rights

In connection with the issuance of the Series A notes, we entered into a registration rights agreement with the initial purchasers pursuant to which we agreed, for the benefit of the holders of the Series A notes, to use our reasonable best efforts to file an exchange offer registration statement with the SEC with respect to the exchange offer for the Series B notes. A copy of the registration rights agreement relating to the Series A notes is filed as an exhibit to the registration statement of which this prospectus is a part.

Upon the exchange offer registration statement being declared effective, we agreed to promptly offer the Series B notes in exchange for surrender of the Series A notes. We agreed to use our reasonable best efforts to cause the exchange offer to be completed not later than 90 days after the exchange offer registration statement is declared effective by the SEC.

For each Series A note surrendered to us pursuant to the exchange offer, the holder of such Series A note will receive a Series B note having a principal amount equal to that of the surrendered Series A note. Interest on each Series B note will accrue from the last interest payment date on which interest was paid on the Series A note surrendered in exchange therefore or, if no interest has been paid on such Series A note, from the date of its original issue. The registration rights agreement also provides an agreement to include in this prospectus certain information necessary to allow a broker-dealer who holds Series A notes that were acquired for its own account as a result of market-making activities or other ordinary course trading activities (other than Series A notes acquired directly from us or one of our affiliates) to exchange such Series A notes pursuant to the exchange offer and to satisfy the prospectus delivery requirements in connection with resales of Series B notes received by such broker-dealer in the exchange offer. We agreed to use our reasonable best efforts to maintain the effectiveness of the exchange offer registration statement for these purposes for a period of 180 days after the closing of the exchange offer.

The preceding agreement is needed because any broker-dealer who acquires Series A notes for its own account as a result of market-making activities or other trading activities is required to deliver a prospectus meeting the requirements of the Securities Act. This prospectus covers the offer and sale of the Series B notes pursuant to the exchange offer made hereby and the resale of Series B notes received in the exchange offer by any broker-dealer who held Series A notes of the same series acquired for its own account as a result of market-making activities or other trading activities other than Series A notes acquired directly from us or one of our affiliates.

Based on interpretations by the staff of the SEC set forth in no-action letters issued to third parties, we believe that the Series B notes issued pursuant to the exchange offer would in general be freely tradeable after the exchange offer without further registration under the Securities Act. However, any purchaser of Series A notes who is an “affiliate” of ours or who intends to participate in the exchange offer for the purpose of distributing the related Series B notes

• will not be able to rely on the interpretation of the staff of the SEC,

• will not be able to tender its Series A notes in the exchange offer, and

30

• must comply with the registration and prospectus delivery requirements of the Securities Act in connection with any sale or transfer of the Series A notes unless such sale or transfer is made pursuant to an exemption from such requirements.

Each holder of the Series A notes (other than certain specified holders) who wishes to exchange Series A notes for Series B notes in the exchange offer will be required to make certain representations, including

• that any Series B notes it receives in the exchange offer will be acquired in the ordinary course of business,

• that at the time of the commencement of the exchange offer it has no arrangement or understanding with any person to participate in a distribution of the Series B notes, and

• that it is not an affiliate of Plains Exploration & Production Company or Plains E&P Company.

We further agreed to use our reasonable best efforts to cause to be filed with the SEC a shelf registration statement as soon as practicable after any of the following:

• we determine that we may not effect the exchange offer as contemplated in this prospectus because it would violate any law or interpretations of the staff of the SEC;

• the exchange offer is not for any other reason completed by November 26, 2003;

• any holder of Series A notes is prohibited by law or the applicable interpretations of the staff of the SEC from participating in the exchange offer; or does not receive freely transferable Series B notes on the date of the exchange that may be sold without restriction under federal and state securities laws; or

• any initial purchaser, upon completion of the exchange offer requests that a shelf registration be made in connection with the sale or offering of any of the Series B notes.

For the purposes of the registration rights agreement, transfer restricted securities means each Series A note, until the earlier of:

• the date on which the SEC has declared effective a registration statement covering that Series A note and that Series A note has been disposed of pursuant to that registration statement;

• the date on which that Series A note has been exchanged in the exchange offer for a Series B note that may be resold without restriction under federal and state securities laws;

• the date on which that Series A note has been sold in compliance with Rule 144 or is eligible to be sold pursuant to Rule 144(k) under the Securities Act or any similar provision other than Rule 144A; or

• the date on which that Series A note ceases to be outstanding.

We agreed to use our reasonable best efforts to keep the shelf registration statement continuously effective until the earlier of:

• two years after the date of issuance of the Series A notes; or

• the date on which all of the transfer restricted securities covered by the shelf registration statement have been sold pursuant to the shelf registration statement.

The registration rights agreement provides that:

• if the exchange offer is not completed or any required shelf registration statement is not declared effective on or prior to November 26, 2003, the interest rate on the transfer restricted

31

securities will be increased by 1.00% per annum until the exchange offer is completed or the shelf registration statement is declared effective by the SEC or the Series A notes become freely tradeable under the Securities Act;

• if any required shelf registration statement has been declared effective and thereafter either ceases to be effective or the related prospectus ceases to be usable at any time that we are obligated to maintain its effectiveness and such failure to remain effective or usable exists for more than 30 days (whether or not consecutive) in any 12-month period, then the interest rate on the transfer restricted securities will be increased by 1.00% per annum commencing on the 31st day in such 12-month period and ending on the date that the shelf registration statement has again been declared effective or the prospectus again becomes usable.

Holders of Series A notes will be required to make certain representations to us (as described in the registration rights agreement) to participate in the exchange offer and will be required to deliver information to be used in connection with the shelf registration statement and to provide comments on the shelf registration statement within the time periods set forth in the registration rights agreement in order to have their Series A notes or exchange notes included in the shelf registration statement.

Except as set forth above, after consummation of the exchange offer, holders of Series A notes that are the subject of the exchange offer have no registration or exchange rights under the registration rights agreement. See “—Consequences of Failure to Exchange,” and “—Resale of the Series B Notes; Plan of Distribution.”

Consequences of Failure to Exchange

The Series A notes which are not exchanged for Series B notes in the exchange offer and are not included in a resale prospectus which, if required, will be filed as part of an amendment to the registration statement of which this prospectus is a part, will remain restricted securities and subject to restrictions on transfer. Accordingly, such Series A notes may only be resold

(1) to us, upon redemption thereof or otherwise,

(2) so long as the Series A notes are eligible for resale pursuant to Rule 144A, to a person whom the seller reasonably believes is a qualified institutional buyer within the meaning of Rule 144A, purchasing for its own account or for the account of a qualified institutional buyer to whom notice is given that the resale, pledge or other transfer is being made in reliance on Rule 144A,

(3) in an offshore transaction in accordance with Regulation S under the Securities Act,

(4) pursuant to an exemption from registration in accordance with Rule 144, if available, under the Securities Act,

(5) in reliance on another exemption from the registration requirements of the Securities Act, or

(6) pursuant to an effective registration statement under the Securities Act.

In all of the situations discussed above, the resale must be in accordance with any applicable securities laws of any state of the United States and subject to certain requirements of the registrar or co-registrar being met, including receipt by the registrar or co-registrar of a certification and, in the case of (3), (4) and (5) above, an opinion of counsel reasonably acceptable to us and the registrar.

To the extent Series A notes are tendered and accepted in the exchange offer, the principal amount of outstanding Series A notes will decrease with a resulting decrease in the liquidity in the market therefor. Accordingly, the liquidity of the market of the Series A notes could be adversely affected.

32

Terms of the Exchange Offer

Upon the terms and subject to the conditions set forth in this prospectus and in the letter of transmittal, a copy of which is attached to this prospectus as Annex A, we will accept any and all Series A notes validly tendered and not withdrawn prior to the Expiration Date. We will issue $1,000 principal amount of Series B notes in exchange for each $1,000 principal amount of Series A notes accepted in the exchange offer. Holders may tender some or all of their Series A notes pursuant to the exchange offer. However, Series A notes may be tendered only in integral multiples of $1,000 principal amount.

The form and terms of the Series B notes are the same as the form and terms of the Series A notes, except that

• the Series B notes will have been registered under the Securities Act and will not bear legends restricting their transfer pursuant to the Securities Act, and

• except as otherwise described above, holders of the Series B notes will not be entitled to the rights of holders of Series A notes under the registration rights agreement.

The Series B notes will evidence the same debt as the Series A notes which they replace, and will be issued under, and be entitled to the benefits of, the indenture which governs all of the notes.

Only a registered holder of Series A notes or such holder’s legal representative or attorney-in-fact as reflected on the trustee’s records under the indenture may participate in the exchange offer. There will be no fixed record date for determining holders of the Series A notes entitled to participate in the exchange offer.

Holders of the Series A notes do not have any appraisal or dissenters’ rights under Delaware law or the indenture in connection with the exchange offer. We intend to conduct the exchange offer in accordance with the applicable requirements of the Exchange Act and the SEC’s rules and regulations thereunder.

We shall be deemed to have accepted validly tendered Series A notes when, as and if we have given oral or written notice thereof to the exchange agent. The exchange agent will act as agent for the tendering holders of the Series A notes for the purposes of receiving the Series B notes. The Series B notes delivered in the exchange offer will be issued on the earliest practicable date following our acceptance for exchange of Series A notes.

If any tendered Series A notes are not accepted for exchange because of an invalid tender, the occurrence of certain other events set forth herein or otherwise, certificates for any such unaccepted Series A notes will be returned, without expense, to the tendering holder as promptly as practicable after the Expiration Date.

Holders who tender Series A notes in the exchange offer will not be required to pay brokerage commissions or fees or, subject to the instructions in the letter of transmittal, transfer taxes with respect to the exchange of the Series A notes in the exchange offer. We will pay all charges and expenses, other than certain taxes, in connection with the exchange offer. See “—Fees and Expenses.”

Expiration Date; Extensions; Amendments

The term “Expiration Date” with respect to the exchange offer means 5:00 p.m., New York City time, on October 17, 2003 unless we, in our sole discretion, extend the exchange offer, in which case the term “Expiration Date” means the latest date and time to which the exchange offer is extended.

33

If we extend the exchange offer, we will notify the exchange agent by oral or written notice and will make a public announcement thereof, each prior to 9:00 a.m., New York City time, on the next business day after the previously scheduled Expiration Date.

We reserve the right, in our sole discretion,

• to extend the exchange offer,

• if any of the conditions set forth below under “—Conditions to the Exchange Offer” have not been satisfied, to terminate the exchange offer, or

• to amend the terms of the exchange offer in any manner.

We may effect any such extension or termination by giving oral or written notice thereof to the exchange agent.

Except as specified in the second paragraph under this heading, we will make a public announcement of any such extension, termination or amendment as promptly as practicable. If we amend the exchange offer in a manner determined by us to constitute a material change, we will promptly disclose such amendment in a prospectus supplement that will be distributed to the registered holders of the Series A notes. The exchange offer will then be extended for a period of five to 10 business days, as required by law, depending upon the significance of the amendment and the manner of disclosure to the registered holders.

We will make a timely release of a public announcement of any extension, termination or amendment of the exchange offer to the Dow Jones News Service.

Procedures for Tendering Series A Notes

Tenders of Series A Notes.    The tender by a holder of Series A notes pursuant to any of the procedures set forth below will constitute the tendering holder’s acceptance of the terms and conditions of the exchange offer. Our acceptance for exchange of Series A notes tendered pursuant to any of the procedures described below will constitute a binding agreement between such tendering holder and us in accordance with the terms and subject to the conditions of the exchange offer. Only holders are authorized to tender their Series A notes. The procedures by which Series A notes may be tendered by beneficial owners that are not holders will depend upon the manner in which the Series A notes are held.

DTC has authorized DTC participants that are beneficial owners of Series A notes through DTC to tender their Series A notes as if they were holders. To effect a tender, DTC participants should either (1) complete and sign the letter of transmittal or a facsimile thereof, have the signature thereon guaranteed if required by Instruction 1 of the letter of transmittal, and mail or deliver the letter of transmittal or such facsimile pursuant to the procedures for book-entry transfer set forth below under “—Book-entry delivery procedures,” or (2) transmit their acceptance to DTC through the DTC Automated Tender Offer Program, or ATOP, for which the transaction will be eligible, and follow the procedures for book-entry transfer, set forth below under “—Book-Entry Delivery Procedures.”

Tender of Series A Notes Held in Physical Form.    To tender Series A notes held in physical form in the exchange offer

• a properly completed letter of transmittal applicable to such notes (or a facsimile thereof) duly executed by the tendering holder, and any other documents the letter of transmittal requires, must be received by the exchange agent at one of its addresses set forth in this prospectus, and tendered Series A notes must be received by the exchange agent at such address (or delivery effected through the deposit of Series A notes into the exchange agent’s account with DTC and making book-entry delivery as set forth below), on or prior to the Expiration Date, or

34

• the tendering holder must comply with the guaranteed delivery procedures set forth below.

Letters of transmittal or Series A notes should be sent only to the exchange agent and should not be sent to us.

Tender of Series A Notes Held Through a Custodian.    To tender Series A notes that a custodian bank, depository, broker, trust company or other nominee holds of record, the beneficial owner thereof must instruct such holder to tender the Series A notes on the beneficial owner’s behalf. A letter of instructions from the record owner to the beneficial owner may be included in the materials provided along with this prospectus which the beneficial owner may use in this process to instruct the registered holder of such owner’s Series A notes to effect the tender.

Tender of Series A Notes Held Through DTC.    To tender Series A notes that are held through DTC, DTC participants should either

• properly complete and duly execute the letter of transmittal (or a facsimile thereof), and any other documents required by the letter of transmittal, and mail or deliver the letter of transmittal or such facsimile pursuant to the procedures for book-entry transfer set forth below, or

• transmit their acceptance through ATOP, for which the transaction will be eligible, and DTC will then edit and verify the acceptance and send an Agent’s Message to the exchange agent for its acceptance.

The term “Agent’s Message” means a message transmitted by DTC to, and received by, the exchange agent and forming a part of the Book-Entry Confirmation, which states that DTC has received an express acknowledgment from each participant in DTC tendering the Series A notes and that such participant has received the letter of transmittal and agrees to be bound by the terms of the letter of transmittal and we may enforce such agreement against such participant.

Tendering Series A notes held through DTC must be delivered to the exchange agent pursuant to the book-entry delivery procedures set forth below or the tendering DTC participant must comply with the guaranteed delivery procedures set forth below.

The method of delivery of Series A notes and letters of transmittal, any required signature guarantees and all other required documents, including delivery through DTC and any acceptance or Agent’s Message transmitted through ATOP, is at the election and risk of the person tendering Series A notes and delivering letters of transmittal. Except as otherwise provided in the letter of transmittal, delivery will be deemed made only when actually received by the exchange agent. If delivery is by mail, it is suggested that the holder use properly insured, registered mail with return receipt requested, and that the mailing be made sufficiently in advance of the Expiration Date to permit delivery to the exchange agent prior to such date.

Except as provided below, unless the Series A notes being tendered are deposited with the exchange agent on or prior to the Expiration Date (accompanied by a properly completed and duly executed letter of transmittal or a properly transmitted Agent’s Message), we may, at our option, reject such tender. Exchange of Series B notes for Series A notes will be made only against deposit of the tendered Series A notes and delivery of all other required documents.

Book-Entry Delivery Procedures.    The exchange agent will establish accounts with respect to the Series A notes at DTC for purposes of the exchange offer within two business days after the date of this prospectus, and any financial institution that is a participant in DTC may make book-entry delivery of the Series A notes by causing DTC to transfer such Series A notes into the exchange agent’s account in accordance with DTC’s procedures for such transfer. However, although delivery of

35

Series A notes may be effected through book-entry at DTC, the letter of transmittal (or facsimile thereof), with any required signature guarantees or an Agent’s Message in connection with a book-entry transfer, and any other required documents, must, in any case, be transmitted to and received by the exchange agent at one or more of its addresses set forth in this prospectus on or prior to the Expiration Date, or compliance must be made with the guaranteed delivery procedures described below. Delivery of documents to DTC does not constitute delivery to the exchange agent. The confirmation of a book-entry transfer into the exchange agent’s account at DTC as described above is referred to as a “Book-Entry Confirmation.”

Signature Guarantees.    Signatures on all letters of transmittal must be guaranteed by a recognized member of the Medallion Signature Guarantee Program or by any other “eligible guarantor institution,” as that term is defined in Rule 17Ad-15 under the Exchange Act (each of the foregoing, an “Eligible Institution”), unless the Series A notes tendered thereby are tendered (1) by a registered holder of Series A notes (or by a participant in DTC whose name appears on a DTC security position listing as the owner of such Series A notes) who has not completed either the box entitled “Special Issuance Instructions” or “Special Delivery Instructions” on the letter of transmittal, or (2) for the account of an Eligible Institution. See Instruction 1 of the letter of transmittal. If the Series A notes are registered in the name of a person other than the signer of the letter of transmittal or if Series A notes not accepted for exchange or not tendered are to be returned to a person other than the registered holder, then the signatures on the letter of transmittal accompanying the tendered Series A notes must be guaranteed by an Eligible Institution as described above. See Instructions 1 and 5 of the letter of transmittal.

Guaranteed Delivery.    If a holder desires to tender Series A notes pursuant to the exchange offer and time will not permit the letter of transmittal, certificates representing such Series A notes and all other required documents to reach the exchange agent, or the procedures for book-entry transfer cannot be completed, on or prior to the Expiration Date, such Series A notes may nevertheless be tendered if all the following conditions are satisfied:

• the tender is made by or through an Eligible Institution;

• a properly completed and duly executed notice of guaranteed delivery, substantially in the form we have provided herewith, or an Agent’s Message with respect to guaranteed delivery that we accept, is received by the exchange agent on or prior to the Expiration Date, as provided below; and

• the certificates for the tendered Series A notes, in proper form for transfer (or a Book-Entry Confirmation of the transfer of such Series A notes into the exchange agent’s account at DTC as described above), together with the letter of transmittal (or facsimile thereof), property completed and duly executed, with any required signature guarantees and any other documents required by the letter of transmittal or a properly transmitted Agent’s Message, are received by the exchange agent within three business days after the date of execution of the notice of guaranteed delivery.

The notice of guaranteed delivery may be sent by hand delivery, telegram, facsimile transmission or mail to the exchange agent and must include a guarantee by an Eligible Institution in the form set forth in the notice of guaranteed delivery.

Notwithstanding any other provision hereof, delivery of Series B notes by the exchange agent for Series A notes tendered and accepted for exchange pursuant to the exchange offer will, in all cases, be made only after timely receipt by the exchange agent of such Series A notes (or Book-Entry Confirmation of the transfer of such Series A notes into the exchange agent’s account at DTC as described above), and the letter of transmittal (or facsimile thereof) with respect to such Series A

36

notes, properly completed and duly executed, with any required signature guarantees and any other documents required by the letter of transmittal, or a properly transmitted Agent’s Message.

Determination of Validity.    All questions as to the validity, form, eligibility (including time of receipt), acceptance and withdrawal of tendered Series A notes will be determined by us in our sole discretion, which determination will be final and binding. We reserve the absolute right to reject any and all Series A notes not properly tendered or any Series A notes our acceptance of which, in the opinion of our counsel, would be unlawful.

We also reserve the right to waive any defects, irregularities or conditions of tender as to particular Series A notes. The interpretation of the terms and conditions of our exchange offer (including the instructions in the letter of transmittal) by us will be final and binding on all parties. Unless waived, any defects or irregularities in connection with tenders of Series A notes must be cured within such time as we shall determine.

Although we intend to notify holders of defects or irregularities with respect to tenders of Series A notes through the exchange agent, neither we, the exchange agent nor any other person is under any duty to give such notice, nor shall they incur any liability for failure to give such notification. Tenders of Series A notes will not be deemed to have been made until such defects or irregularities have been cured or waived.

Any Series A notes received by the exchange agent that are not validly tendered and as to which the defects or irregularities have not been cured or waived, or if Series A notes are submitted in a principal amount greater than the principal amount of Series A notes being tendered by such tendering holder, such unaccepted or non-exchanged Series A notes will either be

• returned by the exchange agent to the tendering holders, or

• in the case of Series A notes tendered by book-entry transfer into the exchange agent’s account at the book-entry transfer facility pursuant to the book-entry transfer procedures described below, credited to an account maintained with such book-entry transfer facility.

By tendering, each registered holder will represent to us that, among other things,

• the Series B notes to be acquired by the holder and any beneficial owner(s) of the Series A notes in connection with the exchange offer are being acquired by the holder and any beneficial owner(s) in the ordinary course of business of the holder and any beneficial owner(s),

• the holder and each beneficial owner are not participating, do not intend to participate, and have no arrangement or understanding with any person to participate, in a distribution of the Series B notes,

• the holder and each beneficial owner acknowledge and agree that (x) any person participating in the exchange offer for the purpose of distributing the Series B notes must comply with the registration and prospectus delivery requirements of the Securities Act in connection with a secondary resale transaction with respect to the Series B notes acquired by such person and cannot rely on the position of the Staff of the SEC set forth in no-action letters that are discussed herein under “—Resale of the Series B Notes; Plan of Distribution,” and (y) any broker-dealer that receives Series B notes for its own account in exchange for Series A notes pursuant to the exchange offer must deliver a prospectus in connection with any resale of such Series B notes, but by so acknowledging, the holder shall not be deemed to admit that, by delivering a prospectus, it is an “underwriter” within the meaning of the Securities Act,

• neither the holder nor any beneficial owner is an “affiliate,” as defined under Rule 405 of the Securities Act, of ours except as otherwise disclosed to us in writing, and

37

• the holder and each beneficial owner understands that a secondary resale transaction described in the third bullet above should be covered by an effective registration statement containing the selling securityholder information required by Item 507 of Regulation S-K of the SEC.

Each broker-dealer that receives Series B notes for its own account in exchange for Series A notes, where such Series A notes were acquired by such broker-dealer as a result of market-making activities or other trading activities, must acknowledge that it will deliver a prospectus in connection with any resale of such Series B notes. See “—Resale of the Series B Notes; Plan of Distribution.”

Withdrawal of Tenders

Except as otherwise provided herein, tenders of Series A notes in the exchange offer may be withdrawn, unless accepted for exchange as provided in the exchange offer, at any time prior to the Expiration Date.

To be effective, a written or facsimile transmission notice of withdrawal must be received by the exchange agent at its address set forth herein prior to the Expiration Date. Any such notice of withdrawal must

• specify the name of the person having deposited the Series A notes to be withdrawn,

• identify the Series A notes to be withdrawn, including the certificate number or numbers of the particular certificates evidencing the Series A notes (unless such Series A notes were tendered by book-entry transfer), and aggregate principal amount of such Series A notes, and

• be signed by the holder in the same manner as the original signature on the letter of transmittal (including any required signature guarantees) or be accompanied by documents of transfer sufficient to have the trustee under the indenture register the transfer of the Series A notes into the name of the person withdrawing such Series A notes.

If Series A notes have been delivered pursuant to the procedures for book-entry transfer set forth in “—Procedures for Tendering Series A Notes—Book-Entry Delivery Procedures,” any notice of withdrawal must specify the name and number of the account at the appropriate book-entry transfer facility to be credited with such withdrawn Series A notes and must otherwise comply with such book-entry transfer facility’s procedures.

If the Series A notes to be withdrawn have been delivered or otherwise identified to the exchange agent, a signed notice of withdrawal meeting the requirements discussed above is effective immediately upon written or facsimile notice of withdrawal even if physical release is not yet effected. A withdrawal of Series A notes can only be accomplished in accordance with these procedures.

All questions as to the validity, form and eligibility (including time of receipt) of such notices will be determined by us in our sole discretion, which determination shall be final and binding on all parties. No withdrawal of Series A notes will be deemed to have been properly made until all defects or irregularities have been cured or expressly waived. Neither we, the exchange agent nor any other person will be under any duty to give notification of any defects or irregularities in any notice of withdrawal or revocation, nor shall we or they incur any liability for failure to give any such notification. Any Series A notes so withdrawn will be deemed not to have been validly tendered for purposes of the exchange offer and no Series B notes will be issued with respect thereto unless the Series A notes so withdrawn are retendered. Properly withdrawn Series A notes may be retendered by following one of the procedures described above under “—Procedures for Tendering Series A Notes” at any time prior to the Expiration Date.

38

Any Series A notes which have been tendered but which are not accepted for exchange due to the rejection of the tender due to uncured defects or the prior termination of the exchange offer, or which have been validly withdrawn, will be returned to the holder thereof unless otherwise provided in the letter of transmittal, as soon as practicable following the Expiration Date or, if so requested in the notice of withdrawal, promptly after receipt by us of notice of withdrawal without cost to such holder.

Conditions to the Exchange Offer

The exchange offer is not subject to any conditions, other than that

• the exchange offer, or the making of any exchange by a holder, does not violate applicable law or any applicable interpretation of the staff of the SEC,

• no action or proceeding shall have been instituted or threatened in any court or by or before any governmental agency with respect to the exchange offer, which, in our judgment, might impair our ability to proceed with the exchange offer,

• there shall not have been adopted or enacted any law, statute, rule or regulation which, in our judgment, would materially impair our ability to proceed with the exchange offer, or

• there shall not have occurred any material change in the financial markets in the United States or any outbreak of hostilities or escalation thereof or other calamity or crisis the effect of which on the financial markets of the United States, in our judgment, would materially impair our ability to proceed with the exchange offer.

If we determine in our reasonable discretion that any of the conditions to the exchange offer are not satisfied, we may

• refuse to accept any Series A notes and return all tendered Series A notes to the tendering holders,

• extend the exchange offer and retain all Series A notes tendered prior to the Expiration Date, subject, however, to the rights of holders to withdraw such Series A notes, or

• waive such unsatisfied conditions with respect to the exchange offer and accept all validly tendered Series A notes which have not been withdrawn.

If such waiver constitutes a material change to the exchange offer, we will promptly disclose such waiver by means of a prospectus supplement that will be distributed to the registered holders, and will extend the exchange offer for a period of five to 10 business days, depending upon the significance of the waiver and the manner of disclosure to the registered holders, if the exchange offer would otherwise expire during such five to 10 business day period.

Exchange Agent

JPMorgan Chase Bank, the trustee under the indenture governing the notes, has been appointed as exchange agent for the exchange offer. Questions and requests for assistance, requests for additional copies of this prospectus or of the letter of transmittal and requests for notices of guaranteed delivery and other documents should be directed to the exchange agent addressed as follows:

By Mail:

JPMorgan Chase Bank

600 Travis Street, Suite 1150

Houston, Texas 77002

Attention: Rebecca Newman

39

By Facsimile:

(713) 577-5200

Attention: Rebecca Newman

Confirm by Telephone:

(713) 216-4931

Attention: Rebecca Newman

By Hand:

JPMorgan Chase Bank

600 Travis Street, Suite 1150

Houston, Texas 77002

Attention: Rebecca Newman

Fees and Expenses

We will bear the expenses of soliciting tenders. The principal solicitation is being made by mail; however, additional solicitation may be made by telegraph, telecopy, telephone or in person by officers and regular employees of Plains Exploration & Production Company or our affiliates.

No dealer-manager has been retained in connection with the exchange offer and no payments will be made to brokers, dealers or others soliciting acceptance of the exchange offer. However, reasonable and customary fees will be paid to the exchange agent for its services and it will be reimbursed for its reasonable out-of-pocket expenses.

Our out of pocket expenses for the exchange offer will include fees and expenses of the exchange agent and the trustee under the indenture, accounting and legal fees and printing costs, among others.

We will pay all transfer taxes, if any, applicable to the exchange of the Series A notes pursuant to the exchange offer. If, however, a transfer tax is imposed for any reason other than the exchange of the Series A notes pursuant to the exchange offer, then the amount of any such transfer taxes (whether imposed on the registered holder or any other persons) will be payable by the tendering holder. If satisfactory evidence of payment of such taxes or exemption therefrom is not submitted with the letter of transmittal, the amount of such transfer taxes will be billed directly to such tendering holder.

Accounting Treatment for Exchange Offer

The Series B notes will be recorded at the carrying value of the Series A notes and no gain or loss for accounting purposes will be recognized. The expenses of the exchange offer will be amortized over the term of the Series B notes.

Resale of the Series B Notes; Plan of Distribution

Each broker-dealer that receives Series B notes for its own account pursuant to the exchange offer must acknowledge that it will deliver a prospectus in connection with any resale of Series B notes. This prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer in connection with resales of Series B notes received in exchange for Series A notes where such Series A notes were acquired as a result of market-making activities or other trading activities. In addition, until December 11, 2003 (90 days after the date of this prospectus), all dealers effecting

40

transactions in the Series B notes, whether or not participating in this distribution, may be required to deliver a prospectus. This requirement is in addition to the obligation of dealers to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.

We will not receive any proceeds from any sale of Series B notes by broker-dealers. Series B notes received by broker-dealers for their own account pursuant to the exchange offer may be sold from time to time in one or more transactions

• in the over-the-counter market,

• in negotiated transactions,

• through the writing of options on the Series B notes or a combination of such methods of resale,

• at market prices prevailing at the time of resale,

• at prices related to such prevailing market prices, or

• at negotiated prices.

Any such resale may be made directly to purchasers or to or through brokers or dealers who may receive compensation in the form of commissions or concessions from any such broker-dealer or the purchasers of any such Series B notes.

Any broker-dealer that resells Series B notes that it received for its own account pursuant to the exchange offer and any broker or dealer that participates in a distribution of such Series B notes may be deemed to be an “underwriter” within the meaning of the Securities Act and any profit on any such resale of Series B notes and any commission on concessions received by any such persons may be deemed to be underwriting compensation under the Securities Act. The letter of transmittal states that, by acknowledging that it will deliver a prospectus and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an “underwriter” within the meaning of the Securities Act.

We agreed to permit broker-dealers use of this prospectus to satisfy this prospectus delivery requirement. To the extent necessary to ensure that the prospectus is available for sales of Series B notes by broker-dealers, we agreed to use our reasonable best efforts to keep the exchange offer registration statement continuously effective, supplemented, amended and current for 180 days from the closing of the exchange offer. We will provide sufficient copies of the latest version of this prospectus to broker-dealers within one day after their request at any time during this period.

USE OF PROCEEDS

The exchange offer is intended to satisfy our obligations under the registration rights agreement. We will not receive any cash proceeds from the issuance of the Series B notes offered by this prospectus. In consideration for issuing the Series B notes as contemplated in this prospectus, we will receive in exchange Series A notes in like principal amount, the form and terms of which are the same as the form and terms of the Series B notes, except as otherwise described herein under “The Exchange Offer—Terms of the Exchange Offer.” The Series A notes surrendered in exchange for the Series B notes will be retired and canceled and cannot be reissued. Accordingly, issuance of the Series B notes will not result in any increase in our indebtedness.

41

CAPITALIZATION

The following table sets forth our capitalization as of June 30, 2003.

You should read the capitalization data set forth in the table below in conjunction with “Use of Proceeds,” “Selected Historical Combined Financial and Other Data,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the historical financial statements and notes included in this prospectus.

	As of June 30, 2003
	(Amounts in thousands)
Cash and cash equivalents	$	3,466
Total debt:
Credit facility	$	233,000
8 3/4% Senior Subordinated Notes(1)		275,000
Other		1,022
Total debt		509,022
Stockholders’ equity:
Stockholders’ equity		368,422
Accumulated other comprehensive income		(28,389	)
Total stockholders’ equity		340,033
Total capitalization	$	849,055

(1) These notes are stated at face value and do not reflect the unamortized discount of $3.0 million on the initial notes and premium of $5.0 million on the new notes.

42

SELECTED HISTORICAL CONSOLIDATED FINANCIAL AND OTHER DATA

The following table sets forth Plains’ selected consolidated and combined historical financial information that has been derived from (i) the unaudited consolidated statements of income and cash flows and balance sheets for its business as of and for the six months ended June 30, 2003 and 2002, (ii) the audited consolidated statements of income and cash flows for its business for each of the years ended December 31, 2002, 2001 and 2000, the audited combined statements of income and cash flows for its business for the year ended December 31, 1999 and the audited consolidated balance sheets for its business as of December 31, 2002, 2001 and 2000 and (iii) the unaudited combined statements of income and cash flows for its business for the year ended December 31, 1998 and the unaudited combined balance sheets for its business as of December 31, 1999 and 1998. You should read this financial information in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations of Plains” beginning on page 51 and the financial statements and notes thereto included in this prospectus.

	Six Months Ended June 30,						Year ended December 31,
	2003(1)			2002			2002			2001			2000			1999			1998
	(Amounts in thousands, except per share data)
Statement of Income Data:
Revenues:
Oil sales to Plains All American Pipeline, L.P.	$	119,593		$	81,676		$	193,615		$	174,613		$	199,233		$	109,863		$	63,559
Other oil sales and oil hedging		(24,619	)		(454	)		(15,577	)		282			(72,799	)		(7,473	)		17,857
Gas sales		18,781			4,578			10,299			28,771			16,017			5,095			4,091
Other operating revenues		407			13			226			473			—			—			—
Total revenues		114,162			85,813			188,563			204,139			142,451			107,485			85,507
Costs and Expenses:
Production expenses		45,534			35,082			78,451			63,795			56,228			50,527			42,823
General and administrative
G&A excluding items below		8,757			4,726			10,756			10,210			6,308			4,367			3,218
Stock appreciation rights		2,647			—			3,653			—			—			—			—
Merger related costs		1,097			—			—			—			—			—			—
Spin-off costs		—			—			777			—			—			—			—
Depreciation, depletion and amortization		17,868			13,507			30,359			24,105			18,859			13,329			13,901
Accretion of asset retirement obligation		1,176			—			—			—			—			—			—
Reduction of carrying cost of oil and gas properties(2)		—			—			—			—			—			—			42,920
Total costs and expenses		77,079			53,315			123,996			98,110			81,395			68,223			102,862
Income (loss) from operations		37,083			32,498			64,567			106,029			61,056			39,262			(17,355	)
Expenses of terminated public equity offering					—			(2,395	)		—			—			—			—
Interest expense		(10,194	)		(9,418	)		(19,377	)		(17,411	)		(15,885	)		(14,912	)		(8,828	)
Interest and other income (expense)		(167	)		36			174			463			343			87			74
Income (loss) before income taxes and cumulative effect of accounting change		26,722			23,116			42,969			89,081			45,514			24,437			(26,109	)
Income tax (expense) benefit:
Current		(2,429	)		(4,018	)		(6,353	)		(6,014	)		(2,431	)		(505	)		(4,435	)
Deferred		(8,460	)		(5,016	)		(10,379	)		(28,374	)		(14,334	)		(4,827	)		11,510
Income (loss) before cumulative effect of accounting change		15,833			14,082			26,237			54,693			28,749			19,105			(19,034	)
Cumulative effect of accounting change, net of tax(3)		12,324			—			—			(1,522	)		—			—			—
Net income (loss)	$	28,157		$	14,082		$	26,237		$	53,171		$	28,749		$	19,105		$	(19,034	)
Net income (loss) per common share:
Basic	$	1.07		$	0.58		$	1.08		$	2.20		$	1.19		$	0.79		$	(0.79	)
Diluted		1.06			0.58			1.08			2.20			1.19			0.79			(0.79	)
Weighted averaged common shares outstanding:
Basic(4)		26,414			24,200			24,193			24,200			24,200			24,200			24,200
Diluted		26,682			24,200			24,201			24,200			24,200			24.200			24.200
Other Financial Data:
Ratio of earnings to fixed charges(5)		3.3	x		3.0	x		2.9	x		5.2	x		3.1	x		2.1	x		—	(6)
Net cash provided by operating activities	$	27,914		$	19,776		$	78,826		$	116,808		$	79,464		$	4,609		$	37,182
Net cash provided by (used in) investing activities		(299,403	)		(42,358	)		(64,158	)		(125,880	)		(70,871	)		(59,362	)		(91,838	)
Net cash provided by (used in) financing activities		273,927			22,576			(13,653	)		8,549			(13,132	)		59,690			54,587
Costs incurred(7)		54,293			42,341			64,497			125,753			70,505			59,167			91,693
Balance Sheet Data (end of period):
Cash and cash equivalents	$	3,466		$	7		$	1,028		$	13		$	536		$	5,075		$	138
Working capital		(75,468	)		(18,285	)		(47,436	)		932			(6,861	)		16,169			(12,148	)
Total assets		1,138,561			522,554			550,880			516,755			401,035			360,964			277,792
Total debt		511,013			259,237			233,677			236,694			227,040			240,172			180,483
Stockholders’/combined owners’ equity		340,033			169,130			173,820			180,087			111,032			82,283			63,177

(1) Reflects the acquisition of 3TEC effective June 1, 2003. Effective January 1, 2003 we adopted Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations” (“SFAS 143”). For a discussion of SFAS 143 see our consolidated financial statements and the notes thereto included elsewhere in this prospectus.

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

(3) Cumulative effect of adopting Statement of Financial Accounting Standards No. 143—”Accounting for Asset Retirement Obligations” on January 1, 2003 and Statement of Financial Accounting Standards No. 133—“Accounting for Derivatives,” on January 1, 2001.

(4) Outstanding shares for proceeds prior to 2002 reflect the shares issued in September 2002 when Old Plains was capitalized.

(5) The ratio of earnings to fixed charges is calculated by dividing earnings by fixed charges. For this purpose, “earnings” consist of income before taxes and the cumulative effect of accounting changes and fixed charges. “Fixed charges” consist of interest expense, capitalized interest and that portion of annual rental expense Plains has deemed to represent the interest factor.

(6) In the year ended December 31, 1998, total fixed charges exceeded total adjusted earnings available for payment of fixed charges by $29,165,000.

(7) Does not include costs attributable to the 3TEC acquisition.

43

PLAINS EXPLORATION & PRODUCTION COMPANY

UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS

The following unaudited pro forma consolidated statements of income for the six months ended June 30, 2003 and the year ended December 31, 2002 have been prepared based on the historical consolidated statements of income of Old Plains and 3TEC under the assumptions set forth in the accompanying footnotes. All of the transactions described below are reflected in the historical consolidated balance sheet of Plains at June 30, 2003.

On July 3, 2002, as provided in the Separation Agreement, Plains Resources transferred to Old Plains (previously known as Stocker Resources L.P.) 100% of the capital stock of Arguello Inc., Plains Illinois, Inc., PMCT, Inc. and Plains Resources International Inc. and all amounts payable to it by Old Plains and its subsidiary companies. These transactions are referred to as the “reorganization.” As part of the reorganization, Old Plains was converted into a Delaware corporation on September 18, 2002. The effect of the reorganization is reflected in the Reorganization, Debt Issuance and Spin-off Adjustments in the unaudited pro forma consolidated statements of income for the year ended December 31, 2002.

On July 3, 2002 Old Plains issued the Initial Notes. Also on July 3, Old Plains entered into a $300.0 million revolving credit facility and made initial borrowings of $117.6 million. On July 3, Old Plains distributed the $195.3 million net proceeds from the Initial Notes and $116.7 million of the initial borrowings under the Old Plains credit facility to Plains Resources. The effect of these transactions is reflected in the Reorganization, Debt Issuance and Spin-off Adjustments in the unaudited pro forma consolidated statements of income for the year ended December 31, 2002.

On December 18, 2002 Plains Resources distributed all of the issued and outstanding shares of Old Plains’ common stock to the holders of Plains Resources common stock on the basis of one share of Old Plains’ 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”). Prior to the spin-off, Plains Resources made a $47.2 million cash capital contribution to Old Plains. In addition, prior to the spin-off Plains Resources transferred to Old Plains certain assets and Old Plains assumed certain liabilities of Plains Resources, primarily related to land, unproved oil and gas properties, office equipment and pension obligations. The effect of these transactions is reflected in the Reorganization, Debt Issuance and Spin-off Adjustments in the unaudited pro forma consolidated statement of income for the year ended December 31, 2002.

Historically, general and administrative expenses consist of Old Plains’ direct expenses plus amounts allocated from Plains Resources for various operational, financial, accounting and administrative services provided to Old Plains. We estimate that as a result of the reorganization and the spin-off, our annual general and administrative expenses will increase by approximately $4.1 million over the historical amount for the year ended December 31, 2002 in connection with the reorganization (excluding expenses related to stock appreciation rights, spin-off costs and the effect of acquiring 3TEC).

On June 4, 2003 Old Plains acquired 3TEC for approximately $312.9 million in cash and common stock plus $90.1 million to retire outstanding debt. Under the terms of the agreement 3TEC stockholders received $8.50 in cash and 0.85 shares of our common stock for each share of 3TEC common stock. This transaction has been accounted for using the purchase method of accounting. The effect of this transaction is reflected in the Merger Adjustments in the unaudited pro forma consolidated statements of income.

44

Old Plains and a group of lenders have entered into a three-year, $500.0 million senior revolving credit facility with JPMorgan Chase Bank serving as administrative agent. The credit facility provides for a borrowing base of $402.5 million. Additionally, the credit facility contains a $50.0 million sub-limit on letters of credit. To secure borrowings, 100% of the shares of stock of our domestic subsidiaries have been pledged and we gave mortgages covering 80% of the total present value of our domestic oil and gas properties.

On May 30, 2003 Old Plains issued $75.0 million of 8.75% senior subordinated notes due 2012 (the “new notes”) at an issue price of 106.75%. The pro forma Offering Adjustments reflect the new notes offering and the application of the estimated net proceeds.

The unaudited pro forma consolidated statements of income for the six months ended June 30, 2003 and the year ended December 31, 2002 assume the Reorganization, Debt Issuance, Spin-off and Merger transactions and the new notes offering occurred on January 1, 2003 and 2002, respectively. We believe the assumptions used provide a reasonable basis for presenting the significant effects directly attributable to such transactions.

The unaudited pro forma consolidated financial statements do not purport to represent what our results of operations would have been if such transactions had occurred on such dates. These unaudited pro forma consolidated financial statements should be read in conjunction with the Consolidated Financial Statements of Plains Exploration & Production Company, the Consolidated Financial Statements of 3TEC Energy Corporation and Management’s Discussion and Analysis of Financial Condition and Results of Operations of Plains, included elsewhere herein.

45

Plains Exploration & Production Company

Unaudited Pro Forma Condensed Consolidated Statement of Income

for the Six Months Ended June 30, 2003

(in thousands, except per share data)

	Old Plains Historical			Offering Adjustments			Old Plains Pro forma			3TEC Historical(4)			Merger Adjustments			Combined Company Pro forma Adjusted
Revenues
Oil, gas and plant revenues	$	113,755		$	—		$	113,755		$	73,664		$	(69	)(5)	$	187,350
Gain (loss) on sale of properties					—			—			72			(72	)(10)		—
Gain (loss) on derivative fair value					—			—			(22,385	)		22,385	(12)		—
Gain (loss) on derivative settlements					—			—			(15,546	)		15,546	(12)		—
Other operating revenues		407			—			407			59			(59	)(12)		407
		114,162			—			114,162			35,864			37,731			187,757
Costs and expenses
Production expenses		45,534			—			45,534			12,974			—			58,508
Geological and geophysical		—			—			—			5,023			(5,023	)(10)		—
Dry hole and impairments		—			—			—			2,198			(2,198	)(10)		—
General and administrative		12,501						12,501			4,389			(263	)(10)		16,627
														(17,313	)(6)
														11,290	(7)
Depreciation, depletion and														(641	)(8)
amortization		17,868			32	(1)		17,900			18,229			417	(13)		29,882
Accretion of asset retirement obligation		1,176			—			1,176			84			—			1,260
		77,079			32			77,111			42,897			(13,731	)		106,277
Income from Operations		37,083			(32	)		37,051			(7,033	)		51,462			81,480
Other Income (Expense):
														1,336	(8)
Interest expense		(10,194	)		(2,408	)(2)		(12,602	)		(1,336	)		(889	)(9)		(13,491	)
Derivative fair value gain (loss)		—			—			—						(22,385	)(12)		(22,385	)
Derivative settlement gain (loss)		—			—			—						(15,546	)(12)		(15,546	)
Merger costs		—			—			—			(11,108	)		11,108	(11)		—
Interest and other income														14	(10)
(expense)		(167	)		—			(167	)		(14	)		59	(12)		(108	)
Income Before Income Taxes and Cumulative Effect of Accounting Change		26,722			(2,440	)		24,282			(19,491	)		25,159			29,950
Income tax benefit (expense)		(10,889	)		994	(3)		(9,895	)		7,601			(9,885	)(14)		(12,179	)
Income Before Cumulative Effect of Accounting Change	$	15,833		$	(1,446	)	$	14,387		$	(11,890	)	$	15,274		$	17,771
Earnings per share:
Basic	$	0.60					$	0.54								$	0.44
Diluted	$	0.59					$	0.54								$	0.44
Weighted average shares outstanding
Basic		26,414						26,414						13,673	(15)		40,087
Diluted		26,682						26,682						13,673	(15)		40,355

(footnotes on following page)

46

Offering Adjustments

(1) Reflects amortization of debt issue costs for the period, on a straight line basis that approximates the interest method, over the life of the Notes.

(2) Reflects interest expense at a rate of 7.71% (net of premium on issuance) for the period on the 8.75% Notes issued in the Notes offering, assuming that the Notes were issued on January 1, 2003. A  ¹/8 of 1% change in the interest rate would result in a $39 thousand change in interest expense.

(3) Reflects the income tax effect of the Offering Adjustments based on Old Plains’ historical effective income tax rate.

Merger Adjustments

(4) 3TEC’s historical results of operations for the five months ended May 31, 2003.

(5) Reflects the $0.20 per barrel marketing fee Plains pays to Plains All American Pipeline, L.P.

(6) Reflects the reversal of 3TEC’s historical DD&A expense related to oil and gas properties.

(7) Reflects the effect of the merger on DD&A expense on oil and gas properties under the full cost method.

(8) Reflects the reversal of 3TEC’s amortization of deferred debt issue costs and interest expense with respect to 3TEC’s debt that will be retired in the merger.

(9) Reflects interest expense for the period on $189.2 million of debt incurred in connection with the acquisition net of $1.6 million of capitalized interest. Interest expense is based on an estimated borrowing rate under Old Plains’ senior revolving credit facility (3.1%). Capitalized interest is based on the $61.1 million of purchase price allocated to oil and gas properties not subject to amortization and Old Plains’ effective average interest rate (6.0% based on pro forma debt). A  ¹/8 of 1% change in the interest rate would result in a $0.1 million change in interest expense.

(10) Reflects the reversal of certain 3TEC’s income items that are charged or credited to income under the successful efforts method of accounting that are capitalized under the full cost method of accounting.

(11) Reflects the reversal of 3TEC expenses related to the merger.

(12) Reflects the reclassification of certain 3TEC revenue and expense items to conform to the Plains presentation.

(13) Reflects amortization of estimated debt issue cost for the period, on a straight-line basis that approximates the interest method over the life of the agreement.

(14) Reflects the adjustment of income tax expense to a post-merger effective rate of 41%.

(15) Reflects common shares issued in the merger.

47

Plains Exploration & Production Company

Unaudited Pro Forma Condensed Consolidated Statement of Income

for the Year Ended December 31, 2002

(in thousands, except per share data)

	Old Plains Historical			Reorganization, Debt Issuance and Spin-Off Adjustments			Old Plains Pro forma			Offering Adjustments			Plains Pro forma (Offering)			3TEC Historical			Merger Adjustments			Combined Company Pro forma Adjusted
Revenues
Oil, gas and plant revenues	$	188,337		$	—		$	188,337		$	—		$	188,337		$	103,064		$	(166	)(11)	$	291,235
Gain (loss) on sale of properties		—			—			—			—			—			(159	)		159	(17)		—
Gain (loss) on derivative fair value		—			—			—			—			—			(6,632	)		6,632	(18)		—
Gain (loss) on derivative settlements		—			—			—			—			—			(5,644	)		5,644	(18)		—
Other operating																				(189	)(17)
revenues		226						226			—			226			473			(284	)(18)		226
		188,563			—			188,563			—			188,563			91,102			11,796			291,461
Costs and expenses
Production expenses		78,451			—			78,451			—			78,451			25,326			188	(18)		103,965
Geological and geophysical		—			—			—			—			—			2,683			(2,683	)(17)		—
Dry hole and impairments		—			—			—			—			—			8,918			(8,918	)(17)		—
Surrendered and expired acreage		—			—			—			—			—			860			(860	)(17)		—
General and																				(816	)(17)
administrative(7)		15,186			—			15,186			—			15,186			9,970			310	(18)		24,650
																				(36,002	)(12)
Depreciation,																				24,817	(13)
depletion and					(451	)(2)														(599	)(14)
amortization		30,359			966	(3)		30,874			76	(8)		30,950			37,357			1,000	(16)		57,523
		123,996			515			124,511			76			124,587			85,114			(23,563	)		186,138
Income from Operations		64,567			(515	)		64,052			(76	)		63,976			5,988			35,359			105,323
Other Income (Expense)
Expenses of terminated public equity offering		(2,395	)		—			(2,395	)		—			(2,395	)		—			—			(2,395	)
					9,732	(1)
					9,536	(2)
					(19,556	)(4)														3,962	(14)
Interest expense		(19,377	)		1,463	(5)		(18,202	)		(5,779	)(9)		(23,981	)		(3,962	)		(2,186	)(15)		(26,167	)
Derivative fair value gain (loss)		—			—			—			—			—			—			(6,632	)(18)		(6,632	)
Derivative settlement gain (loss)		—			—			—			—			—			—			(5,644	)(18)		(5,644	)
Interest and other
income																				131	(17)
(expense)		174			—			174			—			174			(629	)		782	(18)		458
Income Before Income Taxes		42,969			660			43,629			(5,855	)		37,774			1,397			25,772	(18)		64,943
Income tax benefit (expense)		(16,732	)		(257	)(6)		(16,989	)		2,280	(10)		(14,709	)		(45	)		(11,223	)(19)		(25,977	)
Net Income(21)	$	26,237		$	403		$	26,640		$	(3,575	)	$	23,065		$	1,352		$	14,549		$	38,966
Earnings Per Share(21)
Basic	$	1.08					$	1.10					$	0.95								$	0.97
Diluted	$	1.08					$	1.10					$	0.95								$	0.97
Weighted Average Shares Outstanding
Basic		24,193						24,193						24,193						16,070	(20)		40,263
Diluted		24,201						24,201						24,201						16,070	(20)		40,271

(footnotes on following page)

48

Reorganization, Debt Issuance and Spin-off Adjustments

Reorganization

(1) Reflects the reversal of historical interest expense related to amounts payable to Plains Resources since such amounts payable were contributed to Old Plains under the terms of the Separation Agreement.

Debt Issuance

(2) Reflects the reversal of historical amortization of debt issue costs and interest expense.

(3) Reflects amortization of debt issue costs for the period, on a straight line basis that approximates the interest method, over the life of the 8.75% notes and Old Plains credit facility.

(4) Reflects interest expense for the period on the notes ($17.7 million) and the Old Plains credit facility ($4.3 million). Interest expense with respect to the notes includes $0.2 million of amortization of original issue discount. Interest expense with respect to the Old Plains credit facility is computed based on Old Pains’ average borrowing rate under the terms of the agreement (3.1%). A  ¹/8 of 1% change in the interest rate with respect to the Old Plains credit facility would result in a $0.1 million change in interest expense. Pro forma amount reflects interest expense after capitalization of $2.4 million.

Spin-off

(5) Reflects the reversal of interest expense for the period on debt retired in December 2002 using the proceeds from $47.2 million of capital contributions by Plains Resources. Interest expense is based on Old Plains’ average borrowing rate under the Plains credit facility (3.1%). A  ¹/8 of 1% change in the interest rate would result in less than a $0.1 million change in interest expense.

Income Taxes

(6) Reflects the income tax effect of (i) the Reorganization Adjustments ($7.5 million expense); (ii) the Debt Issuance Adjustments ($7.8 million benefit); and (iii) the Spin-off Adjustments ($0.6 million expense) based on Old Plains’ historical effective income tax rate.

Stock Appreciation Rights

(7) When the spin-off occurred, Old Plains employees holding options to acquire Plains Resources common stock received an equal number of stock appreciation rights, or SARs, with respect to Old Plains common stock. The exercise price of the SARs is based on the relationship between the price of Plains Resources common stock and Old Plains common stock at the time of the spin-off. With respect to the SARs that were in-the-money at the time of the spin-off, Old Plains recognized an initial accounting charge of $2.7 million in December 2002 as compensation expense equal to the aggregate in-the-money value of the SARs deemed vested at that time. In addition, Old Plains recognized a $1.0 million accounting charge to reflect the movement in its common stock price and the vesting deemed to have occurred from the spin-off date to December 31, 2002.

SARs are subject to variable accounting treatment. As a result, at the end of each quarter, the combined company will compare the closing price of Plains common stock to the exercise price of each SAR. To the extent the closing price exceeds the exercise price of each SAR that is vested or for accounting purposes is deemed vested during the incremental period, the combined company will recognize such excess as an accounting charge to the extent such excess had not been recognized in previous quarters. If such excess is less than the extent to which accounting charges had been recognized in previous quarters, the combined company will recognize the difference as income in the quarter. These quarterly charges and income will make the combined company’s results of operations depend, in part on fluctuations in the price of its common stock and could have a material adverse effect on Plains’ results of operations.

Offering Adjustments

(8) Reflects amortization of debt issue costs for the period, on a straight line basis that approximates the interest method, over the life of the notes.

(9) Reflects interest expense at a rate of 7.71% (net of premium) for the period on the notes, assuming that the notes were issued on January 1, 2002.

(10) Reflects the income tax effect of the Offering Adjustments based on Old Plains’ historical effective income tax rate.

Merger Adjustments

(11) Reflects the $0.20 per barrel marketing fee Old Plains pays to Plains All American Pipeline, L.P.

(12) Reflects the reversal of 3TEC’s historical DD&A expense related to oil and gas properties.

(13) Reflects the effect of the merger on DD&A expense on oil and gas properties under the full cost method.

(14) Reflects reversal of 3TEC’s amortization of deferred debt issue costs and interest expense with respect to 3TEC’s debt that will be retired in the merger.

(15) Reflects interest expense for the period on $189.2 million of debt incurred in connection with the acquisition net of $3.7 million of capitalized interest. Interest expense is based on estimated borrowing rate under the combined company’s senior revolving credit facility (3.1%). Capitalized interest is based on the $61.1 million of purchase price allocated to oil and gas properties not subject to amortization and the combined company’s effective average interest rate (6.0% based on pro forma debt). A  ¹/8 of 1% change in the interest rate would result in a $0.2 million change in interest expense.

(16) Reflects amortization of estimated debt issue cost for the period, on a straight-line basis that approximates the interest method over the life of the agreement.

(17) Reflects the reversal of certain 3TEC income items that are charged or credited to income under the successful efforts method of accounting that are capitalized under the full cost method of accounting.

(18) Reflects the reclassification of certain 3TEC revenue and expense items to conform to the Plains presentation.

(19) Reflects the adjustment of income tax expense to a post-merger effective rate of 40.0%.

(20) Reflects common shares issued in the merger.

Asset Retirement Obligations

(21) Effective January 1, 2003, Old Plains and 3TEC adopted Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations” (“SFAS 143”). If SFAS 143 had been applied effective January 1, 2002, the combined company’s pro forma adjusted net income and diluted earnings per share would have been $39.7 million and $0.99, respectively.

49

Prior to the merger, 3TEC held certain derivative instruments that had not been qualified for hedge accounting under the provisions of SFAS 133. Accordingly, unrealized gains and losses with respect to such derivatives were recognized currently in 3TEC’s results of operations and are reflected in this manner in the proforma information presented above. Unrealized losses included in 3TEC’s results of operations totaled $22.4 ($13.2 million after tax) million for the six months ended June 30, 2003 and $6.6 million ($3.9 million after tax) for the year ended December 31, 2002. At the time of the merger such derivative instruments were assigned to us and were qualified for hedge accounting in accordance with the provisions of SFAS 133. If such derivative instruments had been qualified for hedge accounting by 3TEC, proforma income before cumulative effect of accounting change would have been $31.0 million ($0.77 per basic share and $0.76 per diluted share) for the six months ended June 30, 2003 and net income would have been $42.9 million ($1.07 per basic and diluted share) for the year ended December 31, 2002.

Plains Exploration & Production Company

Pro Forma Reserve Data

	Old Plains			3TEC			Combined Company Pro forma Adjusted
Estimated Quantities of Oil & Gas Reserves at December 31, 2002
Proved Reserves
Oil (MBbl)		240,161			6,208			246,369
Gas (MMcf)		77,154			259,026			336,180
Proved Developed Reserves
Oil (MBbl)		127,415			5,546			132,961
Gas (MMcf)		53,317			205,301			258,618
Standardized Measure of Discounted Future Net Cash Flows at December 31, 2002 (in thousands)
Future cash inflows	$	6,819,645		$	1,285,657		$	8,105,302
Future development costs		(431,841	)		(53,127	)		(484,968	)
Future production expense		(2,528,065	)		(284,860	)		(2,812,925	)
Future income tax expense		(1,446,528	)		(277,372	)		(1,723,900	)
Future net cash flows		2,413,211			670,298			3,083,509
Discounted at 10% per year		(1,529,704	)		(320,858	)		(1,850,562	)
Standardized measure of discounted future net cash flows	$	883,507		$	349,440		$	1,232,947

50

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 in this prospectus.

Corporate Reorganization and Spin-off

Under the terms of a Master Separation Agreement between Old Plains and Plains Resources, on July 3, 2002 Plains Resources contributed to Old Plains (i) 100% of the capital stock of its wholly owned subsidiaries Arguello Inc., Plains Illinois Inc., PMCT Inc. and Plains Resources International Inc.; and (ii) all amounts payable to it by Old Plains and its subsidiary companies.

Prior to December 18, 2002 Old Plains was a wholly owned subsidiary of Plains Resources. On December 18, 2002 Plains Resources distributed 100% of the issued and outstanding shares of Old Plains’ 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 Old Plains’ common stock for each share of Plains Resources common stock held. Prior to the spin-off, Plains Resources made an aggregate of $52.2 million in cash contributions to Old Plains and transferred to it certain assets and Old Plains assumed certain liabilities of Plains Resources, primarily related to land, unproved oil and gas properties, office equipment and pension obligations. Old Plains used the cash contributions to reduce outstanding debt under its revolving credit facility.

Acquisition of 3TEC Energy Corporation

On June 4, 2003 we acquired 3TEC Energy Corporation, or 3TEC, the merger, for approximately $312.9 million in cash and common stock plus $90.1 million to retire 3TEC’s outstanding debt. Prior to the merger, 3TEC was engaged in the upstream activities of acquiring, exploiting, developing and producing oil and gas in East Texas and the Gulf Coast region, both onshore and in the shallow waters of the Gulf of Mexico. In the transaction, each 3TEC common share was converted in to 0.85 of a share of our common stock and $8.50 in cash. In connection with the merger, we paid cash consideration to the common shareholders of approximately $152.4 million and issued 15.3 million shares. In addition, we paid cash consideration of $8.3 million and issued 0.8 million common shares to redeem outstanding warrants. The cash portion of the purchase price was funded by the issuance of $75.0 million of senior subordinated notes and amounts borrowed under our revolving credit facility. We have accounted for the acquisition of 3TEC as a purchase with effect from June 1, 2003.

General

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

• California;

• the Gulf Coast; and

• East Texas.

We follow the full cost method of accounting whereby all costs associated with property acquisition, exploration, exploitation and development activities are capitalized. Under the full cost method, we capitalize internal general and administrative costs that can be directly identified with our acquisition, exploration and development activities and do not capitalize any costs related to production, general corporate overhead or similar activities. Our revenues are derived from the sale of

51

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 and long term. If oil and gas prices decline significantly in the future, write-downs of our oil and gas properties could occur. Write-downs required by these rules do not directly impact our cash flows from operating activities. Decreases in oil and gas prices have had, and will likely have in the future, an adverse effect on the carrying value of our proved reserves and our revenues, profitability and cash flow.

To manage our exposure to commodity price risks, we use various derivative instruments to hedge our exposure to oil and gas sales price fluctuations. Our hedging arrangements provide us protection on the hedged volumes if oil or gas prices decline below the prices at which these hedges are set. However, if oil or gas prices increase, ceiling prices in our hedges may cause us to receive less revenues on the hedged volumes than we would receive in the absence of hedges. Gains and losses from hedging transactions are recognized as revenues when the associated production is sold.

Our oil and gas production expenses include salaries and benefits of personnel involved in production activities, electric costs, maintenance costs, production, ad valorem and severance taxes, and other costs necessary to operate our producing properties. Depletion of capitalized costs of producing oil and gas properties is provided using the units of production method based upon proved reserves. For the purposes of computing depletion, proved reserves are redetermined as of the end of each year and on an interim basis when deemed necessary. General and administrative expenses consist primarily of salaries and related benefits of administrative personnel, office rent, systems costs and other administrative costs. We estimate that as a result of Old Plains’ reorganization and spin-off, our annual general and administrative expenses will increase by approximately $4.1 million over the amount reported for the year ended December 31, 2002 (excluding expense related to stock appreciation rights, spin-off costs and the effect of the 3TEC merger) reflecting the incremental costs of operating as a separate, publicly held company.

Tax expense and effective tax rates for periods prior to the spin-off have been calculated based on the tax sharing agreement covering all the members of the Plains Resources consolidated group on a combined basis for such periods through the spin-off date.

52

Results of Operations

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

	Six months ended June 30,						Year ended December 31,
	2003(1)			2002			2002			2001			2000
Sales Volumes
Oil and liquids (MBbls)		4,468			4,113			8,783			8,219			7,654
Gas (MMcf)		3,474			1,719			3,362			3,355			3,042
MBOE		5,047			4,400			9,343			8,778			8,161
Daily Average Sales Volumes
Oil (Bbls)		24,685			22,724			24,062			22,518			20,911
Gas (Mcf)		19,193			9,497			9,211			9,192			8,312
BOE		27,884			24,307			25,597			24,050			22,296
Unit Economics (in dollars)
Average Oil Sales Price ($/Bbl)
Average NYMEX	$	31.32		$	24.02		$	26.15		$	26.01		$	30.25
Hedging revenue (expense)		(5.88	)		(0.11	)		(1.77	)		0.03			(9.51	)
Differential		(4.18	)		(4.16	)		(4.11	)		(4.76	)		(4.22	)
Net realized	$	21.26		$	19.75		$	20.27		$	21.28		$	16.52
Average Gas Sales Price ($/Mcf)
Average price before hedge	$	5.83		$	2.66		$	3.06		$	8.58		$	5.26
Hedging revenue (expense)		(0.42	)		—			—			—			—
Net realized price	$	5.41		$	2.66		$	3.06		$	8.58		$	5.26
Average Realized Price per BOE	$	22.54		$	19.50		$	20.16		$	23.20		$	17.46
Average Production Expenses per BOE		(9.02	)		(7.97	)		(8.40	)		(7.27	)		(6.89	)
Gross Margin per BOE		13.52			11.53			11.76			15.93			10.57
G&A per BOE
G&A excluding items below	$	(1.74	)	$	(1.07	)	$	(1.16	)	$	(0.16	)	$	(0.77	)
Stock appreciation rights		(0.52	)		—			(0.39	)		—			—
Merger related costs		(0.22	)		—			—			—			—
Spin-off costs		—			—			(0.08	)		—			—
Gross Profit per BOE	$	11.04		$	10.46		$	10.13		$	14.77		$	9.80
DD&A per BOE (oil and gas properties)	$	3.36		$	3.04		$	3.17		$	2.70		$	2.25

(1) Reflects the acquisition of 3TEC effective June 1, 2003.

53

Comparison of Six Months Ended June 30, 2003 to Six Months Ended June 30, 2002

Net income.    We reported six months 2003 net income of $28.2 million, or $1.06 per diluted share compared to net income of $14.1 million, or $0.58 per diluted share for the first six months of 2002. Net income in the first six months of 2003 includes the effect of the properties acquired in 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”.

Oil and gas revenues.    Our oil and gas revenues, excluding the effect of hedging and the 3TEC properties, increased 48%, or $41.8 million, to $128.1 million for the first six months of 2003 from $86.3 million for the first six months of 2002. The increase was primarily due to increased sales prices that increased revenues by $34.8 million and higher volumes that increased revenues by $7.0 million. Oil and gas revenues from the 3TEC properties totaled $13.6 million in the first six months of 2003. Hedging had the effect of decreasing our oil and gas revenues by $27.7 million in 2003 compared to $0.5 million in 2002.

Our average realized price for oil increased 8%, or $1.51 to $21.26 per Bbl for the first six months of 2003 from $19.75 per Bbl for the first six months of 2002. The increase is primarily attributable to an improvement in the NYMEX oil price, which averaged $31.32 per Bbl in 2003 versus $24.02 per Bbl in 2002. The average differential for location and quality was $4.18 per Bbl in 2003 compared to $4.16 per Bbl in 2002. Hedging losses decreased our average price per Bbl by $5.88 in 2003 compared to $0.11 per Bbl in 2002.

Our average realized price for gas increased 103%, or $2.75, to $5.41 per Mcf for the first six months of 2003 from $2.66 per Mcf for the year earlier period. The increase is primarily attributable to an improvement in the NYMEX average price, which averaged $5.63 in 2003 versus $2.93 in 2002. Hedging losses during 2003 of $0.42 per Mcf were offset by a $0.47 per Mcf improvement in our average differential from the year earlier period.

Production expenses.    Our production expenses increased 29%, or $9.6 million, to $42.4 million for the first six months of 2003 from $32.8 million for the first six months of 2002, primarily from our increased ownership percentage in the offshore California properties and the acquisition of the 3TEC properties. The 3TEC properties accounted for $1.4 million of our 2003 production expenses. On a per unit basis, production expenses increased 13%, or $0.95 per BOE, to $8.39 per BOE for the first six months of 2003 from $7.44 per BOE for the first six months of 2002, primarily due to our increased ownership percentage in the offshore California properties which have a higher per unit production cost than our other properties, as well as higher fuel and electricity costs. Unit production expenses for the offshore California properties will continue to increase as production declines due to the large component of fixed expenses for this asset.

Production and ad valorem taxes.     Our production and ad valorem taxes increased 26%, or $0.6 million, to $2.9 million for the first six months of 2003 from $2.3 million for the first six months of 2002. Production and ad valorem taxes in the first six months of 2003 include $0.7 million attributable to the 3TEC properties.

Gathering and transportation expenses.    Gathering and transportation expense, which totaled $0.3 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.    Our general and administrative, or G&A, expense, excluding amounts attributable to stock appreciation rights and certain merger-related costs, increased 87%, or $4.1 million, to $8.8 million for the first six months of 2003 from $4.7 million for the first six months of 2002. As a result of our reorganization and spin-off our G&A expenses have increased, reflecting the incremental costs of operating as a separate, publicly held company.

54

G&A expense for 2003 includes a non-cash charge of $2.6 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 June 30, 2003 was $10.81 as compared to $9.75 on December 31, 2002 we recorded a non-cash expense. G&A expense for the first six months of 2003 includes $1.1 million related to the merger.

G&A expense does not include amounts capitalized as part of our acquisition, exploration and development activities. We capitalized $4.6 million and $3.0 million of G&A expense in the first six months of 2003 and 2002, respectively.

Depreciation, depletion and amortization, or DD&A.    Our DD&A expense increased 33%, or $4.4 million, to $17.9 million for the first six months of 2003 from $13.5 million for the first six months of 2002. Approximately $3.6 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 $3.97 per BOE for the period subsequent to the merger as compared to $3.18 per BOE prior to the merger. In the first six months of 2002 our rate was $3.02 per BOE. DD&A attributable to production from the 3TEC properties totaled $1.6 million in the first six months of 2003. Other DD&A expense increased approximately $0.8 million, primarily from amortization of debt issue costs related to our senior subordinated debt and our revolving credit facility.

Accretion of asset retirement obligation.    Accretion expense for the first six months of 2003 was $1.2 million. Accretion expense represents the adjustment of our asset retirement obligation to its present value at the end of the period based on our credit adjusted risk free rate.

Interest expense.    Our interest expense increased 9%, or $0.8 million, to $10.2 million for the first six months of 2003 from $9.4 million for 2002 due to higher outstanding debt as a result of the merger. We capitalized approximately $0.9 million and $1.4 million of interest in the first six months of 2003 and 2002, respectively.

Interest and other income (expense).    Interest and other income (expense) in 2003 includes $0.2 million of costs related to refinancing our credit facility in connection with the merger.

Income tax expense.    Our income tax expense increased 21%, or $1.9 million, to $10.9 million for the first six months of 2003 from $9.0 million for the first six months of 2002. Our overall effective tax rate increased to 40.8% in 2003 from 39.1% in 2002. Our currently payable effective tax rate was 9.1% for 2003 as compared to 17.4% 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.

Cumulative effect.    The cumulative effect of accounting change recognized for the first six months of 2003 was for the adoption of Statement of Financial Accounting Standards No. 143 “Accounting for Asset Retirement Obligations,” as amended.

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

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

Operating revenues.    Old Plains’ operating revenues decreased 8%, or $15.5 million, to $188.6 million for the year ended December 31, 2002 from $204.1 million for the year ended December 31, 2001. The decrease was primarily due to lower realized prices for oil and gas that reduced revenues by $26.8 million. Higher volumes increased revenues by $11.5 million.

55

Old Plains’ daily oil sales volumes increased 7%, or 1.6 MBbls, to 24.1 MBbls per day for the year ended December 31, 2002 from 22.5 MBbls for the year ended December 31, 2001 primarily due to the effect of the acquisition of an additional 26.3% interest in Old Plains’ offshore California properties in 2002 which doubled its working interest in these properties. Old Plains’ daily gas sales volumes were 9.2 MMcf per day for the year ended December 31, 2002, unchanged from the year ended December 31, 2001.

Old Plains’ average realized price for oil and natural gas liquids decreased 5%, or $1.01 to $20.27 per Bbl for the year ended December 31, 2002 from $21.28 per Bbl for the year ended December 31, 2001 primarily due to the effect of its hedges in 2002. For the year ended December 31, 2002, its hedges decreased its average oil price by $1.77 per barrel compared to a $.03 per Bbl increase in 2001. The increased hedging cost was partially offset by a 14%, or $0.65 per Bbl improvement in location and quality differentials over the same periods. The average NYMEX oil price increased 1%, or $0.14, to $26.15 per Bbl for the year ended December 31, 2002 from $26.01 per Bbl for the year ended December 31, 2001. The average realized price for gas decreased 64%, or $5.52, to $3.06 per Mcf for the year ended December 31, 2002 from $8.58 per Mcf in 2001. Gas prices were unusually high in 2001, particularly in California.

Production expenses.    Old Plains’ production expenses increased 23%, or $14.7 million, to $78.5 million for the year ended December 31, 2002 from $63.8 million for the year ended December 31, 2001. On a per unit basis, production expenses increased 16%, or $1.13 per BOE, to $8.40 per BOE for the year ended December 31, 2002 from $7.27 per BOE for the year ended December 31, 2001. Production expenses for 2001 were reduced by approximately $0.25 per BOE as a result of nonrecurring credits (primarily the sale of certain California emissions credits). Excluding these credits, production expenses increased 12% per BOE in 2002, primarily due to increased workover and maintenance expense, insurance expense and electricity costs in California as well as Old Plains’ increased ownership percentage in the offshore California properties, which have a higher per unit production cost than Old Plains’ other properties. Unit production expenses for the offshore California properties will continue to increase as production declines due to the large component of fixed expenses for this asset.

General and administrative expense.    Old Plains’ general and administrative, or G&A, expense, excluding amounts attributable to stock appreciation rights and costs related to the spin-off from Plains Resources, increased 6%, or $0.6 million, to $10.8 million in 2002 from $10.2 million in 2001. This increase was primarily due to higher personnel cost. G&A expense for 2002 includes approximately $0.8 million of legal and other costs related to the spin-off and approximately $3.7 million of expense attributable to the in-the-money value of stock appreciation rights issued on the spin-off date. G&A expense does not include amounts capitalized as part of Old Plains’ acquisition, exploration and development activities. Old Plains capitalized $6.3 million and $6.2 million of G&A expense in 2002 and 2001, respectively.

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

Expenses of terminated public equity offering.    In conjunction with the termination of Old Plains’ proposed initial public equity offering it expensed costs incurred of $2.4 million in 2002.

56

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

Income tax expense.    Old Plains’ income tax expense decreased 51%, or $17.7 million to $16.7 million for the year ended December 31, 2002 from $34.4 million for the year ended December 31, 2001. The decrease was primarily due to decreases in pre-tax income. Old Plains’ overall effective tax rate increased slightly to 38.9% in 2002 from 38.6% for the year ended December 31, 2001. Old Plains’ currently payable effective tax rate was 14.8% for the year ended December 31, 2002 as compared to 6.8% for the year ended December 31, 2001. The increased currently payable effective rate in 2002 primarily reflects lower expenditures that are expensed for tax purposes and capitalized for financial reporting purposes and the $3.7 million in expense related to stock appreciation rights that is not deductible until paid. Tax expense and effective tax rates for the periods prior to the spin-off on December 18, 2002 were calculated based on the tax sharing agreement with Plains Resources.

Comparison of Year Ended December 31, 2001 to Year Ended December 31, 2000

Net income.    Old Plains reported net income of $53.2 million, or $2.20 per diluted share, for the year ended December 31, 2001 compared to net income of $28.7 million, or $1.19 per diluted share for 2001. A discussion of the reasons for the increase follows.

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

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

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

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

General and administrative expense.    Old Plains’ G&A expense increased 62%, or $3.9 million, to $10.2 million in 2001 from $6.3 million in 2000. This increase was primarily due to a $3.7 million increase in G&A expenses allocated by Plains Resources. The increase in Plains Resources’ G&A expenses was primarily due to costs related to its 2001 corporate reorganization. G&A expense does not include amounts capitalized as part of Old Plains’ acquisition, exploration and development activities. Old Plains capitalized $6.2 million and $5.2 million of G&A expense in 2001 and 2000, respectively.

57

Depreciation, depletion and amortization.    Old Plains’ DD&A expense increased 28%, or $5.2 million, to $24.1 million in 2001 from $18.9 million in 2000, as its oil and gas DD&A rate increased 20%, or $0.45, to $2.70 per BOE in 2001 from $2.25 per BOE in 2000. DD&A is affected by many factors, including production levels, costs incurred in the acquisition, exploitation and development of proved reserves and estimates of proved reserve quantities and future development costs. The increase in Old Plains’ DD&A rate in 2001 was primarily due to its capital program resulting in higher costs being subject to DD&A and, to a lesser extent, to higher estimated future development costs.

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

Income tax expense.    Old Plains’ income tax expense increased 105%, or $17.6 million, to $34.4 million in 2001 from $16.8 million in 2000. The increase was primarily due to a 96% increase in income before income taxes and cumulative effect of accounting change from $45.5 million in 2000 to $89.1 million in 2001. In addition, Old Plains’ effective tax rate increased to 38.6% in 2001 from 36.8% in 2000.

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

Liquidity and Capital Resources

Our primary sources of liquidity are cash generated from our operations and our revolving credit facility. At June 30, 2003 we had $164.3 million of availability under our 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.

Financing Activities.    On July 3, 2002 Old Plains issued the Initial Notes, or $200.0 million principal amount of 8.75% senior subordinated notes. The Initial 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. On July 3, 2002 Old Plains also entered into a $300.0 million revolving credit facility with a borrowing base of $225.0 million.

Old Plains distributed the net proceeds of $195.3 million from the Initial Notes and $116.7 million in initial borrowings under its credit facility to Plains Resources, which used it to repay debt. Old Plains’ guarantees of Plains Resources debt facilities were terminated when it retired such obligations.

On April 4, 2003, Old Plains entered into a credit facility with a syndicate of banks led by JPMorgan Chase Bank for a three-year, $500.0 million senior revolving credit facility. See “—Capital Requirements” for a summary of the credit facility terms.

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

As of June 30, 2003 we had $233.0 million in borrowings and $5.2 million in letters of credit outstanding under our $500.0 million revolving credit facility. The credit facility provides for a borrowing base of $402.5 million that will be reviewed every six months, with the lenders and us each having the right to one annual interim unscheduled redetermination, and adjusted based on our oil and gas properties, reserves, other indebtedness and other relevant factors, and matures in April 2006. The credit facility contains a $50.0 million sub-limit on letters of credit. To secure borrowings, we pledged

58

100% of the shares of stock of our domestic subsidiaries, who also unconditionally guarantee payments under the credit facility, and gave mortgages covering 80% of the total present value of our domestic oil and gas properties.

Amounts borrowed under the credit facility bear an annual interest rate, at our election, equal to either; (i) the Eurodollar rate, plus from 1.375% to 2.00%; or (ii) the greatest of (1) the prime rate, as determined by JPMorgan Chase Bank, (2) the certificate of deposit rate, plus 1.0%, or (3) the federal funds rate, plus 0.5%; plus an additional 0.125% to .75% for each of (1)-(3). The amount of interest payable on outstanding borrowings will be based on (1) the utilization rate as a percentage of the total amount of funds borrowed under the credit facility to the borrowing base and (2) our long-term debt rating. Commitment fees and letter of credit fees under the credit facility are based on the utilization rate and long-term debt rating. Commitment fees range from 0.375% to 0.5% of the unused portion of the borrowing base. Letter of credit fees range from 1.375% to 2.0%. The issuer of any letter of credit receives an issuing fee of 0.125% of the undrawn amount.

The credit facility contains negative covenants that limit our ability, as well as the ability of our subsidiaries, among other things, to incur additional debt, pay dividends on stock, make distributions of cash or property, change the nature of our business or operations, redeem stock or redeem subordinated debt, make investments, create liens, enter into leases, sell assets, sell capital stock of subsidiaries, create subsidiaries, guarantee other indebtedness, enter into agreements that restrict dividends from subsidiaries, enter into certain types of swap agreements, enter into gas imbalance or take-or-pay arrangements, merge or consolidate and enter into transactions with affiliates. In addition, the credit facility requires us to maintain a current ratio, which includes availability, of at least 1.0 to 1.0 and a minimum tangible net worth (as defined). At June 30, 2003, we were in compliance with the covenants contained in our credit facility and could have borrowed the full $402.5 million available under the credit facility.

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

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

We have been assigned a Ba3 senior implied rating and the notes have been assigned a B2 rating by Moody’s Investors Service, Inc. We have also been assigned a BB- corporate credit rating by Standard and Poor’s Ratings Group. All of these ratings are below investment grade. As a result, at times we may have difficulty accessing capital markets or raising capital on favorable terms.

At June 30, 2003 we had a working capital deficit of $75.5 million. The working capital deficit includes $38.1 million attributable to the fair value of our hedges, $9.3 million attributable to accrued

59

interest on our 8.75% notes and $3.8 million that reflects the in-the-money value of stock appreciation rights that were deemed vested at June 30, 2003. Interest on the 8.75% notes is payable semi-annually on January 1 and July 1 of each year. In accordance with SFAS No. 133 “Accounting for Derivative Instruments and Hedging Activities”, the fair value of all derivative instruments is recorded on the balance sheet. Gains and losses on hedging instruments are included in oil and gas revenues in the period that the related volumes are delivered. The hedge agreements provide for monthly settlement based on the differential between the agreement price and actual NYMEX oil or gas price. Cash received for the sale of physical production will be based on actual market prices and will generally offset any gains or losses on the hedge instruments. The remaining working capital deficit of $24.3 million will be financed through cash flow and borrowings under our credit facility.

When it was the owner of 100% of Old Plains’ capital stock, Plains Resources made an aggregate of $52.2 million of cash contributions to Old Plains from the date of its reorganization to the date of the spin-off. Certain of the contributions were part of the working capital for the upstream assets contributed to Old Plains. These contributions increased stockholders’ equity by $52.2 million, $5.0 million in the third quarter of 2002 and the remaining $47.2 million in the fourth quarter of 2002. Old Plains used these funds to reduce outstanding debt under its revolving credit facility.

Cash Flows

	Six Months Ended June 30,						Year Ended December 31,
	2003			2002			2002			2001			2000
	(in millions)
Cash provided by (used in):
Operating activities	$	27.9		$	19.8		$	78.8		$	116.8		$	79.5
Investing activities		(299.4	)		(42.4	)		(64.2	)		(125.9	)		(70.9	)
Financing activities		273.9			22.6			(13.7	)		8.5			(13.1	)

Net cash provided by operating activities was $27.9 million and $19.8 million for the first six months of 2003 and 2002, respectively. The increase primarily reflects higher prices and sales volumes, partially offset by higher production costs. Net cash provided by operating activities was $78.8 million, $116.8 million and $79.5 million for 2002, 2001 and 2000, respectively. The decrease in 2002 as compared to 2001 is primarily attributable to lower realized prices and increased production costs. The increase in 2001 as compared to 2000 is primarily attributable to higher realized prices in 2001 due to the effects of hedging in 2000.

Net cash used in investing activities was $299.4 million in the first six months of 2003 and $42.4 million in the first six months of 2002. Such amount for 2003 includes $251.9 million related to the merger. Costs incurred in connection with our oil and gas acquisition, development and exploration activities totaled $46.8 million in 2003 compared to $42.3 million in 2002. Net cash used in investing activities was $64.2 million, $125.9 million and $70.9 million for 2002, 2001 and 2000, respectively, and consist primarily of costs incurred in connection with Old Plains’ oil and gas acquisition, development and exploration activities. The 2002 capital expenditure level was reduced from the 2001 amount to manage debt levels and allow flexibility in pursuing acquisition and other opportunities. The capital expenditure amount in 2001 increased from 2000 as Old Plains took advantage of higher prices and increased its spending level to advance some of the more technically challenging projects that existed within Old Plains’ property base at the time.

Net cash used in financing activities in the first six months 2003 was $273.9 million primarily reflecting a $197.2 million increase in amounts outstanding under our revolving credit facility, $80.1 million in proceeds from the issuance of 8.75% notes, the collection of a $0.5 million contribution receivable from Plains Resources and $4.1 million of debt issuance costs. Net cash used in financing activities in 2002 was $13.7 million. Cash receipts in 2002 included proceeds received from the

60

issuance of the initial 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 Old Plains credit facility ($35.8 million). Cash outflows in 2002 included cash distributions to Plains Resources ($312.0 million); payments for debt issuance costs ($5.9 million); and principal payments on long-term debt ($0.5 million). Cash provided by financing activities in 2001 of $8.5 million included cash advances from Plains Resources ($9.0 million) less principal payments on long-term debt ($0.5 million). Cash used in financing activities in 2000 of $13.1 million included repayments of cash advances from Plains Resources ($12.6 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 and exploration of oil and gas. During 2003, we expect to make aggregate capital expenditures of approximately $112-$119 million including expenditures on the 3TEC properties from June 1, 2003 through December 31, 2003. We intend to continue to pursue the acquisition of underdeveloped producing properties.

We will incur cash expenditures upon the exercise of stock appreciation rights, or SARs, but our outstanding share count will not increase. At June 30, 2003 we had approximately 3.7 million SARs outstanding of which 1.5 million were vested. If all of the vested SARs were exercised, based on $10.81, the price of our common stock as of June 30, 2003, we would pay $3.5 million to holders of the SARs. See “Critical Accounting Policies and Factors that May Affect Future Results—Stock Appreciation Rights.”

Commitments and Contingencies

Contractual obligations.    At June 30, 2003, the aggregate amounts of contractually obligated payment commitments are as follows (in thousands):

	2003		2004		2005		2006		2007		Thereafter
Long-term debt	$	511	$	511	$	—	$	233,000	$	—	$	275,000
Producing property remediation		1,240		1,225		1,100		700		600		2,150
Operating leases		1,662		2,696		2,090		1,473		1,331		1,698
	$	3,413	$	4,432	$	3,190	$	235,173	$	1,931	$	278,848

In July, we entered into a new lease agreement that will increase our operating lease obligations by $0.3 million in 2003, $0.9 million in each of 2004 through 2007 and $10.7 million thereafter.

The long-term debt amounts consist principally of amounts due under our credit facility and our 8.75% notes. The obligation for producing property remediation consists of obligations associated with the purchase of certain of our onshore California properties.

Corporate reorganization and spin-off.    In connection with Old Plains’ corporate reorganization and spin-off, it entered into certain agreements with Plains Resources including a master separation agreement, an intellectual property agreement, the Plains Exploration & Production transition services agreement, the Plains Resources transition services agreement and a technical services agreement. For the six months ended June 30, 2003 we billed Plains Resources $0.3 million for services we provided under these agreements and Plains Resources billed us $0.1 million for services they provided to us under these agreements.

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,

61

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

Plugging, abandonment and remediation obligations.    Consistent with normal industry practices, substantially all of our oil and gas leases require that, upon termination of economic production, the working interest owners plug and abandon non-producing wellbores, remove tanks, production equipment and flow lines and restore the wellsite. Typically, when producing oil and gas assets are purchased the purchaser assumes the obligation to plug and abandon wells that are part of such assets. However, in some instances, we received an indemnity with respect to those costs.

We estimate that at December 31, 2002 the costs to perform these tasks (including our commitments related to the purchase of certain of our onshore California properties) will be approximately $0.8 million, net of salvage and other considerations including the fair value of fee lands on which we conduct certain of our production operations ($104.9 million before salvage value and other considerations). Effective January 1, 2003, upon adoption of SFAS No. 143 “Accounting for Asset Retirement Obligations,” we recorded the fair value of liabilities associated with our asset retirement obligations. See “—Recent Accounting Pronouncements.”

We estimate our 2003 cash expenditures related to plugging, abandonment and remediation will be approximately $2.3 million (including the costs required to be expended in connection with the purchase of certain of our onshore California properties). Due to the long life of our onshore 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.

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. 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.

In the ordinary course of business, we are a claimant and/or defendant in various other legal proceedings. In particular, we are required to indemnify Plains Resources for any liabilities it incurs in connection with a lawsuit it (through a predecessor interest in Stocker Resources, Inc.) has regarding an electric services contract with Commonwealth Energy Corporation. In this lawsuit, Plains Resources is seeking a declaratory judgment that it was entitled to terminate the contract and that Commonwealth has no basis for proceeding against a related $1.5 million performance bond. In a counter suit against Plains Resources, Commonwealth is seeking unspecified damages. The two cases have been consolidated and set for trial in December 2003. We understand that Plains Resources intends to defend its rights vigorously in this matter. 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.

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,

62

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. The occurrence of a significant event that is not fully insured against could have a material adverse effect on our financial position. Our insurance does not cover every potential risk associated with operating our pipelines, including the potential loss of significant revenues. Consistent with insurance coverage generally available to the industry, our insurance policies provide limited coverage for losses or liabilities relating to pollution, with broader coverage for sudden and accidental occurrences.

Industry Concentration

Financial instruments which potentially subject us to concentrations of credit risk consist principally of accounts receivable with respect to our oil and gas operations and derivative instruments related to our hedging activities. PAA is the exclusive marketer/purchaser for all of our equity oil production in California and Illinois. This concentration has the potential to impact our overall exposure to credit risk, either positively or negatively, in that PAA may be affected by changes in economic, industry or other conditions. We do not believe the loss of PAA as the exclusive purchaser of our equity production would have a material adverse affect on our results of operations. We believe PAA could be replaced by other purchasers under contracts with similar terms and conditions. The contract counterparties for our derivative commodity contracts are all major financial institutions with Standard & Poor’s ratings of A or better. Three of the financial institutions that are participating lenders in our revolving credit facility hold contracts that represent approximately 43% of the fair value of all open positions as of June 30, 2003. No one counterparty holds contracts that represent more than 19% of the fair value of all open positions as of June 30, 2003.

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

Critical Accounting Policies and Factors that May Affect Future Results

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

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

Periodically, we enter into hedging arrangements relating to a portion of our oil and gas 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

63

limited when commodity prices increase. For a further discussion concerning our risks related to oil and gas prices and our hedging programs, see “—Quantitative and Qualitative Disclosures about Market Risks.”

Write-downs under full cost ceiling test rules.    Under the SEC’s full cost accounting rules, we review the carrying value of our proved oil and gas properties each quarter. Under these rules, capitalized costs of proved oil and gas properties (net of accumulated depreciation, depletion and amortization, and deferred income taxes) may not exceed a “ceiling” equal to:

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

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

These rules generally require that we price our future oil and gas production at the oil and gas prices in effect at the end of each fiscal quarter and require a write-down if our capitalized costs exceed this “ceiling,” even if prices declined for only a short period of time. We have had no write-downs due to these ceiling test limitations since 1998. Given the volatility of oil and gas prices, it is likely that our estimate of discounted future net revenues from proved oil and gas reserves will change in the near term. If oil and gas prices decline significantly in the future, even if only for a short period of 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 or the standardized measure 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 proved reserve base (approximately 81% at December 31, 2002, on a pro forma basis for the 3TEC merger) is comprised of oil properties that are sensitive to oil price volatility. Historically, we have experienced significant upward and downward revisions to our proved reserve 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 proved 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.    At the time of the spin-off, pursuant to Old Plains’ employee matters agreement with Plains Resources, all outstanding options to acquire Plains Resources common stock at the time of the spin-off were “split” into (1) an equal number of options to acquire Plains Resources common stock and (2) an equal number of SARs, with respect to Old Plains’

64

common stock. The exercise price of the original Plains Resources stock options was also “split” between the new Plains Resources stock options and the SARs based on the following relative amounts: the closing price (with dividend) of Plains Resources common stock on the spin-off date ($23.05 per share) less the closing price (on a “when-issued” basis) of Old Plains’ common stock on the spin-off date ($9.10 per share), both as reported on the NYSE, and such closing price of Old Plains’ common stock.

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

We recognized compensation expense of $2.7 million, representing the difference in its common stock price on December 18, 2002, the date of the spin-off, and the exercise price of each SAR deemed vested on that date. In addition, we recognized compensation expense of $1.0 million, representing the increase in its stock price and the vesting deemed to have occurred from the spin-off date to December 31, 2002. For the six months ended June 30, 2003 we recognized $2.7 million of expense due to the increase in our stock price from $9.75 on December 31, 2002 to $10.81 on June 30, 2003.

At June 30, 2003 we had approximately 3.7 million SARs outstanding of which 1.5 million were vested. If all of the vested SARs were exercised, based on $10.81, the closing price of our common stock as of June 30, 2003, we would pay $3.5 million to holders of the SARs.

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. In our acquisition of 3TEC, goodwill totaled $144.0 million and represents 13% of our total assets at June 30, 2003.

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

Recent Accounting Pronouncements

The Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 149 “Amendment of Statement 133 on Derivative Instruments and Hedging Activities”, or SFAS 149 on April 30, 2003. SFAS 149 amends and clarifies accounting for derivative instruments, including

65

certain derivative instruments embedded in other contracts, and for hedging activities under SFAS No. 133. The statement is effective for contracts entered into or modified after June 30, 2003 and for hedging relationships designated after June 30, 2003. The adoption of SFAS No. 149 will have no effect on either our financial position or results of operations.

In May 2003, the FASB issued Statement No. 150 “Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity.” (SFAS 150). SFAS 150 establishes standards for how an issuer classified and measures certain financial instruments with characteristics of both liabilities and equity. SFAS 150 is effective for financial instruments entered into or modified after May 31, 2003, and otherwise is effective at the beginning of the first interim period beginning after June 15, 2003. The adoption of SFAS 150 will not have an impact on our financial statements.

Qualitative and Quantitative Disclosures About Market Risks

We have entered into various derivative instruments to reduce our exposure to fluctuations in the market price of oil and gas. The derivative instruments consist primarily of swap and option contracts entered into with financial institutions.

Derivative instruments are accounted for in accordance with SFAS No. 133 “Accounting for Derivative Instruments and Hedging Activities” as amended by SFAS 137, SFAS 138 and SFAS 149 (“SFAS 133”). Under SFAS 133, all derivative instruments are recorded on the balance sheet at fair value. If the derivative does not qualify as a hedge or is not designated as a hedge, the gain or loss on the derivative is recognized currently in earnings. If the derivative qualifies for hedge accounting, the unrealized gain or loss on the derivative is deferred in accumulated Other Comprehensive Income (“OCI”), a component of Stockholders’ Equity. At June 30, 2003 all open positions qualified for hedge accounting.

Gains and losses on hedging instruments related to OCI and adjustments to carrying amounts on hedged volumes are included in oil and gas revenues in the period that the related volumes are delivered. Gains and losses on hedging instruments representing hedge ineffectiveness, which is measured on a quarterly basis, are included in oil and gas revenues in the period in which they occur. No ineffectiveness was recognized in 2003, 2002 or 2001.

At June 30, 2003, OCI consisted of $47.5 million ($28.1 million net of tax) of unrealized losses on our oil and gas hedging instruments, $0.3 million ($0.2 million, net of tax) loss related to our interest rate swap and $0.1 million ($0.1 million, net of tax) related to pension liabilities. The assets and liabilities related to our open hedging instruments were included in current assets ($1.7 million), other assets ($0.7 million), current liabilities ($39.5 million), other long-term liabilities ($10.4 million) and deferred income taxes (a tax benefit of $19.4 million).

During the first six months of 2003, $27.7 million ($16.4 million net of tax) in losses from the settlement of oil and gas hedging instruments were reclassified from OCI and charged to income as a reduction of oil and gas revenues. As of June 30, 2003, $37.9 million ($22.5 million, net of tax) of deferred net losses on commodity hedging instruments recorded in OCI are expected to be reclassified to earnings during the next twelve-month period.

At December 31, 2001, OCI consisted of $26.6 million ($15.9 million, net of tax) of unrealized gains on Old Plains’ open oil hedging instruments. As oil prices increased significantly during 2002, the fair value of our open oil hedging positions decreased $62.3 million ($37.3 million, net of tax). At December 31, 2002, OCI consisted of $20.9 million ($12.6 million net of tax) of unrealized losses on our crude oil 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) related to pension liabilities. At December 31, 2002, the

66

assets and liabilities related to our open oil hedging instruments were included in current assets ($2.6 million), other assets ($1.4 million), current liabilities ($24.4 million), other long-term liabilities ($0.6 million) and deferred income taxes (a tax benefit of $8.4 million).

During 2002, $14.7 million ($8.9 million net of tax) in losses from the settlement of oil hedging instruments were reclassified from OCI and charged to income as a reduction of oil revenues. Oil revenues for the period have also been reduced by a $0.9 million non-cash expense related to the amortization of option premiums.

Commodity price risk.    As of July 31, 2003, we had the following open oil and gas hedge positions:

	2003	2004	2005
Oil Swaps (Bbls/day)
Average price $24.10 per Bbl	20,250	—	—
Average price $23.89 per Bbl	—	18,500	—
Average price $23.85 per Bbl	—	—	7,500
Gas Swaps (MMBtu/day)
Average price $5.02 per MMBtu	50,000	—	—
Average price $4.45 per MMBtu	—	20,000	—
Gas Costless Collars (MMBtu/day)	—	20,000	—
Floor price of $4.00 per MMBtu
Cap price of $5.15 per MMBtu

Assuming the combined company’s pro forma 2002 annual production volumes were held constant (39.6 MBOE per day) in subsequent periods, these positions result in us hedging approximately 72%, 64% and 19% of our production in 2003, 2004 and 2005, respectively. Location and quality differentials attributable to our properties are not included in the foregoing prices. Because of the quality and location of our production, these adjustments will reduce our net realized price.

The agreements provide for monthly cash settlements based on the differential between the agreement price and the actual NYMEX price. Gains or losses are recognized in the month of related production and are included in oil and gas revenues. These contracts resulted in an increase (decrease) in revenues of $(27.7) million and $(0.5) million for the first six months of 2003 and 2002, respectively, and $(15.6) million, $0.3 million and $(72.8) million for the years ended December 31, 2002, 2001 and 2000, respectively.

Our average realized price for oil and gas is sensitive to changes in location and qualify differential adjustments as set forth in its oil and gas sales contracts. At June 30, 2003 we had basis risk swap contracts on our Illinois Basin oil production through December 31, 2003. The swaps fix the location differential portion of 2,600 barrels per day at $0.39 per barrel for the third quarter of 2003, and 2,500 barrels per day at $0.31 per barrel for the fourth quarter of 2003.

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

	June 30, 2003					December 31, 2002
	Fair Value			Effect of 10% Price Decrease		Fair Value			Effect of 10% Price Decrease
Swaps and options contracts	$	(47.6	)	$	44.0	$	(20.9	)	$	29.3

67

The fair value of the swaps and option contracts are estimated based on quoted prices from independent reporting services compared to the contract price of the swap, and approximate the gain or loss that would have been realized if the contracts had been closed out at 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% decrease in price regardless of term or historical relationships between the contractual price of the instruments and the underlying commodity price. In the event of an actual 10% change in prompt month 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. Three of the financial institutions that are participating lenders in our revolving credit facility hold contracts that represent approximately 43% of the fair value of all open positions as of June 30, 2003. No one counterparty holds contracts that represent more than 19% of the fair value of all open positions as of June 30, 2003.

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

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

68

BUSINESS

General

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

• California;

• Gulf Coast; and

• East Texas.

Our strategy is to continue to grow our cash flow from operations and to use this cash flow to increase our proved developed reserves and production, acquire additional underdeveloped oil and gas properties, make other strategic acquisitions and prudently allocate capital to exploratory projects. We focus on implementing improved production practices and recovery techniques, and relatively low-risk development drilling. We believe we can continue our strong reserve and production growth through the exploitation and development of our existing inventory of projects relating to our properties. We also intend to be opportunistic in pursuing selective acquisitions of oil or gas properties or exploration projects. We will consider opportunities located in our current core areas of operation as well as projects in other areas in North America that meet our investment criteria.

Corporate Reorganization and Spin-off

Prior to December 18, 2002 Old Plains was a wholly owned subsidiary of Plains Resources. On December 18, 2002 Plains Resources distributed 100% of the issued and outstanding shares of Old Plains’ 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 Old Plains common stock for each share of Plains Resources common stock held. Prior to the spin-off, Plains Resources made an aggregate of $52.2 million in cash contributions to Old Plains and transferred to Old Plains certain assets and Old Plains assumed certain liabilities of Plains Resources, primarily related to land, unproved oil and gas properties, office equipment and pension obligations. Old Plains used the cash contributions to reduce outstanding debt under its revolving credit facility.

In contemplation of the spin-off, under the terms of a Master Separation Agreement between Old Plains and Plains Resources, on July 3, 2002 Plains Resources contributed to Old Plains 100% of the capital stock of its wholly owned subsidiaries that own oil and gas properties in offshore California and Illinois. As a result, we indirectly own our offshore California and Illinois properties and directly own our onshore California properties. Plains Resources also contributed to Old Plains $256.0 million of intercompany payables that it or its subsidiaries owed to it. On July 3, 2002 Old Plains issued the initial notes and entered into a $300.0 million revolving credit facility. Old Plains distributed the net proceeds of $195.3 million from the initial notes and $116.7 million of initial borrowings under Old Plains’ credit facility to Plains Resources.

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

Merger with 3TEC

On June 4, 2003 Old Plains acquired 3TEC for approximately $312.9 million in cash and common stock plus $90.1 million to retire outstanding debt. Prior to the merger, 3TEC redeemed all outstanding

69

shares of its Series D preferred stock for $14.7 million. We funded the cash portion of the merger through borrowings under a new credit facility and the proceeds of the Series A notes offering. After the merger, 3TEC common stockholders owned approximately 40% of the combined company and Old Plains’ stockholders owned approximately 60% of the combined company.

Oil and Gas Operations

We own a 100% working interest in and operate all of our onshore California and Illinois Basin properties. On a pro forma basis for the 3TEC merger, the combined company operated approximately 83% of its 2002 production. As a result, we benefit from economies of scale and control the level, timing and allocation of a significant amount of our capital expenditures and expenses. Our onshore California reserves are generally mature but underdeveloped, have produced significant volumes since initial discovery and have significant estimated remaining reserves while our East Texas and Gulf Coast properties generally have higher initial production rates.

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

We actively manage our exposure to commodity price fluctuations by hedging significant portions of our production through the use of swaps, collars and purchased puts and calls. The level of our hedging activity depends on our view of market conditions, available hedge prices and our operating strategy. Under our hedging program, we typically hedge approximately 70-75% of our production for the current year, 40-50% of our production for the next year and up to 25% of our production for the following year. For example, on a pro forma basis for the merger, and assuming a constant production level of 39.6 MBOE per day, as of July 31, 2003 the combined company’s hedge positions would have resulted in its having hedged approximately 72% of production for 2003, approximately 64% of production for 2004 and approximately 19% for 2005.

We had estimated pro forma total proved reserves of 302.4 MMBOE as of December 31, 2002, of which 81% was comprised of oil and 58% was proved developed. We have pro forma a reserve life of over 20 years and a proved developed reserve life of over 12 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, 2002 and based on year-end 2002 spot market prices of $31.20 per Bbl of oil and $4.79 per MMBtu of gas, our pro forma reserves had a PV-10 of $2.0 billion and a standardized measure of $1.2 billion.

The following table sets forth information with respect to the combined company’s pro forma oil and gas properties as of and for the year ended December 31, 2002 (dollars in millions):

	California			Gulf Coast			East Texas			Other			Total
	(Dollars in millions)
Proved reserves
MMBOE		227.4			6.3			29.5			39.2			302.4
Percent oil		94	%		24	%		5	%		74	%		81	%
Proved Developed Reserves—MMBOE		120.4			5.4			22.4			27.9			176.1
2002 Production—MMBOE		8.4			1.5			2.4			2.1			14.4
PV-10(1)	$	1,408.5		$	119.2		$	270.7		$	204.6		$	2,003.0
Standardized measure(2)													$	1,232.9

(1) Based on year-end 2002 spot market prices of $31.20 per Bbl of oil and $4.79 per MMBtu of gas. 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.

70

Oil and Gas Reserves

The following table sets forth certain information with respect to Old Plains’ reserves based upon reserve reports prepared by the independent petroleum consulting firms of Netherland, Sewell & Associates, Inc. and Ryder Scott Company in 2002 and 2001, and H.J. Gruy and Associates, Inc., Netherland, Sewell & Associates, Inc. and Ryder Scott Company in 2000. 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.

	Year Ended December 31,
	2002			2001			2000
	(Dollars in thousands, except per unit amounts)
Oil and Gas Reserves
Oil (MBbls)
Proved developed		127,415			119,248			105,679
Proved undeveloped		112,746			104,045			98,708
Total		240,161			223,293			204,387
Gas (MMcf)
Proved developed		53,317			59,101			52,184
Proved undeveloped		23,837			37,116			41,302
Total		77,154			96,217			93,486
MBOE		253,020			239,329			219,968
PV-10(1):
Proved developed	$	916,373		$	454,095		$	982,752
Proved undeveloped		598,671			189,125			321,430
	$	1,515,044		$	643,220		$	1,304,182
Standardized Measure	$	883,507		$	384,467		$	789,438
Average year-end realized prices(2)
Oil (per Bbl)	$	26.91		$	15.31		$	21.93
Gas (per Mcf)	$	4.63		$	2.56		$	14.63
Year-end spot market prices
Oil (per Bbl)	$	31.20		$	19.84		$	26.80
Gas (per MMBtu)	$	4.79		$	2.58		$	13.70
Reserve replacement ratio		261	%		321	%		218	%
Reserve life (years)		27.1			27.3			27.0
Reserve replacement cost per BOE	$	2.64		$	4.47		$	3.97

(1) PV-10 represents the standardized measure before deducting estimated future income taxes. Old Plains’ year-end 2002 PV-10 and standardized measure include future development costs related to proved undeveloped reserves of $43.7 million in 2003, $55.6 million in 2004 and $46.6 million in 2005.

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

During the three-year period ended December 31, 2002 Old Plains drilled 407 development wells, 403 of which were successful. During this period, Old Plains incurred aggregate oil and gas acquisition, exploitation, development and exploration costs of $260.8 million, resulting in proved reserve additions of 70.3 MMBOE, at an average reserve replacement cost of $3.71 per BOE, which we believe to be among the lowest of Old Plains’ peer group. During that three-year period approximately 99% of Old Plains’ oil and gas capital expenditures were for acquisition, exploitation and development activities.

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

71

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

Exploitation and Development

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

• enhancing product price realizations;

• optimizing production practices;

• realigning and expanding injection processes;

• drilling wells; and

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

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

By implementing our exploitation plan, we seek to increase cash flows and enhance the value of our asset base. In doing so, we add to and enhance our proved reserves. During the three-year period ended December 31, 2002 Old Plains’ additions to proved reserves, excluding reserves added as a result of Old Plains’ acquisition activities, totaled 67.7 MMBOE or approximately 257% of cumulative net production for this period. Old Plains added these reserves at an aggregate average cost of $3.86 per BOE.

Description of Properties

Onshore California

LA Basin.    In 1992 Old Plains acquired from ChevronTexaco substantially all of its producing oil properties in the LA Basin. These interests included the Inglewood, East Beverly Hills, San Vicente and South Salt Lake fields. Following the initial acquisition Old Plains expanded its holdings in this area by acquiring additional interests within the existing fields, including all of ChevronTexaco’s interest in its

72

Vickers lease, which further consolidated its holdings in the Inglewood field. We refer to all of our properties in the LA Basin acquired before 1997 collectively as the “LA Basin properties.” We hold a 100% working interest in the LA Basin properties.

The LA Basin properties consist of oil reserves discovered at various times between 1924 and 1966. We have performed various exploitation activities, including drilling additional production and injection wells, returning previously marginal wells to economic production, optimizing pre-existing waterflood operations, initiating new waterfloods, optimizing artificial lift, increasing the capacity and efficiency of facilities, upgrading facilities to maintain regulatory compliance, reducing unit production expenses and improving marketing margins. Additionally, we continuously update and perform technical studies to identify new investment opportunities on these properties. Through these acquisition and exploitation activities, Old Plains’ net average daily production from this area has increased from approximately 6.7 MBOE per day in 1992 to 12.2 MBOE per day in 2002.

In 2002 Old Plains spent $32.3 million on capital projects, including drilling 20 production wells and four injection wells, performing numerous recompletions and workovers, and modifying various production and injection facilities. In 2003 we expect to drill 25 to 30 wells, perform workovers, stimulations and conversions, perform various technical studies including reservoir simulation, tracer surveys and reserve modeling and upgrade facilities to increase capacities and efficiencies.

We are also applying 3-D seismic technology to further evaluate the unproved reserves in our LA Basin properties, in particular at the Inglewood field. We shot a 3-D survey in 2003. Interpretation of the data should occur in 2003 and any drilling based on the results may take place in late 2003 and in 2004 and beyond. This will be the first application of 3-D seismic technology in an onshore LA Basin Field. Also in the Inglewood field, we have initiated a 20-well evaluation program using cased hole resistivity logging technology. This technology potentially identifies commercially producible sands behind casing in older wells. Furthermore, we expect these analyses to provide us with a more complete understanding of the field thereby potentially allowing us to improve the waterflood program.

Montebello.    In March 1997 Old Plains expanded its operations in the LA Basin by acquiring ChevronTexaco’s interest in the Montebello field, which included a 100% working interest (99.2% net revenue interest) in 55 producing oil wells and related facilities and approximately 480 acres of surface fee land. Old Plains’ net average daily production from this field has increased from 0.9 MBOE per day at the time of acquisition to 2.6 MBOE per day in 2002. Since the acquisition, Old Plains has drilled a total of 65 producing wells and 25 injection wells. In 2002 Old Plains spent $10.8 million on capital projects, which included drilling 18 production wells and 3 injection wells, performing numerous workovers, acquiring seismic and other technical data and increasing the capacity of the production and injection facilities. In 2003 we expect to perform several technical studies that may lead to additional drilling or other development opportunities that would likely be initiated beginning in 2004.

Arroyo Grande.    In November 1997 Old Plains acquired a 100% working interest (94% net revenue interest) in the Arroyo Grande field located in San Luis Obispo County, California, from subsidiaries of Shell Oil Company. Old Plains also acquired surface and related development rights to approximately 1,000 acres included in the 1,500-acre producing unit. The field is primarily under continuous steam injection and, at Old Plains’ acquisition date, was producing approximately 1.6 MBOE per day (approximately 1.5 MBOE net to our interest) of 14 degree API gravity oil from 70 wells. Since acquiring this property, Old Plains has drilled additional wells to downsize the injection patterns in the currently developed area from five acres to one and a quarter acres to accelerate recoveries, and realigned steam injection within these areas to increase the efficiency of the recovery process. Old Plains also curtailed steam injection by about 50% immediately following the acquisition due to low oil prices. Although oil prices subsequently rebounded, Old Plains maintained injection at this low rate

73

pending its analysis of the saturation inputs provided by the infill drilling program, and in 2001 due to excessive gas fuel costs. As a result, base volumes declined considerably, but this decline was offset by the wells Old Plains drilled to downsize the injection patterns.

In 2001 Old Plains spent $10.6 million on capital projects in the Arroyo Grande field, the most significant of which was drilling 19 production and 11 injection wells and installing a gas processing facility to reduce third-party fuel gas purchases. During 2002 Old Plains reduced capital expenditures to $1.5 million to allow time to assess the results of the 2001 drilling program and prepare to expand our steam flood in 2003-2004. We are also reviewing a plan to optimize steam handling and produced water disposal. In 2003 we expect to drill 15 to 20 wells and install a small cogeneration facility to reduce electricity costs and provide additional steam. Old Plains’ net average daily production from this field was 1.9 MBOE per day during 2002.

Mt. Poso.    In 1998 Old Plains acquired the Mt. Poso field from Aera Energy LLC. The Mt. Poso field is located near Bakersfield, California, in Kern County. Since acquisition, Old Plains has undertaken an aggressive recompletion and drilling program targeting the Pyramid Hills formation, completing a 107-well drilling program in 2000-2001. During 2002 Old Plains reduced capital expenditures to focus on optimizing operating costs, including the installation of electrical generation facilities, and reviewing past drilling results to identify future drilling potential. In 2002 Old Plains spent $0.8 million on capital projects to optimize our producing infrastructure. In 2003 we expect to drill 75 to 100 new wells. Old Plains’ net average daily production from this field was 1.5 MBOE during 2002.

Offshore California

Point Arguello.    In 1999 and 2002 Old Plains acquired separate 26.3% working interests in the Point Arguello unit and the various partnerships owning the related transportation, processing and marketing infrastructure. We are the operator for the Point Arguello unit which consists of three offshore platforms. The sellers of those interests retained responsibility for certain abandonment costs, including: (1) removing, dismantling and disposing of the existing offshore platforms; (2) removing and disposing of all existing pipelines; and (3) removing, dismantling, disposing and remediating all existing onshore facilities. Old Plains assumed the sellers’ 52.6% share of all other abandonment costs.

In 2002 Old Plains spent $6.2 million on capital projects, which included drilling 4 development wells, one of which was a dry hole, converting wells to electric submersible lift systems, and various workovers and stimulations. In 2003 we expect to drill one to two new wells and continue with our successful workover and high volume lift programs. At the time Old Plains acquired its interest in Point Arguello, its net average daily production from this unit was 5.2 MBOE. During 2002, including the effect of the interest acquired effective August 1, 2002, Old Plains’ net average daily production was 4.9 MBOE.

P-0451 E/2 Development.    We have applied for appropriate permits or modification of existing permits to federal, state, and local agencies to allow drilling into the East half of offshore lease P-0451. The West half of lease P-0451 is developed as part of the Point Arguello Unit. During 1983-1984 five exploratory wells were drilled into E/2 of P-0451 or the adjacent lease P-0452 that tested at rates of 3500, 1629, 1100, 604, and 120 barrels of oil per day, respectively, from an oil accumulation considered separate from the Point Arguello Field. Based on geologic and geophysical interpretations, we believe approximately 60 percent of that accumulation underlies P-0451 E/2. We are the operator of P-0451 and have agreements in place between the P-0451 owners and the Point Arguello Unit owners that will allow us to participate with at least a 52.6% working interest in any development of the P-0451 E/2 lease. Such development would occur by means of extended reach wells drilled from two of the three Point Arguello Unit platforms. In addition to regulatory permit approvals, extended reach

74

drilling would require acquisition or contracting of a suitable drilling rig. There can be no assurance that any such drilling can or will occur or that we will recover economic quantities of oil and gas from E/2 of P-0451.

East Texas

In connection with the 3TEC merger, we acquired all of 3TEC’s properties located in East Texas. The interests included Rosewood, White Oak/Glenwood, Beckville, Carthage, East Henderson and Oak Hill fields with the White Oak/Glenwood and Beckville being the fields with the most identified potential. The predominant producing formation is the Cotton Valley Sand gas reservoir with indicated additional pay in the shallower Travis Peak and Pettit formations. There are many proven undeveloped Cotton Valley drilling locations due to a change in regulatory field rules that now permit wells to be drilled on 80 acre spacing as opposed to 160 acre spacing. At December 31, 2002, 3TEC had identified 128 proved undeveloped locations in this area. During the first seven months of 2003, we and 3TEC drilled 8 development wells and participated in 24 additional wells drilled by other operators. All wells encountered productive intervals and have productive lives in excess of 20 years from the Cotton Valley reservoir. We intend to participate in an additional 9 to 12 Cotton Valley wells by the end of 2003.

White Oak/Glenwood Fields.    Wagner & Brown is the predominant operator in the White Oak/Glenwood fields and we have an interest in almost all wells drilled by Wagner & Brown. In June 2003 Wagner & Brown operated 247 producing wells in the field. Our working interest varies from well to well and ranges from 5% to 39%. Of the 24 wells drilled by outside operators during the first seven months of 2003, Wagner & Brown drilled 20 wells and plans to spud an additional 9 to 12 wells during the remainder of the year.

Beckville Field.    We are the operator of the Beckville field with a working interest that varies from well to well and ranges from 48% to 100%. In June 2003 we operated 35 producing wells. During the first seven months of 2003 we and 3TEC drilled 6 wells and plan to drill one additional well during the remainder of the year.

Gulf Coast

In connection with the 3TEC merger we acquired a substantial base of proved reserves and undeveloped acreage with significant exploration potential along the Gulf Coast of Louisiana.

State Waters.    We have multiple drilling projects in Breton Sound, Main Pass and Chandeleur Sound. During 2002, 3TEC participated in five exploratory wells in Louisiana State Waters, of which four were gas discoveries. In 2003, through August 7, an additional six exploratory wells have been drilled in the Breton/Chandeleur Sound areas. All six are apparent successes. We are continuing our work in the area to drill additional identified prospects and identify new prospects based on additional or reprocessed existing 3-D seismic data.

South Louisiana.    We have multiple drilling projects in several areas of South Louisiana. The area of greatest impact is in St. Mary Parish near the Garden City Field. During 2002, 3TEC operated a successful exploratory well, the Bailey Minerals #1. In 2003 the Bailey #1 was successfully re-completed to an up hole interval after depletion of the original completion. In 2003, we plan to drill an additional Garden City test well and have completed acquisition of 102 square miles of a new 3-D seismic data in an area overlapping and adjacent to the Bailey wells. Several older fields near the new 3-D data have produced large amounts of oil and gas. Other significant fields in South Louisiana include East Roanoke, Bay de Chene and Queen Bess Isle.

75

Other

Old Plains’ 2002 capital expenditures include $8.4 million of capitalized interest and general and administrative costs allocable directly to acquisition, exploitation and development activities and $2.6 million attributable to other projects.

Exploitation, Development, Exploration and Acquisition Expenditures

The following table summarizes the costs incurred during the last three years for Old Plains’ exploitation and development, exploration and acquisition activities (in thousands)(1):

	Year Ended December 31,
	2002			2001		2000
Property acquisitions costs:
Unproved properties	$	65		$	44	$	73
Proved properties(2)		(4,516	)		1,645		1,953
Exploration costs		602			286		293
Exploitation and development costs(3)		68,346			123,778		68,186
	$	64,497		$	125,753	$	70,505

(1) Includes capitalized general and administrative expense of $6.0 million, $6.2 million and $5.2 million in 2002, 2001 and 2000, respectively, and capitalized interest expense of $2.4 million, $3.1 million and $3.8 million in 2002, 2001 and 2000, respectively.

(2) In connection with the acquisition of an additional interest in the Point Arguello field, offshore California, Old Plains assumed certain obligations of the seller. As consideration for receiving the transferred properties and assuming such obligations, Old Plains received $2.4 million. In addition, Old Plains 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).

(3) Exploitation and development costs include expenditures of $27.3 million in 2002, $58.5 million in 2001 and $20.6 million in 2000 related to the development of proved undeveloped reserves included in our proved oil and gas reserves at the beginning of each year.

76

Production and Sales

The following table presents information with respect to oil and gas production attributable to our properties, the revenues we derived from the sale of this production, average sales prices we received and our average production expenses during the six months ended June 30, 2003 and 2002 and the years ended December 31, 2002, 2001 and 2000.

	Six Months Ended June 30,						Year Ended December 31,
	2003(1)			2002			2002			2001			2000
Sales
Oil (MBbls)		4,468			4,113			8,783			8,219			7,654
Gas (MMcf)		3,474			1,719			3,362			3,355			3,042
MBOE		5,047			4,400			9,343			8,778			8,161
Revenue
Oil	$	94,974		$	81,222		$	178,038		$	174,895		$	126,434
Gas		18,781			4,578			10,299			28,771			16,017
Other		407			13			226			473			—
	$	114,162		$	85,813		$	188,563		$	204,139		$	142,451
Average Prices and Costs
Average Oil Sales Price ($/Bbl)
Average NYMEX	$	31.32		$	24.02		$	26.15		$	26.01		$	30.25
Hedging revenue (expense)		(5.88	)		(0.11	)		(1.77	)		0.03			(9.51	)
Differential		(4.18	)		(4.16	)		(4.11	)		(4.76	)		(4.22	)
Net realized	$	21.26		$	19.75		$	20.27		$	21.28		$	16.52
Average Gas Sales Price ($/Mcf)
Average price before hedge	$	5.83		$	2.66		$	3.06		$	8.58		$	5.26
Hedging revenue (expense)		(0.42	)		—			—			—			—
Net realized price	$	5.41		$	2.66		$	3.06		$	8.58		$	5.26
Average Realized Price per BOE	$	22.54		$	19.50		$	20.16		$	23.20		$	17.46
Average Production Costs per BOE		(9.02	)		(7.97	)		(8.40	)		(7.27	)		(6.89	)
Gross Margin per BOE		13.52			11.53			11.76			15.93			10.57
G&A per BOE
G&A excluding items below		(1.74	)		(1.07	)		(1.16	)		(1.16	)		(0.77	)
Stock appreciation rights		(0.52	)		—			(0.39	)		—			—
Merger related costs		(0.22	)		—			—			—			—
Spin-off costs		—			—			(0.08	)		—			—
Gross Profit per BOE	$	11.04		$	10.46		$	10.13		$	14.77		$	9.80
DD&A per BOE (oil and gas properties)	$	3.36		$	3.04		$	3.17		$	2.70		$	2.25

(1) Reflects the acquisition of 3TEC effective June 1, 2003.

Plains All American Pipeline, L.P., or PAA, is the exclusive purchaser of all of our equity oil production in California and Illinois. See “—Product Markets and Major Customers.”

Product Markets and Major Customers

Our revenues are highly dependent upon the prices of, and demand for, oil and gas. Historically, the markets for oil and gas have been volatile and are likely to continue to be volatile in the future. The prices we receive for our oil and gas production and the levels of our production are subject to wide

77

fluctuations and depend on numerous factors beyond our control, including seasonality, economic conditions, foreign imports, political conditions in other oil-producing and gas-producing countries, the actions of OPEC, and domestic government regulation, legislation and policies. Decreases in oil and gas prices have had, and could have in the future, an adverse effect on the carrying value of our proved reserves and our revenues, profitability and cash flow.

To manage our exposure to commodity price risks, we use various derivative instruments to hedge our exposure to price fluctuations on oil and gas sales. Our hedging arrangements provide us protection on the hedged volumes if prices decline below the prices at which these hedges are set. However, ceiling prices in our hedges may cause us to receive less revenues on the hedged volumes than we would receive in the absence of hedges.

Deregulation of gas prices has increased competition and volatility of gas prices. Prices received for our gas are subject to seasonal variations and other fluctuations.

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.

PAA is currently the exclusive purchaser of all of our equity oil production in California and Illinois. We pay PAA a marketing and administration fee of $0.20 per barrel and reimburse PAA for its reasonable expenses incurred in transporting or exchanging our oil. We have agreed to renegotiate the marketing and administration fee in good faith every three years. Under the marketing agreement, PAA has also agreed to, upon our request and reimbursement for its reasonable expenses, market certain of our gas and gas liquids and negotiate our gas purchase agreements. If we were to lose PAA as the exclusive purchaser of our equity production, we believe PAA could be replaced by other purchasers under contracts with similar terms and conditions. However, PAA’s role as the exclusive purchaser for all of our equity oil production does have the potential to impact our overall exposure to credit risk, either positively or negatively, in that PAA may be affected by changes in economic, industry or other conditions.

We are currently negotiating a new marketing agreement with PAA to, among other things, add a definitive term to the agreement and provide that PAA will use its reasonably best efforts to obtain the best price for our oil production.

Productive Wells and Acreage

As of December 31, 2002 Old Plains had working interests in 2,148 gross (2,132 net) active producing oil wells, and 3TEC had working interests in 885 gross (395 net) productive natural gas wells and 114 gross (52 net) productive oil wells. The following tables set forth information with respect to Old Plains’ and 3TEC’s developed and undeveloped acreage as of December 31, 2002.

Plains

	Developed Acres		Undeveloped Acres(1)
	Gross	Net	Gross	Net
Onshore California	8,889	8,844	9,272	6,289
Offshore California(2)	15,326	8,066	41,720	2,898
Illinois	16,622	14,628	13,625	5,418
Indiana	1,155	854	1,280	575
Kansas	—	—	48,147	37,647
Kentucky	—	—	1,321	521
Total	41,992	32,392	115,365	53,348

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

(2) Excludes 3,264 undeveloped acres (net) that we have the right to acquire under an option agreement.

78

3TEC

	Developed Acreage		Undeveloped Acreage
	Gross	Net	Gross	Net
Texas	128,788	62,782	8,752	5,402
Louisiana	25,036	10,439	17,386	9,528
Oklahoma	22,375	8,864	790	138
Other	84,472	49,514	1,307	776
Total	260,671	131,599	28,235	15,844

Excluded from the 3TEC acreage data are approximately 33,495 net mineral acres owned by 3TEC at December 31, 2002, primarily in La Fourche, St. Mary and Terrebonne parishes of Louisiana, all of which 3TEC believed have potential for oil and natural gas exploration. Additionally, at December 31, 2002 3TEC had lease options covering 28,427 gross acres in the Bayou Carlin area of St. Mary Parish, Louisiana, which begin expiring in April, 2004.

Drilling Activities

Information with regard to Old Plains’ drilling activities during the years ended December 31, 2002, 2001 and 2000 is set forth below:

	Year Ended December 31,
	2002		2001		2000
	Gross	Net	Gross	Net	Gross	Net
Development Wells
Oil	79.0	77.4	168.0	163.4	156.0	154.0
Dry	1.0	0.5	1.0	1.0	2.0	2.0
Total	80.0	77.9	169.0	164.4	158.0	156.0

Real Estate

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

Property	Location	Approximate Acreage (Net to Our Interest)
Inglewood	Los Angeles County, California	25
Montebello	Los Angeles County, California	480
Arroyo Grande	San Luis Obispo County, California	1,047
Mt. Poso	Kern County, California	1,236
Gaviota	Santa Barbara County, California	84

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

Title to Properties

Our properties are subject to customary royalty interests, liens incident to operating agreements, liens for current taxes and other burdens, including other mineral encumbrances and restrictions. We

79

do not believe that any of these burdens materially interfere with our use of the properties in the operation of our business.

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

Competition

Our competitors include major integrated oil and gas companies and numerous independent oil and gas companies, individuals and drilling and income programs. Many of our larger competitors possess and employ financial and personnel resources substantially greater than ours. These competitors are able to pay more for productive oil and gas properties and exploratory prospects and to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. Our ability to acquire additional properties and to discover reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, there is substantial competition for capital available for investment in the oil and gas industry.

Regulation

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

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

MMS.    The 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

80

California, might impose regulations that increase our costs and may terminate or suspend our operations,” and has proposed regulations that would permit it to expel unsafe operators from offshore operations. The MMS has also established rules governing the calculation of royalties and the valuation of oil produced from federal offshore leases and regulations regarding costs for gas transportation. Delays in the approval of plans and issuance of permits by the MMS because of staffing, economic, environmental or other reasons could adversely affect our operations.

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

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

Sale of gas.    The FERC regulates interstate gas pipeline transportation rates and service conditions. Although the FERC does not regulate gas producers such as us, the agency’s actions are 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.

81

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

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

Plugging, Abandonment and Remediation Obligations

Consistent with normal industry practices, substantially all of our oil and gas leases require that, upon termination of economic production, the working interest owners plug and abandon 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 Illinois and we believe that such properties have been operated in accordance with standard oil field practices, certain of the fields have been in operation for 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 the combined company’s 2003 cash expenditures related to plugging, abandonment and remediation will be approximately $2.3 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

82

shorter reserve life, third parties have retained the majority of the obligations for abandoning these properties.

Spin-off Agreements

In connection with Old Plains’ separation from Plains Resources, Old Plains entered into the following agreements:

Master Separation Agreement

Overview.    To effect Old Plains’ separation from Plains Resources, Old Plains entered into a master separation agreement on July 3, 2002 with Plains Resources simultaneous with entering into Old Plains’ financing. The master separation agreement provides for the separation of substantially all of the upstream assets and liabilities of Plains Resources, other than its Florida operations. The master separation agreement provides for, among other things:

• the separation;

• cross-indemnification provisions;

• allocation of fees related to these transactions between Old Plains and Plains Resources;

• other provisions governing Old Plains’ relationship with Plains Resources, including mandatory dispute arbitration, sharing information, confidentiality and other covenants;

• a noncompetition provision; and

• Old Plains entering into the ancillary agreements discussed below with Plains Resources.

Separation.    To effect the separation, on July 3, 2002, Plains Resources transferred to Old Plains assets and liabilities related to Plains Resources’ upstream business other than its Florida operations, including the capital stock of Arguello Inc., Plains Illinois Inc., PMCT, Inc. and Plains Resources International Inc., miscellaneous upstream assets and related hedging agreements. Old Plains assumed the liabilities associated with the transferred assets and businesses. Plains Resources also transferred to Old Plains additional assets and liabilities, including remaining upstream agreements and permits that require consent to transfer and office furniture and equipment, and we will sublease a portion of Plains Resources’ office space. Except as set forth in the master separation agreement, no party made any representation or warranty as to the assets or liabilities transferred as a part of the separation, and all assets were transferred on an “as is, where is” basis.

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

Indemnification.    The master separation agreement provides for cross-indemnities intended to place sole financial responsibility on us for all liabilities associated with the current and historical businesses and operations we conduct after giving effect to the separation, regardless of the time those liabilities arise, and to place sole financial responsibility for liabilities associated with Plains Resources’ other businesses with Plains Resources and its other subsidiaries. The master separation agreement also contains indemnification provisions under which we and Plains Resources each indemnify the other with respect to breaches by the indemnifying party of the master separation agreement or any of the ancillary agreements described below. We will indemnify Plains Resources and its other subsidiaries against liabilities arising from misstatements or omissions in the various offering documents for the exchange offer related to our initial notes or the spin-off including related

83

prospecti or in documents to be filed with the SEC in connection therewith, except for information regarding Plains Resources provided by Plains Resources for inclusion in such documents. Plains Resources agrees to indemnify us against liabilities arising from misstatements or omissions in the various offering documents for the exchange offer related to our initial issuance of 8.75% notes or the spin-off, including related prospecti or in documents to be filed with the SEC in connection therewith if such information was provided by Plains Resources.

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

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

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

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

Employee Matters Agreement

Old Plains entered into an employee matters agreement with Plains Resources. The employee matters agreement does not address the treatment of Messrs. Flores, Raymond and Stephens, whom we call the executives, except with respect to the treatment of their existing options to acquire Plains Resources common stock.

Other employees.    The employee matters agreement provided that those employees who work for Old Plains after the spin-off were transferred to Old Plains immediately before the spin-off. Neither their transfer nor the spin-off was treated as a termination of their employment for purposes of any benefits under any plans.

Stock options and restricted stock awards.    Under the employee matters agreement, as a result of the spin-off, all outstanding options to acquire Plains Resources common stock at the time of the spin-off were “split” into (1) an equal number of options to acquire Plains Resources common stock

84

and (2) an equal number of stock appreciation rights, or SARs, with respect to Old Plains’ common stock.

The exercise price for the original Plains Resources stock options was also “split” between the new Plains Resources stock options and the SARs based on the following relative amounts: 39.5% Old Plains, and 60.5% Plains Resources.

Also, unless otherwise provided for in the agreement governing the restricted stock award, at the time of the spin-off all restricted stock awards for Plains Resources common stock were “split” into (1) restricted stock awards for an equal number of shares of Plains Resources common stock and (2) restricted stock awards for an equal number of shares of Old Plains’ common stock.

Other plans.    Under the employee matters agreement (1) Old Plains established a nonqualified deferred compensation plan for certain executive officers and, to the extent that any of the executives are participants in the Plains Resources deferred compensation plan, the related assets and liabilities under the Plains Resources plan were transferred to Old Plains’ plan, (2) Plains Resources transferred its 401(k) plan and welfare benefit plans to Old Plains and formed a similar 401(k) plan and similar welfare benefit plans, and (3) Old Plains established plans that mirror the fringe benefits and company policies of Plains Resources.

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

Tax Allocation Agreement

On July 3, 2002, Old Plains entered into the tax allocation agreement, which Old Plains and Plains Resources amended and restated on November 20, 2002. This agreement provides that, until the spin-off, Old Plains continued to be included in Plains Resources’ consolidated federal income tax group, and Old Plains’ federal income tax liability was included in the consolidated federal income tax liability of Plains Resources. The amount of taxes that Old Plains pays or receives with respect to consolidated or combined returns of Plains Resources in which Old Plains is included generally are to be determined by multiplying Old Plains’ net taxable income included in the Plains Resources consolidated tax return by the highest marginal tax rate applicable to the income. Plains Resources is not required to pay us for the use of our tax attributes that come into existence before the spin-off until such time as we would otherwise be able to utilize such attributes.

In general, the agreement provides that Old Plains is included in Plains Resources’ consolidated group for federal income tax purposes until the time of the spin-off. Each member of a consolidated group is jointly and severally liable for the federal income tax liability of each other member of the consolidated group. Accordingly, although this agreement allocates tax liabilities between Old Plains and Plains Resources during the period in which Old Plains is included in Plains Resources’ consolidated group, we could be liable if any federal tax liability is incurred, but not discharged, by any other member of Plains Resources’ consolidated group. In addition, to the extent Plains Resources’ net operating losses are used in the consolidated return to offset Old Plains 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 million exclusive of any interest accruing under the agreement. Such liability is reflected in our consolidated financial statements.

Under the terms of this agreement, we will 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.

85

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

We also are liable for transfer taxes associated with the transfer of assets and liabilities in connection with the separation and the spin-off.

Plains Exploration & Production Transition Services Agreement

On July 3, 2002 Old Plains entered into the Plains Exploration & Production transition services agreement, which provided that Plains Resources would provide Old Plains the following services, on an interim basis:

• management services, including managing Old Plains’ operations, evaluating investment opportunities for us, overseeing Old Plains’ upstream activities, and staffing;

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

• accounting services, including maintaining general ledgers, preparing financial statements and working with Old Plains’ auditors;

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

• insurance services, including maintaining for the interim period the existing insurance that Plains Resources provided for Old Plains;

• employee benefits services, including administering and maintaining the employee benefit plans that covered Old Plains’ employees;

• limited services for legal matters; and

• financial services, including helping Old Plains raise capital, preparing budgets and executing hedges.

Through December 31, 2002 Plains Resources charged Old Plains $10.8 million to reimburse it for its costs of providing such services. Plains Resources will continue to provide services under this agreement until June 16, 2004 unless we and Plains Resources decide to terminate the agreement earlier. For the six months ended June 30, 2003, Plains Resources billed us $0.1 million under this agreement.

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

Plains Resources Transition Services Agreement

On July 3, 2002 Old Plains entered into the Plains Resources transition services agreement, under which we will provide Plains Resources the following services on an interim basis beginning on a

86

date to be determined by both us and Plains Resources upon the transfer by Plains Resources of substantially all of its employees to us:

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

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

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

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

• limited services for legal matters; and

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

The services we provide under the Plains Resources transition services agreement and the services Plains Resources provided under the Plains Exploration & Production transition services agreement are substantially similar, except that:

• the Plains Resources transition services agreement does not cover management services, insurance services or operational services;

• the tax services provided under the Plains Resources transition services agreement are not subject to the tax allocation agreement; and

• the legal services provided under the Plains Exploration & Production transition services agreement include legal services that have been historically provided for it and its subsidiaries by Plains Resources.

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

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

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

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

The term of this agreement expires on June 8, 2004 unless we and Plains Resources decide to terminate the agreement earlier. We and Plains Resources may agree to extend the term if necessary or desirable.

87

Technical Services Agreement

On July 3, 2002 Old Plains entered into the technical services agreement, which provides that, beginning on a date to be determined by us and Plains Resources, we will provide Calumet Florida certain engineering and technical support services required to support operation and maintenance of the oil and gas properties owned by Calumet, including geological, geophysical, surveying, drilling and operations services, environmental and other governmental or regulatory compliance related to oil and gas activities and other oil and gas engineering services as requested, and accounting services.

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

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

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

We are not obligated to provide any service to the extent it is impracticable as a result of causes outside of our control.

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

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

Employees

As of June 30, 2003 we had 417 full-time employees, 216 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.

88

MANAGEMENT

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

Name	Age	Title
James C. Flores	43	Chairman of the Board, Chief Executive Officer and a Director
John T. Raymond	33	President and Chief Operating Officer
Stephen A. Thorington	47	Executive Vice President, Chief Financial Officer
John F. Wombwell	41	Executive Vice President and General Counsel
Thomas M. Gladney	50	Executive Vice President—Exploration & Production
Cynthia A. Feeback	45	Senior Vice President—Accounting and Treasurer
Alan R. Buckwalter, III	56	Director
Jerry L. Dees	62	Director
Tom H. Delimitros	62	Director
John H. Lollar	64	Director
Robert L. Zorich	51	Director

The following biographies describe the business experience of our executive officers and directors:

James C. Flores, Chairman of the Board, Chief Executive Officer and a Director since September 2002.    He also has been Plains Resources’ Chairman of the Board since December 2002. He was Chairman of the Board and Chief Executive Officer of Plains Resources from May 2001 to December 2002. He was President and Chief Executive Officer of Ocean Energy, Inc., an oil and gas company, from July 1995 until March 1999, and a director of Ocean Energy, Inc. from 1992 until March 1999. In March 1999 Ocean Energy, Inc. was merged into Seagull Energy Corporation, which was the surviving corporation of the merger, and which was renamed Ocean Energy, Inc. Mr. Flores served as Chairman of the Board of the new Ocean Energy, Inc. from March 1999 until January 2000, and as Vice Chairman from January 2000 until January 2001. From January 2001 to May 2001 Mr. Flores managed various private investments.

John T. Raymond, President and Chief Operating Officer since September 2002.    He also has been Plains Resources’ President and Chief Executive Officer since December 2002. He was Plains Resources’ President and Chief Operating Officer from November 2001 to December 2002. Previously, he was its Executive Vice President and Chief Operating Officer from May 2001 to November 2001. In addition, Mr. Raymond served as Director of Corporate Development of Kinder Morgan, Inc. from January 2000 to May 2001, and as Vice President of Corporate Development of Ocean Energy, Inc. from April 1998 to January 2000. Mr. Raymond also served as Vice President of Howard Weil Labouisse Friedrichs, Inc., an energy investment company, from 1992 to April 1998. In addition, Mr. Raymond is a director of Plains All American GP LLC, which is the general partner of PAA.

Stephen A. Thorington, Executive Vice President and Chief Financial Officer since September 2002.    He also has been Plains Resources’ Executive Vice President and Chief Financial Officer since February 2003. He was Plains Resources’ Acting Executive Vice President and Chief Financial Officer from December 2002 to February 2003. Previously, he was Senior Vice President—Finance and Corporate Development of Ocean Energy, Inc. from July 2001 to September 2002 and

89

Senior Vice President—Finance, Treasury and Corporate Development of Ocean Energy, Inc. from March 1999 to July 2001. He also served as Vice President, Finance and Treasurer of Seagull Energy Corporation from May 1996 to March 1999. Mr. Thorington served as a Managing Director of Chase Securities, Inc. from April 1994 to May 1996.

John F. Wombwell, Executive Vice President and General Counsel since September 2003. He was previously with two New York Stock Exchange traded companies, serving as Vice President, General Counsel and Secretary of ExpressJet Holdings, Inc. from April 2002 until September 2003 and prior to joining ExpressJet, Mr. Wombwell was Executive Vice President, General Counsel and Secretary of Integrated Electrical Services, Inc. from November 1999 to April 2002 and Senior Vice President, General Counsel and Secretary of that company from January 1998 to November 1999. Prior to that time, Mr. Wombwell was a partner at the national law firm of Andrews & Kurth L.L.P. with a practice focused on representing public companies with respect to corporate and securities matters.

Thomas M. Gladney, Executive Vice President—Exploration & Production since June 2003.    He was our Senior Vice President of Operations from September 2002 to June 2003. He also was Plains Resources’ Senior Vice President of Operations from November 2001 to December 2002. He was President of Arguello, Inc., a subsidiary of Plains, from December 1999 to November 2001. From July 1999 to December 1999 he served as a Project Manager for Torch Energy Services, a contract operating services company. From January 1999 to June 1999 he served as a Project Manager for Venoco Inc., an oil and gas company. From September 1998 to January 1999 he was a self-employed engineering services consultant. From 1992 to September 1998 he was Offshore Operations Manager for Oryx Energy Company. Previously, he served as Gulf Coast Reserve Development Manager of Oryx Energy/Sun E&P from 1988 to 1992.

Cynthia A. Feeback, Senior Vice President—Accounting and Treasurer since September 2002.    She also was Plains Resources’ Senior Vice President—Accounting and Treasurer from July 2001 to December 2002. She was its Vice President—Accounting and Assistant Treasurer from May 1999 to July 2001, and its Assistant Treasurer, Controller and Principal Accounting Officer from May 1998 to May 1999. Previously, Ms. Feeback served as its Controller and Principal Accounting Officer from 1993 to 1998, Controller from 1990 to 1993, and Accounting Manager from 1988 to 1990.

Alan R. Buckwalter, III, 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 (SCI), the Texas Medical Center, the Federal Reserve Bank of Dallas, Houston Branch and he is currently serving as Chairman of the Board of Trustees for Texas Southern University Foundation. He sits on the Audit Committees for SCI and St. Luke’s Episcopal Health System.

Jerry L. Dees, 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, 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

90

energy services company. He currently serves as Chairman for two privately-owned companies— ImageLinks, Inc., and InterCorp International Inc.—both of which sell products and services to energy companies. Previously, he has served as President and CEO for Magna Corporation, (now Baker Petrolite, a unit of Baker Hughes). From 1983 to 1988, Mr. Delimitros was a General Partner of Sunwestern Investment Funds and Senior Vice President of Sunwestern Management, Inc.

John H. Lollar, 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. 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.

Robert L. Zorich, Director since May 2003.    He is Managing Director and co-founder of EnCap Investments L.L.C. Prior to the formation of EnCap, Mr. Zorich was a Senior Vice President in charge of the Houston office of Trust Company of the West, a large, privately-held pension fund manager. Prior to joining Trust Company of the West in September 1986, Mr. Zorich co-founded MAZE Exploration, Inc. and served as its Co-Chief Executive Officer, and prior to that was a Vice President and Division Manager in the Energy Department of RepublicBank Dallas. Mr. Zorich currently serves on the Board of Directors of Laredo Energy, L.P., Enerplus Resources Fund, AROC, Inc. and Plantation Energy and is a member of the Independent Petroleum Association of America and the Texas Independent Producers and Royalty Owners Association.

COMMITTEES OF THE BOARD OF DIRECTORS

In addition to establishing Corporate Governance Principles, our board has established an audit committee, an organization and compensation committee and a nominating and corporate governance committee. Our board may establish other committees from time to time to facilitate our management. The composition of the committees will be determined by the board of directors in its sole discretion. During 2002 Old Plains’ board held two meetings. No director attended fewer than 75% of the total number of meetings of the meetings of our board and committees on which he served.

Our audit committee currently consists of Messrs. Buckwalter, Dees, Delimitros and Lollar, with Mr. Delimitros acting as chairman. Our audit committee selects our independent auditors to be engaged by us, reviews the plan, scope and results of our annual audit, and reviews our internal controls and financial management policies with our independent auditors. Our audit committee has adopted a written audit committee charter. During 2003, the board of directors adopted the First Amendment to the Charter of the Audit Committee. All of the members of our audit committee are non-employee directors. Our board of directors, in its business judgment, has determined that all current members of our audit committee are “independent” as defined in Sections 303.01(B)(2)(a) and (3) of the NYSE listing standards and are “financially literate” in compliance with the NYSE listing standards as our board of directors interprets that designation. In addition, our board of directors has determined that Mr. Delimitros is an “audit committee financial expert” as defined in Item 401(h)(2) of Regulation S-K. In addition to the information on Mr. Delimitros set forth in this prospectus, Mr. Delimitros (1) obtained a MBA from Harvard University, (2) as President and CEO of Magna Corporation, directly supervised the chief financial officer of Magna Corporation, (3) is currently the chief financial officer of AMT Venture Funds, (4) serves on the boards of directors and the audit committees thereof of various privately-held companies in which AMT Venture Funds has invested, and (5) as director of corporate planning for General Signal Corporation, analyzed financial reports, supervised the preparation of earnings and cash flows projections, and supervised the development of certain internal control systems.

91

Our organization and compensation committee currently consists of Messrs. Dees, Delimitros and Lollar, with Mr. Lollar acting as chairman. Our organization and compensation committee establishes guidelines and standards relating to the determination of executive compensation, reviews executive compensation policies and recommends to our entire board compensation for our executive officers and key employees. Our organization and compensation committee also administers our equity compensation plan and determines the number of shares covered by, and terms of, grants to executive officers and key employees. All of the members of our compensation committee are non-employee directors.

Our nominating and corporate governance committee currently consists of Messrs. Dees, Delimitros and Lollar, with Mr. Dees acting as chairman. Our nominating and corporate governance committee identifies and evaluates candidates for election as directors, considers appointments to board committees, nominates the slate of directors for election by our stockholders, and develops and recommends to our board our corporate governance principles.

COMPENSATION

Compensation of Directors

We pay each non-employee director an annual retainer of $25,000, each non-employee committee chairperson an annual retainer of $2,000, an attendance fee of $3,000 for each board meeting attended in person, an attendance fee of $1,000 for each committee meeting attended in person and an attendance fee of $500 for each board or committee meeting attended telephonically, and we reimburse all directors for reasonable expenses they incur while attending board and committee meetings.

Any non-employee director may elect to receive a grant of shares of our common stock in lieu of the annual retainer fees as a board member and chairperson and attendance fees for board meetings (except telephonic meetings or other meetings attended by the director telephonically). The number of shares is determined by dividing the fee amount by the closing price per share of our common stock on the last trading day before it becomes obligated to pay the fee.

In addition, each year on the day after the date of our annual stockholders meeting, each non-employee director is entitled to receive 10,000 restricted stock units, which vest ratably over three years with one-third of the restricted stock award vesting on the grant date.

None of our officers who serve as directors receive separate compensation for service on our board of directors.

Executive Compensation

Plains Resources paid all the compensation of its officers during 2000 and 2001. Under a transition services agreement between Plains Resources and Old Plains entered into in 2002, Old Plains reimbursed Plains Resources for costs incurred to provide us with management services, including general and administrative expenses and other employee costs.

92

Summary Compensation Table

The following table shows certain compensation information for our chief executive officer and four additional highly compensated executive officers, or named executive officers, for services rendered to Old Plains in all capacities during the fiscal year ended December 31, 2002.

	Annual Compensation							Long Term Compensation
								Awards			Payouts
Name and Principal Position	Year	Salary ($)(1)		Bonus ($)	Other Annual Compensation ($)			Restricted Stock Award(s) ($)(2)		Securities Underlying Options/ SARs (#)	All Other Compensation ($)
James C. Flores	2002	$	16,668	—	$	400,000		$	682,500	1,125,000	—
Chairman of the Board & Chief Executive Officer
John T. Raymond	2002	$	14,583	—	$	350,000		$	546,000	475,000	—
President and Chief Operating Officer
Stephen A. Thorington	2002	$	12,500	—	$	450,000	(3)	$	409,500	300,000	—
Executive Vice President and Chief Financial Officer
Timothy T. Stephens	2002	$	11,458	—	$	275,000		$	273,000	310,000	—
Executive Vice President— Administration, Secretary and General Counsel
Thomas M. Gladney	2002	$	7,292	—	$	175,000			—	45,000	—
Executive Vice President—Exploration & Production

(1) These amounts constitute the individuals’ salary from the date of the spin-off, December 18, 2002, through December 31, 2002.

(2) These dollar amounts represent the closing price of a share of Old Plains’ common stock on December 18, 2002 (the date of the spin off and the restricted stock grant) at $9.10 times the number of restricted shares granted to the individuals as follows:  Flores—75,000, Raymond—60,000, Thorington—45,000 and Stephens—30,000.

(3) Includes a $350,000 signing bonus.

93

Option/SAR Grants in 2002

The following table provides information regarding stock appreciation rights, or SARs, that were granted to the named executive officers during 2002. No stock options were granted to any other named executive officer during 2002. The amounts shown as potential realizable values are based on assumed annualized rates of stock price appreciation of 5% and 10% over the term of the options as required by SEC rules. No gain to the optionee is possible without an increase in stock price that will benefit all stockholders proportionately. For comparative purposes, also shown are the total gains that could be realized over a five-year period (the term of the options) by all our employees based on the same assumptions. There can be no assurance that the potential realizable values shown in this table will be achieved.

	Individual Grants			Exercise or Base Price ($/Sh)		Expiration Date
Name	Number of Securities Underlying Options/ SARs Granted (#)(1)	Percent of Total Options/ SARs Granted to Employees in 2002					Potential Realizable Value At Assumed Annual Rates of Stock Price Appreciation For Option Term
							5%		10%
James C. Flores	1,000,000	29	%	$	9.08	5/2011	$	4,594,196	$	11,124,318
	125,000	4	%		9.36	2/2007		264,553		572,320
John T. Raymond	100,000	3	%		9.97	5/2011		506,258		1,226,689
	200,000	6	%		9.97	6/2006		367,990		781,932
	175,000	5	%		9.36	2/2007		370,374		801,248
Stephen A. Thorington	300,000	9	%		9.10	9/2007		705,687		1,547,781
Timothy T. Stephens	83,333	2	%		9.97	5/2011		421,880		1,022,237
	166,667	5	%		9.97	6/2006		306,659		651,611
	60,000	2	%		9.36	2/2007		126,985		274,714
Thomas M. Gladney	10,000	0	%		5.47	7/2005		7,415		15,419
	10,000	0	%		9.37	5/2006		16,833		35,692
	25,000	1	%		9.36	2/2007		52,911		114,464
All Employees	3,417,257	100	%					9,251,658		21,393,440

(1) Represents SARs received in the spin-off as a result of the split of Plains Resources options into Plains Resources options and SARs with respect to our common stock.

94

Aggregated SAR Exercises in 2002 and Year-End SAR Values

The following table sets forth certain information for each of the named executive officers concerning the exercise of SARs during 2002 and all unexercised SARs held at December 31, 2002.

Name	Shares Acquired on Exercise (#)	Value Realized ($)	Number of Securities Underlying Unexercised Options/SARs At Fiscal Year-End (#)		Value of Unexercised In-the-Money SARs at Year-End ($)(1)
			Exercisable	Unexercisable	Exercisable		Unexercisable
James C. Flores	—	—	—	1,125,000	$	—	$	718,750
John T. Raymond	—	—	66,667	408,333		—		68,250
Stephen A. Thorington	—	—	—	300,000		—		195,000
Timothy T. Stephens	—	—	83,334	226,666		—		23,400
Thomas M. Gladney	—	—	10,000	35,000		33,050		23,300

(1) Year-end values are determined by aggregating for each SAR outstanding as of December 31, 2002 the amount calculated by multiplying the number of shares underlying such SAR by the closing price of our common stock on December 31, 2002, which was $9.75, less the exercise price of such SAR.

95

PRINCIPAL STOCKHOLDERS

The following table sets forth information regarding the beneficial ownership of our common stock after June 4, 2003 by each of our current directors and executive officers and each person known to us to own beneficially more than 5% of the outstanding shares of our common stock.

Beneficial ownership has been determined in accordance with applicable SEC rules, under which a person is deemed to be the beneficial owner of securities if he or she has or shares voting power or investment power with respect to such securities or has the right to acquire beneficial ownership within 60 days.

Unless otherwise indicated, to our knowledge the persons listed in the table below have sole voting and investment powers with respect to the shares indicated. The address of our directors and officers is 500 Dallas Street, Suite 700, Houston, Texas 77002.

The percentages are based on 40,451,261 shares of our common stock assumed to be issued and outstanding immediately after the merger.

Name and Address of Beneficial Owner	Amount and Nature of Beneficial Ownership		Percent of Class
Alan R. Buckwalter, III	10,000	(1)	*
Jerry L. Dees	12,947	(2)	*
Tom H. Delimitros	16,070	(3)	*
Cynthia A. Feeback	19,601	(4)	*
James C. Flores	1,167,828	(5)	2.8	%
Thomas M. Gladney	31,302	(6)	*
John H. Lollar	23,415	(7)	*
John T. Raymond	140,221	(8)	*
Stephen A. Thorington	100,000	(9)	*
Robert L. Zorich	10,000	(10)	*
Directors and Executive Officers as a group (11 persons)	1,597,124		3.9	%
EnCap Investments L.L.C.(11)	4,263,168	(12)	10.5	%

 * Represents less than 1%.

  (1) This amount includes 6,666 Restricted Stock Units granted as part of the annual non-employee director compensation. These units vest ratably over three years with one-third of the units vesting on the grant date and one-third vesting on each of the first two anniversaries of the grant date.

  (2) This amount includes 6,666 Restricted Stock Units granted as part of the annual non-employee director compensation. These units vest ratably over three years with one-third of the units vesting on the grant date and one-third vesting on each of the first two anniversaries of the grant date.

  (3) These shares include 38 shares that are owned by Mr. Delimitros’ spouse and 6,666 Restricted Stock Units granted as part of the annual non-employee director compensation. These units vest ratably over three years with one-third of the units vesting on the grant date and one-third vesting on each of the first two anniversaries of the grant date.

  (4) 2,101 of these shares are held directly through Plains’ 401(k) Plan. This amount also includes a grant of 17,500 Restricted Stock Units with one-third of the units vesting February 12, 2004, one-third vesting February 12, 2005 and one-third vesting February 12, 2006.

  (5) 1,000,000 of these shares are held directly by Sable Management, L.P., the general partner of which is Sable Management, LLC, of which Mr. Flores is the sole member. 221 of these shares are held directly through Plains’ 401(k) Plan. This amount also includes a grant of 85,000 Restricted Stock Units with one-third of the units vesting February 12, 2004, one-third vesting February 12, 2005 and one-third vesting February 12, 2006.

  (6) 702 of these shares are held directly through Plains’ 401(k) Plan. This amount also includes a grant of 30,000 Restricted Stock Units with one-third of the units vesting February 12, 2004, one-third vesting February 12, 2005 and one-third vesting February 12, 2006.

  (7) This amount includes 6,666 Restricted Stock Units granted as part of the annual non-employee director compensation. These units vest ratably over three years with one-third of the units vesting on the grant date and one-third vesting on each of the first two anniversaries of the grant date.

  (8) 221 of these shares are held directly through Plains’ 401(k) Plan. This amount also includes a grant of 70,000 Restricted Stock Units with one-third of the units vesting February 12, 2004, one-third vesting February 12, 2005 and one-third vesting February 12, 2006.

  (9) This amount includes a grant of 45,000 Restricted Stock Units with one-third of the units vesting February 12, 2004, one-third vesting February 12, 2005 and one-third vesting February 12, 2006.

(10) This amount includes 6,666 Restricted Stock Units granted as part of the annual non-employee director compensation. These units vest ratably over three years with one-third of the units vesting on the grant date and one-third vesting on each of the first two anniversaries of the grant date.

(11) The address for EnCap Investments L.L.C. is 1100 Louisiana Suite 3150, Houston, TX 77002.

(12) Represents 2,138,965 shares held by EnCap Energy Capital Fund III, L.P., 1,011,098 shares held by EnCap Energy Acquisition III-B, Inc., 593,849 shares held by EnCap Energy Capital Fund III-B, L.P., and 519,256 shares held by BOCP Energy Partners, L.P., each of which may be deemed beneficially owned by EnCap Investments L.L.C. as a result of EnCap Investments being the general partner or controlling person of such persons.

96

CERTAIN TRANSACTIONS

Plains Resources owns approximately 24% of Plains All American Pipeline, L.P., or PAA, including 44% of the general partner of PAA. We are party to the following agreements with PAA and Plains Resources:

• a marketing agreement that provides that PAA will purchase all of our equity oil production at market prices for a fee of $0.20 per Bbl. For the purchase of oil under the agreement, including the royalty share of production, in the first six months of 2003, 2002, 2001 and 2000, PAA’s purchases totaled $142.4 million, $225.7 million, $202.1 million and $229.6 million, respectively; and

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

Prior to the reorganization, Old Plains used a centralized cash management system under which its cash receipts were remitted to Plains Resources and its cash disbursements were funded by Plains Resources. Old Plains was charged interest on any amounts, other than income taxes payable, due to Plains Resources at the average effective interest rate of Plains Resources long-term debt. For the years ended December 31, 2002, 2001 and 2000 Old Plains was charged $10.7 million, $20.4 million and $19.5 million, respectively, of interest on amounts payable to Plains Resources. Of such amounts, $9.3 million, $17.3 million and $15.7 million was included in interest expense in 2002, 2001 and 2000, respectively, and $1.4 million, $3.1 million and $3.8 million was capitalized in oil and gas properties in 2002, 2001 and 2000, respectively.

To compensate Plains Resources for services rendered under the Services Agreement described below, we are allocated direct and indirect corporate and administrative costs of Plains Resources. Such costs for the years ended December 31, 2002, 2001 and 2000 totaled $4.4 million, $8.2 million and $3.9 million, respectively. Of such amounts, $3.1 million, $6.1 million and $2.8 million was included in general and administrative expense in 2002, 2001 and 2000, respectively, and $1.3 million, $2.1 million and $1.1 million was capitalized in oil and gas properties in 2002, 2001 and 2000, respectively.

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

In connection with the reorganization and the spin-off Old Plains entered into certain agreements with Plains Resources, including a master separation agreement; an intellectual property agreement; the Plains Exploration & Production transition services agreement; the Plains Resources transition services agreement; and a technical services agreement.

For the six months ended June 30, 2003 we billed Plains Resources $0.3 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.

Master Separation Agreement.    The master separation agreement provides for the separation of substantially all of the upstream assets and liabilities of Plains Resources, other than its Florida

operations. The master separation agreement provides for, among other things: the separation; cross-indemnification provisions; allocation of fees related to these transactions between us and Plains

97

Resources; other provisions governing our relationship with Plains Resources, including mandatory dispute arbitration, sharing information, confidentiality and other covenants; and a noncompetition provision.

Intellectual Property Agreement.    The intellectual property agreement provides that Plains Resources will transfer to us ownership and all rights associated with certain trade names, trademarks and service marks. We will grant to Plains Resources a full license to use certain trade names subject to certain limitations.

Plains Exploration & Production Transition Services Agreement.    This agreement provides that Plains Resources will provide us management, tax, accounting, payroll, insurance, employee benefits, legal and financial services on an interim basis. Through December 31, 2002 Plains Resources has charged us $10.8 million of the $30.0 million maximum amount allowed under the agreement to reimburse it for its costs of providing such services. For the six months ended June 30, 2003 Plains Resources billed us $0.1 million under this agreement.

Plains Resources Transition Services Agreement.    This agreement became effective as of the date of the spin-off and provides that we will provide Plains Resources tax, accounting, payroll, employee benefits, legal and financial services on an interim basis. We will charge Plains Resources on a monthly basis our costs of providing such services. No charges were made to Plains Resources in 2002 under the terms of this agreement.

Technical Services Agreement.    The technical services agreement provides that we will provide Calumet Florida, a subsidiary of Plains Resources, certain engineering and technical support services required to support operation and maintenance of the oil and gas properties owned by Calumet, including geological, geophysical, surveying, drilling and operations services, environmental and other governmental or regulatory compliance related to oil and gas activities and other oil and gas engineering services as requested, and accounting services. We will charge Plains Resources on a monthly basis our costs of providing such services. No charges were made to Plains Resources in 2002 under the terms of this agreement.

For the six months ended June 30, 2003 we billed Plains Resources $0.3 million for services provided under the Plains Resources transition services agreement and the technical services agreement.

We charter private aircraft from Gulf Coast Aviation Inc. (“Gulf Coast”), a corporation which from time-to-time leases an aircraft owned by our Chief Executive Officer. In the first six months of 2003 and the year 2002, respectively, we paid Gulf Coast $0.6 million and $0.2 million, respectively, in connection with charter services in which our Chief Executive Officer’s aircraft was used. The charter services were arranged through arms-length dealings and the rates were market-based.

98

DESCRIPTION OF CERTAIN OTHER INDEBTEDNESS

Initial Notes

On July 3, 2002 Old Plains issued the Initial Notes. Old Plains distributed the net proceeds of $195.3 million from the Initial Notes and $116.7 million in initial borrowings under its existing credit facility described below to Plains Resources, which used it to repay debt.

$500 Million Revolving Credit Facility

On April 4, 2003, Old Plains entered into a new credit facility with a syndicate of banks led by JPMorgan Chase Bank for a three-year, $500.0 million senior revolving credit facility. The credit facility provides for a borrowing base of $402.5 million that will be redetermined on a semi-annual basis, with the lenders and us each having the right to one annual interim unscheduled redetermination, and adjusted based on our oil and gas properties, reserves, other indebtedness and other relevant factors. Additionally, the credit facility contains a $50.0 million sub-limit on letters of credit.

Amounts borrowed under this senior revolving credit facility will bear an annual interest rate, at its election, equal to either; (i) the Eurodollar rate, plus from 1.375% to 2.00%; or (ii) the greatest of (1) the prime rate, as determined by JPMorgan Chase Bank, (2) the certificate of deposit rate, plus 1.0%, or (3) the federal funds rate, plus 0.5%; plus an additional 0.125% to .75% for each of (1)-(3). The amount of interest payable on outstanding borrowings will be 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.

99

DESCRIPTION OF NOTES

On May 30, 2003 the Issuers issued the Series A Notes as joint and several obligors under the indenture (the “Indenture”) dated as of July 3, 2002 among the Issuers, the Subsidiary Guarantors and JPMorgan Chase Bank, as trustee (the “Trustee”), as supplemented by the First Supplemental Indenture dated as of March 31, 2003. The terms of the Notes include those expressly set forth in the Indenture and those made part of the Indenture by reference to the Trust Indenture Act of 1939, as amended (the “Trust Indenture Act”).

This description of Notes is intended to be a useful overview of the material provisions of the Notes and the Indenture. Since this description of notes is only a summary, you should refer to the Indenture for a complete description of the obligations of the Issuers and your rights.

The section entitled “Certain Definitions” includes the definitions of the capitalized terms used in this description. In this section, references to the “Company” mean only Plains Exploration & Production Company and not its subsidiaries and references to the “Issuers” mean collectively Plains Exploration & Production Company and Plains E&P Company.

General

The Notes

The Notes:

• are general unsecured, senior subordinated obligations of the Issuers;

• were initially limited to an aggregate principal amount of $75.0 million, but subject to compliance with the covenant described in “Limitation on Indebtedness,” additional Notes may be issued without limitation as to aggregate principal amount (the “Additional Notes”);

• mature on July 1, 2012;

• will be issued in denominations of $1,000 and integral multiples of $1,000;

• will be represented by one or more registered Notes in global form, but in certain circumstances may be represented by Notes in definitive form. See “Book-entry; Delivery and Form;”

• are subordinated in right of payment to all existing and future Senior Indebtedness of the Issuers;

• rank equally in right of payment to any future Senior Subordinated Indebtedness of the Issuers; and

• are expected to be eligible for trading in The PORTAL^SM Market.

Interest

Interest on the Notes will compound semi-annually and will:

• accrue at the rate of 8¾% per annum;

• accrue from the date of issuance or the most recent interest payment date;

• be payable in cash semi-annually in arrears on January 1 and July 1;

• be payable to the holders of record on the December 15 and June 15 immediately preceding the related interest payment dates; and

100

• be computed on the basis of a 360-day year comprised of twelve 30-day months.

Interest on the Notes will be payable commencing on July 1, 2003. Additional interest may accrue on the Notes in certain circumstances pursuant to the Registration Rights Agreement.

Payments on the Notes; Paying Agent and Registrar

Principal of, premium, if any, and interest on the Notes will be payable, and the Notes may be exchanged or transferred, at the office or agency of the Issuers in the Borough of Manhattan, The City of New York (which initially will be the corporate trust office of the Trustee in New York, New York), except that, at the option of the Issuers, payment of interest may be made by check mailed to the address of the holders as such address appears in the Note Register. Payment of principal of, premium, if any, and interest on, Notes in global form registered in the name of or held by the Depositary or its nominee will be made in immediately available funds to the Depositary or its nominee, as the case may be, as the registered holder of such global Note. No service charge will be made for any registration of transfer or exchange of Notes, but the Issuers may require payment of a sum sufficient to cover any transfer tax or other similar governmental charge payable in connection therewith.

The Trustee will initially act as Paying Agent and Registrar. The Issuers may change the Paying Agent or Registrar without prior notice to the holders of the Notes, and the Issuers or any of the Restricted Subsidiaries may act as Paying Agent or Registrar.

Transfer and Exchange

A holder may transfer or exchange Notes in accordance with the Indenture. The Registrar and the Trustee may require a holder, among other things, to furnish appropriate endorsements and transfer documents and the Issuers may require a holder to pay any taxes and fees required by law or permitted by the Indenture. The Issuers are not required to transfer or exchange any Note selected for redemption. Also, the Issuers are not required to transfer or exchange any Note for a period of 15 days before a selection of Notes to be redeemed.

The registered holder of a Note will be treated as the owner of it for all purposes.

Subordination

The payment of the principal of, premium, if any, and interest on the Notes and any other payment obligations in respect of the Notes (including any obligation to repurchase the Notes) will be subordinated to the prior payment in full in cash or Cash Equivalents when due of all Senior Indebtedness of the Issuers. However, payment from the money or the proceeds of U.S. Government Obligations held in any defeasance trust (as described under “Defeasance” below) is and will not be subordinated to any Senior Indebtedness or subject to these restrictions.

101

As a result of the subordination provisions described below, holders of the Notes may recover less than creditors of the Issuers who are holders of Senior Indebtedness in the event of an insolvency, bankruptcy, reorganization, receivership or similar proceedings relating to the Issuers. Moreover, the Notes will be structurally subordinated to the liabilities of the Subsidiaries of the Issuers other than the Subsidiary Guarantors. See “—Senior Subordinated Guarantees of Notes.” The following table shows the amounts of Senior Indebtedness, Senior Subordinated Indebtedness, total senior debt of the Issuers’ restricted subsidiaries and availability under its credit facility for the Issuers:

	On June 30, 2003
	(amounts in millions)
Total outstanding Senior Indebtedness(1)	$	234.0
Outstanding Senior Subordinated Notes		275.0
Total Senior Indebtedness of the Issuers’ restricted subsidiaries (other than under the Credit Facility and the Notes)		—
Availability under Credit Facility(1)		169.5

(1) Excludes $5.2 million in letters of credit outstanding under our credit facility.

Although the Indenture will limit the amount of indebtedness that the Issuers and the Restricted Subsidiaries may incur, such indebtedness of the Issuers may be substantial and all of it may be Senior Indebtedness.

Only Indebtedness of the Issuers that is Senior Indebtedness will rank senior in right of payment to the Notes in accordance with the provisions of the Indenture. The Notes will in all respects rank equally with all other Senior Subordinated Indebtedness of the Issuers. As described in “Limitation on Layering,” the Issuers may not incur any indebtedness that is senior in right of payment to the Notes, but junior in right of payment to Senior Indebtedness. Unsecured Indebtedness of the Issuers is not deemed to be subordinate or junior to secured Indebtedness merely because it is unsecured.

The Issuers may not pay principal of, premium, if any, or interest on, or other payment obligations in respect of, the Notes or make any deposit pursuant to the provisions described under “Defeasance” below and may not otherwise purchase, redeem or retire any Notes (collectively, “pay the Notes”) if:

(1)    any Senior Indebtedness is not paid when due in cash or Cash Equivalents; or

(2)    any other default on Senior Indebtedness occurs and the maturity of such Senior Indebtedness is accelerated in accordance with its terms unless, in either case, the default has been cured or waived and any such acceleration has been rescinded or such Senior Indebtedness has been paid in full in cash or Cash Equivalents.

However, the Issuers may pay the Notes if the Issuers and the Trustee receive written notice approving such payment from the Representative of the Senior Indebtedness with respect to which either of the events set forth in clause (1) or (2) of the immediately preceding sentence has occurred and is continuing.

The Issuers also will not be permitted to pay the Notes for a Payment Blockage Period (as defined below) during the continuance of any default (a “Non-Payment Default”), other than a default described in clause (1) or (2) of the preceding paragraph, on any Designated Senior Indebtedness that permits the holders of the Designated Senior Indebtedness to accelerate its maturity immediately without either further notice (except such notice as may be required to effect such acceleration) or the expiration of any applicable grace periods.

A “Payment Blockage Period” commences on the receipt by the Trustee (with a copy to the Issuers) of written notice (a “Blockage Notice”) of a default of the kind described in the immediately

102

preceding paragraph from the Representative of the holders of such Designated Senior Indebtedness specifying an election to effect a Payment Blockage Period and ends 179 days thereafter. The Payment Blockage Period will end earlier if such Payment Blockage Period is terminated:

(1)    by written notice to the Trustee and the Issuers from the Person or Persons who gave such Blockage Notice;

(2)    because the default giving rise to such Blockage Notice is no longer continuing; or

(3)    because such Designated Senior Indebtedness has been repaid in full in cash or Cash Equivalents.

The Issuers may resume payments on the Notes after the end of the Payment Blockage Period, unless the holders of such Designated Senior Indebtedness or the Representative of such holders have accelerated the maturity of such Designated Senior Indebtedness. Not more than one Blockage Notice may be given in any consecutive 360-day period, irrespective of the number of defaults with respect to Designated Senior Indebtedness during such period. No Non-Payment Default that existed or was continuing on the date of delivery of any Payment Blockage Period Notice to the Trustee will be, or can be, made the basis for the commencement of a subsequent Payment Blockage Period.

In the event of:

(1)    a total or partial liquidation or a dissolution of the Company;

(2)    a reorganization, bankruptcy, insolvency, receivership of or similar proceeding relating to either Issuer or its property; or

(3)    an assignment for the benefit of creditors or marshaling of either Issuer’s assets and liabilities, then

the holders of Senior Indebtedness will be entitled to receive payment in full in cash or Cash Equivalents in respect of such Senior Indebtedness (including interest accruing after, or which would accrue but for, the commencement of any proceeding at the rate specified in the applicable Senior Indebtedness, whether or not a claim for such interest would be allowed) before the holders of the Notes will be entitled to receive any payment or distribution other than Junior Securities, in the event of any payment or distribution of the assets or securities of the Issuers. In addition, until the Senior Indebtedness is paid in full in cash or Cash Equivalents, any payment or distribution to which holders of the Notes would be entitled but for the subordination provisions of the Indenture will be made to holders of the Senior Indebtedness as their interests may appear. If a payment or distribution is made to holders of the Notes that, due to the subordination provisions, should not have been made to them, such holders are required to hold it in trust for the holders of Senior Indebtedness and pay it over to them as their interests may appear.

If payment of the Notes is accelerated because of an Event of Default, the Issuers or the Trustee will promptly notify the holders of the Designated Senior Indebtedness or the Representative of such holders of the acceleration. The Issuers may not pay the Notes until five Business Days after such holders or the Representative of the Designated Senior Indebtedness receives notice of such acceleration and, after that five Business Day period, may pay the Notes only if the subordination provisions of the Indenture otherwise permit payment at that time.

Senior Subordinated Guarantees of Notes

As of the date of this document, Arguello Inc., Plains Illinois Inc., PMCT Inc., Plains Resources International Inc. and PXP Gulf Coast Inc. will be the only Subsidiary Guarantors; however, other Restricted Subsidiaries may in the future incur Subsidiary Guarantees of the Notes as described in this Description of notes. Each Subsidiary Guarantor will unconditionally guarantee, jointly and severally, to

103

each holder of Notes and the Trustee the full and prompt performance of the Issuers’ obligations under the Indenture and the Notes, including the payment of principal of and premium, if any, on and interest on the Notes pursuant to its Subsidiary Guarantee. The obligations of each Subsidiary Guarantor will be limited to the maximum amount as will, after giving effect to all other contingent and fixed liabilities (including, but not limited to, Guarantor Senior Indebtedness) of such Subsidiary Guarantor and after giving effect to any collections from or payments made by or on behalf of any other Subsidiary Guarantor in respect of the obligations of such other Subsidiary Guarantor under its Subsidiary Guarantee or pursuant to its contribution obligations under the Indenture, result in the obligations of such Subsidiary Guarantor under the Subsidiary Guarantee not constituting a fraudulent conveyance or fraudulent transfer under federal or state law. Each Subsidiary Guarantor that makes a payment or distribution under a Subsidiary Guarantee shall be entitled to a contribution from each other Subsidiary Guarantor in a pro rata amount based on the Adjusted Net Assets of each Subsidiary Guarantor.

Each Subsidiary Guarantor may consolidate with or merge into or sell or otherwise dispose of all or substantially all of its properties and assets to the Company or another Subsidiary Guarantor without limitation, except to the extent any such transaction is subject to the covenant described under “—Merger and Consolidation” or “—Limitation on Sales of Assets and Subsidiary Stock.” Each Subsidiary Guarantor may consolidate with or merge into or sell all or substantially all of its properties and assets to a Person other than the Company or another Subsidiary Guarantor (whether or not Affiliated with the Subsidiary Guarantor). However:

(1)    if the surviving Person is not the Subsidiary Guarantor, the surviving Person must agree to assume the Subsidiary Guarantor’s Subsidiary Guarantee and all its obligations pursuant to the Indenture (except to the extent the following paragraph would result in the release of such Subsidiary Guarantee) and

(2)    the transaction must not (a) violate any of the covenants described under the heading “—Certain Covenants” or (b) result in a Default or Event of Default immediately thereafter that is continuing.

Upon the sale or other disposition (by merger or otherwise) of a Subsidiary Guarantor (or all or substantially all of its properties and assets) to a Person other than the Company or another Subsidiary Guarantor and pursuant to a transaction that is otherwise in compliance with the Indenture (including as described in the foregoing paragraph), such Subsidiary Guarantor shall be deemed released from its Subsidiary Guarantee and the related obligations set forth in the Indenture. However, any such termination shall occur only to the extent that all obligations of such Subsidiary Guarantor under all of its guarantees of, and under all of its pledges of assets or other security interests which secure, other Indebtedness of the Company or any other Restricted Subsidiary shall also terminate upon such sale or other disposition. Each Subsidiary Guarantor that is designated as an Unrestricted Subsidiary in accordance with the Indenture shall be released from its Subsidiary Guarantee and related obligations set forth in the Indenture for so long as it remains an Unrestricted Subsidiary.

The obligations of each Subsidiary Guarantor under its Subsidiary Guarantee are subordinated to the prior payment in full of all Guarantor Senior Indebtedness of such Subsidiary Guarantor (including its guarantee of Indebtedness of the Company under the Senior Credit Agreement) to substantially the same extent as the Notes are subordinated to Senior Indebtedness. The Subsidiary Guarantees will be structurally subordinated to all existing and future liabilities of Subsidiaries of Subsidiary Guarantors that are not also Subsidiary Guarantors.

Optional Redemption

Except as described below, the Notes are not redeemable until July 1, 2007. On and after July 1, 2007, the Issuers may redeem all or a part of the Notes from time to time upon not less than 30 nor

104

more than 60 days’ notice, at the following redemption prices (expressed as a percentage of principal amount) plus accrued and unpaid interest thereon, if any, to the applicable redemption date (subject to the right of holders of record on the relevant record date to receive interest due on the relevant interest payment date), if redeemed during the twelve-month period beginning on July 1 of the years indicated below:

Year	Percentage
2007	104.375	%
2008	102.917	%
2009	101.458	%
2010 and thereafter	100.000	%

Prior to July 1, 2005, the Issuers may on any one or more occasions redeem up to 35% of the original principal amount of the Notes with the Net Cash Proceeds of one or more Equity Offerings at a redemption price of 108.75% of the principal amount thereof, plus accrued and unpaid interest, if any, to the redemption date (subject to the right of holders of record on the relevant record date to receive interest due on the relevant interest payment date); provided that

(1)    at least 65% of the original principal amount of the Notes remains outstanding after each such redemption; and

(2)    the redemption occurs within 90 days after the closing of such Equity Offering.

In the case of any partial redemption, selection of the Notes for redemption will be made by the Trustee in compliance with the requirements of the principal national securities exchange, if any, on which the Notes are listed or, if the Notes are not listed, then on a pro rata basis, by lot or by such other method as the Trustee in its sole discretion will deem to be fair and appropriate, although no Note of $1,000 in original principal amount or less will be redeemed in part. If any Note is to be redeemed in part only, the notice of redemption relating to such Note will state the portion of the principal amount thereof to be redeemed. A new Note in principal amount equal to the unredeemed portion thereof will be issued in the name of the holder thereof upon cancellation of the original Note.

Mandatory Redemption

The Issuers are not required to make mandatory redemption or sinking fund payments with respect to the Notes.

Change of Control

If a Change of Control occurs, each holder will have the right to require the Issuers to repurchase all or any part (equal to $1,000 or an integral multiple thereof) of such holder’s Notes at a purchase price in cash equal to 101% of the principal amount of the Notes plus accrued and unpaid interest, if any, to the date of purchase (subject to the right of holders of record on the relevant record date to receive interest due on the relevant interest payment date).

Within 30 days following any Change of Control, the Issuers will mail a notice (the “Change of Control Offer”) to each holder with a copy to the Trustee stating:

(1)    that a Change of Control has occurred and that such holder has the right to require the Issuers to purchase such holder’s Notes at a purchase price in cash equal to 101% of the principal amount thereof plus accrued and unpaid interest, if any, to the date of purchase (subject to the right of holders of record on a record date to receive interest on the relevant interest payment date) (the “Change of Control Payment”);

105

(2)    the repurchase date (which shall be no earlier than 30 days nor later than 60 days from the date such notice is mailed) (the “Change of Control Payment Date”); and

(3)    the procedures determined by the Issuers, consistent with the Indenture, that a holder must follow in order to have its Notes repurchased.

On the Change of Control Payment Date, the Issuers will, to the extent lawful:

(1)    accept for payment all Notes or portions thereof (equal to $1,000 or an integral multiple thereof) properly tendered pursuant to the Change of Control Offer;

(2)    deposit with the paying agent an amount equal to the Change of Control Payment in respect of all Notes or portions thereof so tendered; and

(3)    deliver or cause to be delivered to the Trustee the Notes so accepted together with an Officers’ Certificate stating the aggregate principal amount of Notes or portions thereof being purchased by the Issuers.

The paying agent will promptly mail to each holder of Notes so tendered the Change of Control Payment for such Notes, and the Trustee will promptly authenticate and mail (or cause to be transferred by book entry) to each holder a new Note equal in principal amount to any unpurchased portion of the Notes surrendered, if any; provided that each such new Note will be in a principal amount of $1,000 or an integral multiple thereof.

If the Change of Control Payment Date is on or after an interest record date and on or before the related interest payment date, any accrued and unpaid interest will be paid to the Person in whose name a Note is registered at the close of business on such record date, and no additional interest will be payable to holders who tender pursuant to the Change of Control Offer.

The Change of Control provisions described above will be applicable whether or not any other provisions of the Indenture are applicable. Except as described above with respect to a Change of Control, the Indenture does not contain provisions that permit the holders to require that the Issuers repurchase or redeem the Notes in the event of a takeover, recapitalization or similar transaction.

Prior to mailing a Change of Control Offer, and as a condition to such mailing (i) all Senior Indebtedness must be repaid in full in cash or Cash Equivalents, or the Issuers must offer to repay all Senior Indebtedness whose holders accept such offer or (ii) the requisite holders of each issue of Senior Indebtedness shall have consented to such Change of Control Offer being made and waived the event of default, if any, caused by the Change of Control. The Issuers covenant to effect such repayment or obtain such consent and waiver within 30 days following any Change of Control, it being a default of the Change of Control provision if the Issuers fail to comply with such covenant. A default under the Indenture may result in a cross-default under the Senior Credit Agreement. In the event of a default under the Senior Credit Agreement, the subordination provisions of the Indenture would likely restrict payments to the holders of the Notes.

The Issuers will not be required to make a Change of Control Offer upon a Change of Control if a third party makes the Change of Control Offer in the manner, at the times and otherwise in compliance with the requirements set forth in the Indenture applicable to a Change of Control Offer made by the Issuers and purchases all Notes validly tendered and not withdrawn under such Change of Control Offer.

The Issuers will comply, to the extent applicable, with the requirements of Section 14(e) of the Exchange Act and any other securities laws or regulations in connection with the repurchase of Notes pursuant to this covenant. To the extent that the provisions of any securities laws or regulations conflict

106

with provisions of the Indenture, the Issuers will comply with the applicable securities laws and regulations and will not be deemed to have breached its obligations described in the Indenture by virtue thereof.

The Issuers’ ability to repurchase Notes pursuant to a Change of Control Offer may be limited by a number of factors. The occurrence of the events that constitute a Change of Control will constitute a default under the Senior Credit Agreement. In addition, certain events that may constitute a change of control under the Senior Credit Agreement and cause a default thereunder may not constitute a Change of Control under the Indenture. Future Indebtedness of the Issuers and the Subsidiaries may also contain prohibitions of certain events that would constitute a Change of Control or require such Indebtedness to be repurchased upon a Change of Control. Moreover, the exercise by the holders of their right to require the Issuers to repurchase the Notes could cause a default under such Indebtedness, even if the Change of Control itself does not, due to the financial effect of such repurchase on the Issuers. Finally, the Issuers’ ability to pay cash to the holders upon a repurchase may be limited by the Issuers’ then existing financial resources. There can be no assurance that sufficient funds will be available when necessary to make any required repurchases.

The Change of Control provisions described above may deter certain mergers, tender offers and other takeover attempts involving the Issuers by increasing the capital required to effectuate such transactions. The definition of “Change of Control” includes a disposition of all or substantially all of the property and assets of the Company and its Restricted Subsidiaries taken as a whole to any Person. Although there is a limited body of case law interpreting the phrase “substantially all,” there is no precise established definition of the phrase under applicable law. Accordingly, in certain circumstances there may be a degree of uncertainty as to whether a particular transaction would involve a disposition of “all or substantially all” of the property or assets of a Person. As a result, it may be unclear as to whether a Change of Control has occurred and whether a holder of Notes may require the Issuers to make an offer to repurchase the Notes as described above.

Certain Covenants

Limitation on Indebtedness

The Company will not, and will not permit any of its Restricted Subsidiaries to, Incur any Indebtedness; provided, however, that the Company and its Restricted Subsidiaries may Incur Indebtedness if on the date thereof:

(1)    the Consolidated Coverage Ratio for the Company and its Restricted Subsidiaries is at least 2.50 to 1.00; and

(2)    no Default or Event of Default will have occurred and be continuing or would occur as a consequence thereof.

The first paragraph of this covenant will not prohibit the incurrence of the following Indebtedness:

(1)    Indebtedness Incurred pursuant to the Senior Credit Agreement, including any amendment, modification, supplement, extension, restatement, replacement (including replacement after the termination of such Senior Credit Agreement), restructuring, increase, renewal, or refinancing thereof from time to time in one or more agreements or instruments; provided, however, that, after giving effect to any such Incurrence, the aggregate principal amount of such Indebtedness then outstanding does not exceed the greater of (i) $300.0 million and (ii) so long as the Consolidated Coverage Ratio for the Company and its Restricted Subsidiaries is at least 2.00 to 1.00 after giving effect to any such Incurrence, $100.0 million plus 25% of Adjusted Consolidated Net Tangible Assets determined as of the date of the Incurrence of such Indebtedness;

107

(2)    Indebtedness owed to and held by the Company or a Restricted Subsidiary; provided, however, that any subsequent issuance or transfer of any Capital Stock which results in any such Restricted Subsidiary ceasing to be a Restricted Subsidiary or any subsequent transfer of such Indebtedness (other than to the Company or a Restricted Subsidiary) shall be deemed, in each case, to constitute the Incurrence of such Indebtedness by the obligor thereon;

(3)    Indebtedness under the Notes (but not Additional Notes) and the Subsidiary Guarantees;

(4)    Indebtedness outstanding on the Issue Date (other than Indebtedness described in clause (1), (2) or (3) of this covenant);

(5)    Indebtedness of a Restricted Subsidiary Incurred and outstanding on or prior to the date on which such Subsidiary was acquired by the Company (other than Indebtedness Incurred in connection with, or to provide all or any portion of the funds or credit support utilized to consummate, the transaction or series of related transactions pursuant to which such Subsidiary became a Restricted Subsidiary or was acquired by the Company);

(6)    Refinancing Indebtedness in respect of Indebtedness Incurred pursuant to the first paragraph of this covenant or pursuant to clause (3), (4), (5) or this clause (6); provided, however, that to the extent such Refinancing Indebtedness directly or indirectly Refinances Indebtedness of a Subsidiary Incurred pursuant to clause (5), such Refinancing Indebtedness shall be Incurred only by such Subsidiary or the Company;

(7)    Permitted Acquisition Indebtedness;

(8)    Indebtedness in respect of purchase money obligations, including Capitalized Lease Obligations, in an aggregate amount not to exceed $25.0 million;

(9)    Hedging Obligations consisting of Interest Rate Agreements directly related to Indebtedness permitted to be Incurred pursuant to the Indenture;

(10)    Non-Recourse Debt;

(11)    Indebtedness in respect of bid, performance, reimbursement or surety obligations issued by or for the account of the Company or any Restricted Subsidiary in the ordinary course of business, including Guarantees and letters of credit functioning as or supporting such bid, performance, reimbursement or surety obligations (in each case other than for an obligation for money borrowed);

(12)    Indebtedness consisting of obligations in respect of purchase price adjustments, indemnities or Guarantees of the same or similar matters in connection with the acquisition or disposition of Property;

(13)    Indebtedness under Commodity Agreements and Currency Agreements entered into in the ordinary course of business for the purpose of limiting risks that arise in the ordinary course of business of the Company and its Restricted Subsidiaries;

(14)    Any Guarantee by the Company or a Subsidiary of the Company of Indebtedness Incurred pursuant to the first paragraph of this covenant or pursuant to clause (1), (2), (3), (4), (8), (9), (13) or (15) or pursuant to clause (6) to the extent the Refinancing Indebtedness Incurred thereunder directly or indirectly Refinances Indebtedness Incurred pursuant to the first paragraph of this covenant or pursuant to clauses (3) or (4); and

(15)    Indebtedness in an aggregate principal amount which, when taken together with all other Indebtedness of the Company outstanding on the date of such Incurrence (other than Indebtedness permitted by clauses (1) through (14) above or the first paragraph of this covenant) does not exceed $30.0 million.

The Company will not Incur any Indebtedness under the preceding paragraph if the proceeds thereof are used, directly or indirectly, to refinance any Subordinated Obligations of the Company

108

unless such Indebtedness will be subordinated to the Notes to at least the same extent as such Subordinated Obligations.

For purposes of determining compliance with, and the outstanding principal amount of any particular Indebtedness incurred pursuant to and in compliance with, this covenant:

(i)    in the event that Indebtedness meets the criteria of more than one of the types of Indebtedness described in the first and second paragraphs of this covenant, the Company, in its sole discretion, will on the date of Incurrence classify (or later reclassify) such item of Indebtedness and only be required to include the amount and type of such Indebtedness in one of such clauses; and

(ii)    the amount of Indebtedness issued at a price that is less than the principal amount thereof will be equal to the amount of the liability in respect thereof determined in accordance with GAAP.

Accrual of interest, accrual of dividends, the accretion of accreted value, the payment of interest in the form of additional Indebtedness and the payment of dividends in the form of additional shares of Preferred Stock will not be deemed to be an incurrence of Indebtedness for purposes of this covenant. The amount of any Indebtedness outstanding as of any date shall be (i) the accreted value thereof in the case of any Indebtedness issued with original issue discount and (ii) the principal amount or liquidation preference thereof, together with any interest thereon that is more than 30 days past due, in the case of any other Indebtedness.

In addition, the Company will not permit any of its Unrestricted Subsidiaries to Incur any Indebtedness or issue any shares of Disqualified Stock, other than Non-Recourse Debt. If at any time an Unrestricted Subsidiary becomes a Restricted Subsidiary, any Indebtedness of such Subsidiary shall be deemed to be Incurred by a Restricted Subsidiary of the Company as of such date (and, if such Indebtedness is not permitted to be Incurred as of such date under this “Limitation on Indebtedness” covenant, the Company shall be in Default of this covenant).

For purposes of determining compliance with any U.S. dollar-denominated restriction on the Incurrence of Indebtedness, the U.S. dollar-equivalent principal amount of Indebtedness denominated in a foreign currency shall be calculated based on the relevant currency exchange rate in effect on the date such Indebtedness was Incurred, in the case of term Indebtedness, or first committed, in the case of revolving credit Indebtedness; provided that if such Indebtedness is Incurred to refinance other Indebtedness denominated in a foreign currency, and such refinancing would cause the applicable U.S. dollar-denominated restriction to be exceeded if calculated at the relevant currency exchange rate in effect on the date of such refinancing, such U.S. dollar-denominated restriction shall be deemed not to have been exceeded so long as the principal amount of such refinancing Indebtedness does not exceed the principal amount of such Indebtedness being refinanced. Notwithstanding any other provision of this covenant, the maximum amount of Indebtedness that the Company may Incur pursuant to this covenant shall not be deemed to be exceeded solely as a result of fluctuations in the exchange rate of currencies. The principal amount of any Indebtedness incurred to refinance other Indebtedness, if Incurred in a different currency from the Indebtedness being refinanced, shall be calculated based on the currency exchange rate applicable to the currencies in which such Refinancing Indebtedness is denominated that is in effect on the date of such refinancing.

Limitation on Layering

The Issuers will not Incur any Indebtedness if such Indebtedness is subordinate or junior in ranking in any respect to any Senior Indebtedness unless such Indebtedness is Senior Subordinated Indebtedness or is contractually subordinated in right of payment to Senior Subordinated Indebtedness. No Subsidiary Guarantor will incur or allow to remain outstanding, any Indebtedness

109

(including Acquired Indebtedness and any indebtedness allowed pursuant to the second paragraph of the covenant described under “Limitation on Indebtedness”) other than such Subsidiary Guarantor’s Subsidiary Guarantee, that is subordinated in right of payment to any Guarantor Senior Indebtedness unless such Indebtedness is Guarantor Senior Subordinated Indebtedness or is subordinated in right of payment to Guarantor Senior Subordinated Indebtedness.

Limitation on Restricted Payments

The Company will not, and will not permit any of its Restricted Subsidiaries, directly or indirectly, to:

(1)    declare or pay any dividend or make any distribution on or in respect of its Capital Stock (including any payment in connection with any merger or consolidation involving the Company or any of its Restricted Subsidiaries) except:

(a)    dividends or distributions payable in Capital Stock of the Company (other than Disqualified Stock) or in options, warrants or other rights to purchase such Capital Stock of the Company; and

(b)    dividends or distributions payable to the Company or a Restricted Subsidiary of the Company (and if such Restricted Subsidiary is not a Wholly-Owned Subsidiary, to its other holders of common Capital Stock on a pro rata basis);

(2)    purchase, redeem, retire or otherwise acquire for value any Capital Stock of the Company or any direct or indirect parent of the Company held by Persons other than the Company or a Restricted Subsidiary of the Company (other than in exchange for Capital Stock of the Company (other than Disqualified Stock));

(3)    purchase, repurchase, redeem, defease or otherwise acquire or retire for value, prior to scheduled maturity, scheduled repayment or scheduled sinking fund payment, any Subordinated Obligations (other than the purchase, repurchase or other acquisition of Subordinated Obligations purchased in anticipation of satisfying a sinking fund obligation, principal installment or final maturity, in each case due within one year of the date of purchase, repurchase or acquisition); or

(4)    make any Restricted Investment in any Person;

(any such dividend, distribution, purchase, redemption, repurchase, defeasance, other acquisition, retirement or Restricted Investment referred to in clauses (1) through (4) shall be referred to herein as a “Restricted Payment”), if at the time the Company or such Restricted Subsidiary makes such Restricted Payment:

(a)    a Default shall have occurred and be continuing (or would result therefrom); or

(b)    the Company is not able to Incur an additional $1.00 of Indebtedness pursuant to the first paragraph under the “Limitation on Indebtedness” covenant after giving effect to such Restricted Payment; or

(c)    the aggregate amount of such Restricted Payment and all other Restricted Payments declared or made subsequent to the Issue Date would exceed the sum of:

(i)    50% of Consolidated Net Income for the period (treated as one accounting period) from the beginning of the first fiscal quarter commencing after the date of the Indenture to the end of the most recent fiscal quarter ending prior to the date of such Restricted Payment for which financial statements are in existence (or, in case such Consolidated Net Income is a deficit, minus 100% of such deficit);

(ii)    the aggregate Net Cash Proceeds received by the Company from the issue or sale of its Capital Stock (other than Disqualified Stock) or other capital contributions

110

subsequent to the Issue Date (other than Net Cash Proceeds received from an issuance or sale of such Capital Stock to a Subsidiary of the Company or an employee stock ownership plan, option plan or similar trust to the extent such sale to an employee stock ownership plan, option plan or similar trust is financed by loans from or Guaranteed by the Company or any Restricted Subsidiary unless such loans have been repaid with cash on or prior to the date of determination);

(iii)    the amount by which Indebtedness of the Company is reduced on the Company’s balance sheet upon the conversion or exchange (other than by a Subsidiary of the Company) subsequent to the Issue Date of any Indebtedness of the Company convertible or exchangeable for Capital Stock (other than Disqualified Stock) of the Company (less the amount of any cash, or other property, distributed by the Company upon such conversion or exchange); and

(iv)    the amount equal to the net reduction in Restricted Investments made by the Company or any of its Restricted Subsidiaries in any Person resulting from:

(A)    repurchases or redemptions of such Restricted Investments by such Person, proceeds realized upon the sale of such Restricted Investment to a purchaser other than the Company or a Subsidiary, repayments of loans or advances or other transfers of assets (including by way of dividend or distribution) by such Person to the Company or any Restricted Subsidiary of the Company; or

(B)    the redesignation of Unrestricted Subsidiaries as Restricted Subsidiaries (valued in each case as provided in the definition of “Investment”) not to exceed, in the case of any Unrestricted Subsidiary, the amount of Investments previously made by the Company or any Restricted Subsidiary in such Unrestricted Subsidiary,

which amount in each case under this clause (iv) was included in the calculation of the amount of Restricted Payments; provided, however, that no amount will be included under this clause (iv) to the extent it is already included in Consolidated Net Income.

The provisions of the preceding paragraph will not prohibit:

(1)    any purchase or redemption of Capital Stock or Subordinated Obligations of the Company made by exchange for, or out of the proceeds of the substantially concurrent sale of, Capital Stock of the Company (other than Disqualified Stock and other than Capital Stock issued or sold to a Subsidiary or an employee stock ownership plan or similar trust to the extent such sale to an employee stock ownership plan or similar trust is financed by loans from or guaranteed by the Company or any Restricted Subsidiary unless such loans have been repaid with cash on or prior to the date of determination); provided, however, that (a) such purchase or redemption will be excluded in subsequent calculations of the amount of Restricted Payments and (b) the Net Cash Proceeds from such sale will be excluded from clause (c)(ii) of the preceding paragraph;

(2)    any purchase or redemption of Subordinated Obligations of the Company made by exchange for, or out of the proceeds of the substantially concurrent sale of, Subordinated Obligations of the Company that qualifies as Refinancing Indebtedness; provided, however, that such purchase or redemption will be excluded in subsequent calculations of the amount of Restricted Payments;

(3)    so long as no Default or Event of Default has occurred and is continuing, any purchase or redemption of Subordinated Obligations or Preferred Stock from Net Available Cash to the extent permitted under “—Limitation on Sales of Assets and Subsidiary Stock” below; provided, however, that such purchase or redemption will be excluded in subsequent calculations of the amount of Restricted Payments;

(4)    dividends paid within 60 days after the date of declaration if at such date of declaration such dividend would have complied with this provision; provided, however, that such dividends will be

111

included in subsequent calculations of the amount of Restricted Payments unless the declaration of such dividend had been counted in a prior period;

(5)    so long as no Default or Event of Default has occurred and is continuing, the declaration and payment of dividends to holders of any class or series of Disqualified Stock of the Company issued in accordance with the terms of the Indenture to the extent such dividends are included in the definition of “Consolidated Interest Expense;” provided, that the payment of such dividends will be excluded from subsequent calculations of Restricted Payments;

(6)    repurchases of Capital Stock deemed to occur upon the exercise of stock options if such Capital Stock represents a portion of the exercise price thereof; provided, however, that such repurchases will be excluded from subsequent calculations of the amount of Restricted Payments;

(7)    payments contemplated by the Transition Agreements (except the employment matters agreement) as in effect on the date hereof, as these agreements may be amended, modified or supplemented from time to time; provided, however, that any future amendment, modification or supplement entered into after the Issue Date will be permitted to the extent that its terms do not adversely affect the rights of any holders of the Notes as compared to the terms of the agreements in effect on the Issue Date; provided, further, that payments made pursuant to the Plains Exploration & Production transition services agreement shall be the costs and expenses incurred in providing the services and limited in an aggregate amount not to exceed $30.0 million;

(8)    repurchases of Capital Stock of any officer, director or employee of the Company in an aggregate amount not to exceed $2.0 million in any twelve-month period; provided, that such payments will be excluded from subsequent calculation of the amounts of Restricted Payments; and

(9)    Restricted Payments in an amount not to exceed $15.0 million; provided, that such payments will be included in subsequent calculations of the amount of Restricted Payments.

The amount of all Restricted Payments (other than cash) shall be the fair market value on the date of such Restricted Payment of the asset(s) or securities proposed to be paid, transferred or issued by the Company or such Restricted Subsidiary, as the case may be, pursuant to such Restricted Payment. The fair market value of any cash Restricted Payment shall be its face amount and any non-cash Restricted Payment shall be determined conclusively by the Board of Directors acting in good faith whose resolution with respect thereto shall be delivered to the Trustee, such determination to be based upon an opinion or appraisal issued by an accounting, appraisal or investment banking firm of national standing if such fair market value is estimated to exceed $25.0 million. Not later than the date of making any Restricted Payment other than a Restricted Payment allowed pursuant to (1) through (9) of the previous paragraph, the Company shall deliver to the Trustee an Officers’ Certificate stating that such Restricted Payment is permitted and setting forth the basis upon which the calculations required by the covenant “Restricted Payments” were computed, together with a copy of any fairness opinion or appraisal required by the Indenture.

Limitation on Liens

The Company will not, and will not permit any of its Restricted Subsidiaries to, directly or indirectly, create, incur or permit to exist any Lien (other than Permitted Liens) upon any Principal Property or any shares of stock or Indebtedness of any Restricted Subsidiary that owns or leases any Principal Property (whether such Principal Property, shares of stock or Indebtedness are now owned or hereafter acquired), securing any Senior Subordinated Indebtedness or Subordinated Obligations, unless all payments due under the Indenture with respect to the Notes are secured on an equal and ratable basis with the obligations so secured until such time as such obligations are no longer secured by a Lien.

112

Limitation on Restrictions on Distributions from Restricted Subsidiaries

The Company will not, and will not permit any Restricted Subsidiary to, create or otherwise cause or permit to exist or become effective any consensual encumbrance or consensual restriction on the ability of any Restricted Subsidiary to:

(1)    pay dividends or make any other distributions on its Capital Stock or pay any Indebtedness or other obligations owed to the Company or any Restricted Subsidiary;

(2)    make any loans or advances to the Company or any Restricted Subsidiary; or

(3)    transfer any of its property or assets to the Company or any Restricted Subsidiary.

The preceding provisions will not prohibit:

(i)    any encumbrance or restriction pursuant to an agreement in effect at or entered into on the Issue Date (including, without limitation, the Indenture and the Senior Credit Agreement in effect on such date);

(ii)    any encumbrance or restriction with respect to a Restricted Subsidiary pursuant to an agreement effecting a refinancing of Indebtedness Incurred pursuant to an agreement referred to in clause (i) of this paragraph or this clause (ii) or contained in any amendment to an agreement referred to in clause (i) of this paragraph or this clause (ii); provided, however, that the encumbrances and restrictions with respect to such Restricted Subsidiary contained in any such agreement or amendment taken as a whole are no less favorable in any material respect to the holders of the Notes than the encumbrances and restrictions contained in such agreements referred to in clause (i) of this paragraph on the Issue Date;

(iii)    in the case of clause (3) of the first paragraph of this covenant, any encumbrance or restriction:

(a)    that restricts in a customary manner the subletting, assignment or transfer of any property or asset that is subject to a lease, license or similar contract, or the assignment or transfer of any such lease, license or other contract;

(b)    contained in mortgages, pledges or other security agreements permitted under the Indenture securing Indebtedness of the Company or a Restricted Subsidiary to the extent such encumbrances or restrictions restrict the transfer of the property subject to such mortgages, pledges or other security agreements; or

(c)    pursuant to customary provisions restricting dispositions of real property interests set forth in any reciprocal easement agreements of the Company or any Restricted Subsidiary;

(iv)    purchase money obligations for property acquired in the ordinary course of business that impose encumbrances or restrictions of the nature described in clause (3) of the first paragraph of this covenant on the property so acquired;

(v)    any restriction with respect to a Restricted Subsidiary (or any of its property or assets) imposed pursuant to an agreement entered into for the direct or indirect sale or disposition of all or substantially all the Capital Stock or assets of such Restricted Subsidiary (or the property or assets that are subject to such restriction) pending the closing of such sale or disposition;

(vi)    encumbrances or restrictions arising or existing by reason of applicable law or any applicable rule, regulation or order;

(vii)    customary supermajority voting provisions and other customary provisions with respect to the disposition or distribution of assets or property in joint venture agreements;

(viii)    customary encumbrances or restrictions imposed pursuant to any agreement referred to in the definition of “Permitted Business Investment;”

113

(ix)    encumbrances or restrictions in instruments evidencing Indebtedness of a Restricted Subsidiary Incurred and outstanding on or prior to the date on which such Subsidiary was acquired by the Company; provided, however, that such encumbrances or restrictions are not created, incurred or assumed in connection with, or in contemplation of, such acquisition; and

(x)    Indebtedness permitted under the Indenture containing encumbrances or restrictions that taken as a whole are not materially more restrictive than the encumbrances and restrictions otherwise contained in the Indenture.

Limitation on Sales of Assets and Subsidiary Stock

The Company will not, and will not permit any of its Restricted Subsidiaries to, make any Asset Disposition unless:

(1)    the Company or such Restricted Subsidiary receives consideration at the time of such Asset Disposition at least equal to the fair market value, as determined in good faith by the Board of Directors (including as to the value of all non-cash consideration), of the shares and assets subject to such Asset Disposition;

(2)    at least 75% of the consideration thereof received by the Company or such Restricted Subsidiary, as the case may be, is in the form of cash, Cash Equivalents or Additional Assets; and

(3)    an amount equal to 100% of the Net Available Cash from such Asset Disposition is applied by the Company or such Restricted Subsidiary, as the case may be:

(a)    to the extent the Company or any Restricted Subsidiary, as the case may be, elects (or is required by the terms of any Senior Indebtedness), to prepay, repay or purchase Senior Indebtedness or Indebtedness (other than any Preferred Stock) of a Restricted Subsidiary that is a Subsidiary Guarantor (in each case other than Indebtedness owed to the Company or an Affiliate of the Company) within 360 days from the later of the date of such Asset Disposition or the receipt of such Net Available Cash; provided, however, that, in connection with any prepayment, repayment or purchase of Indebtedness pursuant to this clause (a), the Company or such Restricted Subsidiary will retire such Indebtedness and will cause the related commitment (if any) to be permanently reduced in an amount equal to the principal amount so prepaid, repaid or purchased; and

(b)    to the extent the Company or such Restricted Subsidiary elects, to invest in Additional Assets within 360 days from the later of the date of such Asset Disposition or the receipt of such Net Available Cash.

Pending the final application of any Net Available Cash, the Company may temporarily reduce its revolving credit borrowings or otherwise invest such Net Available Cash in any manner that is not prohibited by the Indenture.

Any Net Available Cash from Asset Dispositions that is not applied or invested as provided in the second preceding paragraph will be deemed to constitute “Excess Proceeds.” On the 361st day after an Asset Disposition (or, if there exists any Senior Indebtedness with similar provisions requiring the Company to make an offer to purchase such Senior Indebtedness, on the 451st day after an Asset Disposition), if the aggregate amount of Excess Proceeds exceeds $10.0 million, the Issuers will be required to make an offer (“Asset Disposition Offer”) to all holders of Notes and to the extent required by the terms thereof, to all holders of other Senior Subordinated Indebtedness outstanding with similar provisions requiring the Company or the Issuers to make an offer to purchase such Senior Subordinated Indebtedness with the proceeds from any Asset Disposition (“Pari Passu Notes”), to purchase the maximum principal amount of Notes and any such Pari Passu Notes to which the Asset Disposition Offer applies that may be purchased out of the Excess Proceeds, at an offer price in cash

114

in an amount equal to 100% of the principal amount thereof plus accrued and unpaid interest to the date of purchase, in accordance with the procedures set forth in the Indenture or the agreements governing the Pari Passu Notes, as applicable. To the extent that the aggregate amount of Notes and Pari Passu Notes so validly tendered and not properly withdrawn pursuant to an Asset Disposition Offer is less than the Excess Proceeds, the Issuers may use any remaining Excess Proceeds for general corporate or partnership purposes, subject to the other covenants contained in the Indenture. If the aggregate principal amount of Notes surrendered by holders thereof and other Pari Passu Notes surrendered by holders or lenders thereof, collectively, exceeds the amount of Excess Proceeds, the Trustee shall select the Notes to be purchased on a pro rata basis on the basis of the aggregate principal amount of tendered Notes and Pari Passu Notes. Upon completion of such Asset Disposition Offer, the amount of Excess Proceeds shall be reset at zero.

The Asset Disposition Offer will remain open for a period of 20 Business Days following its commencement, except to the extent that a longer period is required by applicable law (the “Asset Disposition Offer Period”). No later than five Business Days after the termination of the Asset Disposition Offer Period (the “Asset Disposition Purchase Date”), the Issuers will purchase the principal amount of Notes and Pari Passu Notes required to be purchased pursuant to this covenant (the “Asset Disposition Offer Amount”) or, if less than the Asset Disposition Offer Amount has been so validly tendered, all Notes and Pari Passu Notes validly tendered in response to the Asset Disposition Offer.

If the Asset Disposition Purchase Date is on or after an interest record date and on or before the related interest payment date, any accrued and unpaid interest will be paid to the Person in whose name a Note is registered at the close of business on such record date, and no additional interest will be payable to holders who tender Notes pursuant to the Asset Disposition Offer.

On or before the Asset Disposition Purchase Date, the Issuers will, to the extent lawful, accept for payment, on a pro rata basis to the extent necessary, the Asset Disposition Offer Amount of Notes and Pari Passu Notes or portions thereof so validly tendered and not properly withdrawn pursuant to the Asset Disposition Offer, or if less than the Asset Disposition Offer Amount has been validly tendered and not properly withdrawn, all Notes and Pari Passu Notes so validly tendered and not properly withdrawn. The Issuers will deliver to the Trustee an Officers’ Certificate stating that such Notes or portions thereof were accepted for payment by the Issuers in accordance with the terms of this covenant and, in addition, the Issuers will deliver all certificates and notes required, if any, by the agreements governing the Pari Passu Notes. The Issuers or the Paying Agent, as the case may be, will promptly (but in any case not later than five Business Days after the termination of the Asset Disposition Offer Period) mail or deliver to each tendering holder of Notes or holder or lender of Pari Passu Notes, as the case may be, an amount equal to the purchase price of the Notes or Pari Passu Notes so validly tendered and not properly withdrawn by such holder or lender, as the case may be, and accepted by the Issuers for purchase, and the Issuers will promptly issue a new Note, and the Trustee, upon delivery of an Officers’ Certificate from the Issuers will authenticate and mail or deliver such new Note to such holder, in a principal amount equal to any unpurchased portion of the Note surrendered. In addition, the Company or the Issuers will take any and all other actions required by the agreements governing the Pari Passu Notes. Any Note not so accepted will be promptly mailed or delivered by the Issuers to the holder thereof. The Issuers will publicly announce the results of the Asset Disposition Offer on the Asset Disposition Purchase Date.

For the purposes of this covenant, the following will be deemed to be cash:

(1)    the assumption by the transferee of Indebtedness (other than Senior Subordinated Indebtedness, Subordinated Obligations or Disqualified Stock) of the Company or Indebtedness (other than Preferred Stock) of any Restricted Subsidiary of the Company and the release of the Company or such Restricted Subsidiary from all liability on such Indebtedness in connection with such Asset Disposition (in which case the Company will, without further action, be deemed to have applied such deemed cash to Indebtedness in accordance with clause (3)(a) above); and

115

(2)    securities, notes or other obligations received by the Company or any Restricted Subsidiary of the Company from the transferee that are promptly converted by the Company or such Restricted Subsidiary into cash.

The Issuers will comply, to the extent applicable, with the requirements of Section 14(e) of the Exchange Act and any other securities laws or regulations in connection with the repurchase of Notes pursuant to the Indenture. To the extent that the provisions of any securities laws or regulations conflict with provisions of this covenant, the Issuers will comply with the applicable securities laws and regulations and will not be deemed to have breached its obligations under the Indenture by virtue thereof.

Limitation on Affiliate Transactions

The Company will not, and will not permit any of its Restricted Subsidiaries to, directly or indirectly, enter into or conduct any transaction (including the purchase, sale, lease or exchange of any property or the rendering of any service) with any Affiliate of the Company (an “Affiliate Transaction”) unless:

(1)    the terms of such Affiliate Transaction are no less favorable to the Company or such Restricted Subsidiary, as the case may be, than those that could be obtained in a comparable transaction at the time of such transaction in arm’s-length dealings with a Person who is not such an Affiliate;

(2)    in the event such Affiliate Transaction involves an aggregate amount in excess of $5.0 million, the terms of such transaction have been approved by a majority of the members of the Board of Directors of the Company and by a majority of the members of such Board having no personal stake in such transaction, if any (and such majority or majorities, as the case may be, determines that such Affiliate Transaction satisfies the criteria in clause (1) above); and

(3)    in the event such Affiliate Transaction involves an aggregate amount in excess of $20.0 million, the Company has received a written opinion from an independent investment banking firm, appraiser or other expert of nationally recognized standing that such Affiliate Transaction is not materially less favorable than those that might reasonably have been obtained in a comparable transaction at such time on an arms-length basis from a Person that is not an Affiliate.

The preceding paragraph will not apply to:

(1)    any Restricted Payment (other than a Restricted Investment) permitted to be made pursuant to the covenant described under “Limitation on Restricted Payments;”

(2)    any issuance of securities, or other payments, awards or grants in cash, securities or otherwise pursuant to, or the funding of, employment arrangements, stock options and stock ownership plans and other reasonable fees, compensation, benefits and indemnities paid or entered into by the Company or its Restricted Subsidiaries in the ordinary course of business to or with officers, directors or employees of the Company and its Restricted Subsidiaries;

(3)    loans or advances to employees in the ordinary course of business of the Company or any of its Restricted Subsidiaries;

(4)    any transaction between the Company and a Restricted Subsidiary or between Restricted Subsidiaries;

(5)    the payment of reasonable and customary fees paid to, and indemnity provided on behalf of, officers, directors or employees of the Company or any Restricted Subsidiary of the Company;

(6)    any transaction between the Company and Plains Resources Inc. and its Subsidiaries or between a Restricted Subsidiary and Plains Resources Inc. or its Subsidiaries pursuant to any of

116

the Transition Agreements as in effect on the Issue Date, as these agreements may be amended, modified or supplemented from time to time; provided, however that any future amendment, modification or supplement entered into after the Issue Date will be permitted to the extent that its terms do not adversely affect the rights of any holders of the Notes as compared to the terms of the agreements in effect on the Issue Date;

(7)    any transaction pursuant to the existing agreements between the Company and PAA as in effect on the date hereof, as these agreements may be amended, modified or supplemented from time to time; provided, however that any future amendment, modification or supplement entered into after the Issue Date will be permitted to the extent that its terms do not adversely affect the rights of any holders of the Notes as compared to the terms of the agreements in effect on the Issue Date; and

(8)    the performance of obligations of the Company or any of its Restricted Subsidiaries under the terms of any agreement to which the Company or any of its Restricted Subsidiaries is a party on the Issue Date and identified on a schedule to the Indenture on the Issue Date, as these agreements may be amended, modified or supplemented from time to time; provided, however that any future amendment, modification or supplement entered into after the Issue Date will be permitted to the extent that its terms do not adversely affect the rights of any holders of the Notes as compared to the terms of the agreements in effect on the Issue Date.

Limitation on Sale of Capital Stock of Restricted Subsidiaries

The Company will not, and will not permit any Restricted Subsidiary of the Company to, transfer, convey, sell, lease or otherwise dispose of any Voting Stock of any Restricted Subsidiary or to issue any of the Voting Stock of a Restricted Subsidiary (other than, if necessary, shares of its Voting Stock constituting directors’ qualifying shares) to any Person except:

(1)    to the Company or a Restricted Subsidiary or the parent of a Restricted Subsidiary; or

(2)    in compliance with the covenant described under “—Limitation on Sales of Assets and Subsidiary Stock” and immediately after giving effect to such issuance or sale, such Restricted Subsidiary would continue to be a Restricted Subsidiary.

Notwithstanding the preceding paragraph, the Company may sell all the Voting Stock of a Restricted Subsidiary as long as the Company complies with the terms of the covenant described under “—Limitation on Sales of Assets and Subsidiary Stock.”

SEC Reports

Notwithstanding that the Company may not be subject to the reporting requirements of Section 13 or 15(d) of the Exchange Act, to the extent permitted by the Exchange Act, the Company will file with the Commission, and provide the Trustee and the holders of the Notes with, the annual reports and the information, documents and other reports (or copies of such portions of any of the foregoing as the Commission may by rules and regulations prescribe) that are specified in Sections 13 and 15(d) of the Exchange Act within the time periods specified therein. In the event that the Company is not permitted to file such reports, documents and information with the Commission pursuant to the Exchange Act, the Company will nevertheless provide such Exchange Act information to the Trustee and the holders of the Notes as if the Company were subject to the reporting requirements of Section 13 or 15(d) of the Exchange Act within the time periods specified therein.

117

Merger and Consolidation

The Company will not consolidate with or merge with or into, or convey, transfer or lease all or substantially all its assets to, any Person, unless:

(1)    the resulting, surviving or transferee Person (the “Successor Company”) will be a corporation, partnership, trust or limited liability company organized and existing under the laws of the United States of America, any State thereof or the District of Columbia and the Successor Company (if not the Company) will expressly assume, by supplemental indenture, executed and delivered to the Trustee, in form satisfactory to the Trustee, all the obligations of the Company under the Notes and the Indenture;

(2)    immediately after giving effect to such transaction (and treating any Indebtedness that becomes an obligation of the Successor Company or any Subsidiary of the Successor Company as a result of such transaction as having been Incurred by the Successor Company or such Subsidiary at the time of such transaction), no Default or Event of Default shall have occurred and be continuing;

(3)    immediately after giving effect to such transaction, the Successor Company would be able to Incur at least an additional $1.00 of Indebtedness pursuant to the first paragraph of the “Limitation on Indebtedness” covenant;

(4)    if the Company is not the continuing obligor under the Indenture, then any Subsidiary Guarantor, unless it is the Successor Company, shall have by supplemental indenture to the Indenture confirmed that its Subsidiary Guarantee of the Notes shall apply to the Successor Company’s obligations under the Indenture and the Notes; and

(5)    the Company shall have delivered to the Trustee an Officers’ Certificate and an Opinion of Counsel, each stating that such consolidation, merger or transfer and such supplemental indenture (if any) comply with the Indenture.

For purposes of this covenant, the sale, lease, conveyance, assignment, transfer, or other disposition of all or substantially all of the properties and assets of one or more Subsidiaries of the Company, which properties and assets, if held by the Company instead of such Subsidiaries, would constitute all or substantially all of the properties and assets of the Company on a consolidated basis, shall be deemed to be the transfer of all or substantially all of the assets of the Company.

The Successor Company will succeed to, and be substituted for, and may exercise every right and power of, the Company under the Indenture, but, in the case of a lease of all or substantially all its assets, the Company will not be released from the obligation to pay the principal of and interest on the Notes.

Although there is a limited body of case law interpreting the phrase “substantially all,” there is no precise established definition of the phrase under applicable law. Accordingly, in certain circumstances there may be a degree of uncertainty as to whether a particular transaction would involve “all or substantially all” of the property or assets of a Person.

Notwithstanding the foregoing, the Company is permitted to reorganize as a corporation in accordance with the procedures established in the Indenture, and may merge or consolidate with an Affiliate for such purpose; provided that the Company shall have delivered to the Trustee an Opinion of Counsel reasonably acceptable to the Trustee confirming that the holders of the outstanding Notes will not recognize income, gain or loss for federal income tax purposes as a result of such reorganization. Notwithstanding the preceding clause (3), (x) any Restricted Subsidiary of the Company may consolidate with, merge into or transfer all or part of its properties and assets to the Company, and (y) if then a corporation, the Company may merge with an Affiliate solely for the purpose of reincorporating the Company in another jurisdiction to realize tax or other benefits.

118

Effectiveness of Covenants

The covenants described under “—Limitation on Indebtedness,” “—Limitation on Layering,” “—Limitation on Restricted Payments,” “—Limitation on Restrictions on Distributions from Restricted Subsidiaries,” “—Limitation on Sales of Assets and Subsidiary Stock,” “—Limitation on Sale of Capital Stock of Restricted Subsidiaries,” “—Limitation on Lines of Business” and “—Payments for Consent” (collectively, the “Suspended Covenants”), will no longer be in effect upon (a) the Notes having an Investment Grade Rating from either of the Rating Agencies and (b) no Default or Event of Default having occurred and continuing under the Indenture. In the event that the Issuers and the Restricted Subsidiaries are not subject to the Suspended Covenants for any period of time as a result of the preceding sentence and, subsequently, one or both of the Rating Agencies withdraws its ratings or downgrades the rating assigned to the Notes below the required Investment Grade Ratings or a Default or Event of Default occurs and is continuing, then the Issuers and the Restricted Subsidiaries will thereafter again be subject to the Suspended Covenants and compliance with the Suspended Covenants. Compliance with the Suspended Covenants with respect to Restricted Payments made after the time of such withdrawal, downgrade, Default or Event of Default will be calculated in accordance with the terms of the covenant described above under “—Limitation on Restricted Payments” as though such covenant had been in effect during the entire period of time from the date the Notes are issued.

Future Subsidiary Guarantors

After the Issuer Date, the Company will cause each Restricted Subsidiary other than a Foreign Subsidiary created or acquired by the Company to execute and deliver to the Trustee a Subsidiary Guarantee pursuant to which such Subsidiary Guarantor will unconditionally Guarantee, on a joint and several basis, the full and prompt payment of the principal of, premium, if any, and interest on the Notes on a senior subordinated basis.

Limitation on Lines of Business

The Company will not, and will not permit any Restricted Subsidiary to, engage in any business other than a Related Business.

Restrictions on Activities of Plains E&P Company

Plains E&P Company will not hold any material assets, become liable for any material obligations, other than the Notes, or engage in any significant business activities; provided that Plains E&P Company may be a co-obligor with respect to Indebtedness if the Company is the primary obligor of such Indebtedness and the net proceeds of such Indebtedness are received by the Company or one or more of the Company’s Restricted Subsidiaries other than Plains E&P Company. At any time after the Company is a corporation, Plains E&P Company may consolidate or merge with or into the Company or any Restricted Subsidiary.

Payments for Consent

Neither the Issuers nor any of the Restricted Subsidiaries will, directly or indirectly, pay or cause to be paid any consideration, whether by way of interest, fees or otherwise, to any holder of any Notes for or as an inducement to any consent, waiver or amendment of any of the terms or provisions of the Indenture or the Notes unless such consideration is offered to be paid or is paid to all holders of the Notes that consent, waive or agree to amend in the time frame set forth in the solicitation documents relating to such consent, waiver or agreement.

119

Events of Default

Each of the following is an Event of Default:

(1)    default in any payment of interest or additional interest (as required by the Registration Rights Agreement) on any Note when due, continued for 30 days, whether or not such payment is prohibited by the provisions described under “Subordination;”

(2)    default in the payment of principal of or premium, if any, on any Note when due at its Stated Maturity, upon optional redemption, upon required repurchase, upon declaration or otherwise, whether or not such payment is prohibited by the provisions described under “Subordination;”

(3)    failure by the Company to comply with its obligations under “Certain Covenants—Merger and Consolidation;”

(4)    failure by the Issuers to comply for 30 days after notice with any of its obligations under the covenants described under “Change of Control” above or under the covenants described under “Certain Covenants” above (in each case, other than a failure to purchase Notes which will constitute an Event of Default under clause (2) above and other than a failure to comply with “Certain Covenants—Merger and Consolidation” which is covered by clause (3));

(5)    failure by the Issuers or any Subsidiary Guarantor to comply for 60 days after notice with its other agreements contained in the Indenture;

(6)    default under any mortgage, indenture or instrument under which there may be issued or by which there may be secured or evidenced any Indebtedness for money borrowed by the Company or any of its Restricted Subsidiaries (or the payment of which is guaranteed by the Company or any of its Restricted Subsidiaries), other than Indebtedness owed to the Company or a Restricted Subsidiary, whether such Indebtedness or guarantee now exists, or is created after the date of the Indenture, which default:

(a)    is caused by a failure to pay principal of, or interest or premium, if any, on such Indebtedness prior to the expiration of the grace period provided in such Indebtedness (“payment default”); or

(b)    results in the acceleration of such Indebtedness prior to its maturity (the “cross acceleration provision”);

and, in each case, the principal amount of any such Indebtedness, together with the principal amount of any other such Indebtedness under which there has been a payment default or the maturity of which has been so accelerated, aggregates $10.0 million or more;

(7)    any Subsidiary Guarantee shall be held in a judicial proceeding to be, or be asserted by the Issuers or any Subsidiary Guarantor, as applicable, not to be, enforceable or valid or shall cease to be in full force and effect (except pursuant to the release or termination of any such Subsidiary Guarantee in accordance with the Indenture);

(8)    certain events of bankruptcy, insolvency or reorganization of the Company or a Significant Subsidiary or group of Restricted Subsidiaries that, taken together (as of the latest audited consolidated financial statements for the Company and its Restricted Subsidiaries), would constitute a Significant Subsidiary (the “bankruptcy provisions”); or

(9)    failure by the Company or any Significant Subsidiary or group of Restricted Subsidiaries that, taken together (as of the latest audited consolidated financial statements for the Company and its Restricted Subsidiaries), would constitute a Significant Subsidiary to pay final judgments aggregating in excess of $10.0 million (net of any amounts that a reputable and creditworthy insurance company has acknowledged liability for in writing), which judgments are not paid, discharged or stayed for a period of 60 days (the “judgment default provision”).

120

However, a default under clauses (4) and (5) of this paragraph will not constitute an Event of Default until the Trustee or the holders of 25% in principal amount of the outstanding Notes notify the Company, and the Trustee in the case of a notice given by the holders, of the default and the Company does not cure such default within the time specified in clauses (4) and (5) of this paragraph after receipt of such notice.

If an Event of Default (other than an Event of Default described in clause (8) above) occurs and is continuing, the Trustee by notice to the Company, or the holders of at least 25% in principal amount of the outstanding Notes by notice to the Company and the Trustee, may, and the Trustee at the request of such holders shall, declare the principal of, premium, if any, and accrued and unpaid interest, if any, on all the Notes to be due and payable. Upon such a declaration, such principal, premium and accrued and unpaid interest will be due and payable immediately. In the event of a declaration of acceleration of the Notes because an Event of Default described in clause (6) under “Events of Default” has occurred and is continuing, the declaration of acceleration of the Notes shall be automatically annulled if the event of default or payment default triggering such Event of Default pursuant to clause (6) shall be remedied or cured by the Company or a Restricted Subsidiary of the Company or waived by the holders of the relevant Indebtedness within 20 days after the declaration of acceleration with respect thereto and if (1) the annulment of the acceleration of the Notes would not conflict with any judgment or decree of a court of competent jurisdiction and (2) all existing Events of Default, except nonpayment of principal, premium or interest on the Notes that became due solely because of the acceleration of the Notes, have been cured or waived. If an Event of Default described in clause (8) above occurs and is continuing, the principal of, premium, if any, and accrued and unpaid interest on all the Notes will become and be immediately due and payable without any declaration or other act on the part of the Trustee or any holders. The holders of a majority in principal amount of the outstanding Notes may waive all past defaults (except with respect to nonpayment of principal, premium or interest) and rescind any such acceleration with respect to the Notes and its consequences if (1) rescission would not conflict with any judgment or decree of a court of competent jurisdiction and (2) all existing Events of Default, other than the nonpayment of the principal of, premium, if any, and interest on the Notes that have become due solely by such declaration of acceleration, have been cured or waived.

Subject to the provisions of the Indenture relating to the duties of the Trustee, if an Event of Default occurs and is continuing, the Trustee will be under no obligation to exercise any of the rights or powers under the Indenture at the request or direction of any of the holders unless such holders have offered to the Trustee reasonable indemnity or security against any loss, liability or expense. Except to enforce the right to receive payment of principal, premium, if any, or interest when due, no holder may pursue any remedy with respect to the Indenture or the Notes unless:

(1)    such holder has previously given the Trustee notice that an Event of Default is continuing;

(2)    holders of at least 25% in principal amount of the outstanding Notes have requested the Trustee to pursue the remedy;

(3)    such holders have offered the Trustee reasonable security or indemnity against any loss, liability or expense;

(4)    the Trustee has not complied with such request within 60 days after the receipt of the request and the offer of security or indemnity; and

(5)    the holders of a majority in principal amount of the outstanding Notes have not given the Trustee a direction that, in the opinion of the Trustee, is inconsistent with such request within such 60-day period.

Subject to certain restrictions, the holders of a majority in principal amount of the outstanding Notes are given the right to direct the time, method and place of conducting any proceeding for any remedy available to the Trustee or of exercising any trust or power conferred on the Trustee. The

121

Trustee, however, may refuse to follow any direction that conflicts with law or the Indenture or that the Trustee determines is unduly prejudicial to the rights of any other holder or that would involve the Trustee in personal liability. Prior to taking any action under the Indenture, the Trustee will be entitled to indemnification satisfactory to it in its sole discretion against all losses and expenses caused by taking or not taking such action.

The Indenture provides that if a Default occurs and is continuing and is known to the Trustee, the Trustee must mail to each holder notice of the Default within 90 days after it occurs. Except in the case of a Default in the payment of principal of, premium, if any, or interest on any Note, the Trustee may withhold notice if and so long as a committee of trust officers of the Trustee in good faith determines that withholding notice is in the interests of the holders. In addition, the Issuers are required to deliver to the Trustee, within 120 days after the end of each fiscal year, a certificate indicating whether the signers thereof know of any Default that occurred during the previous year. The Issuers also are required to deliver to the Trustee, within 30 days after the occurrence thereof, written notice of any events which would constitute certain Defaults, their status and what action the Issuers are taking or proposes to take in respect thereof.

In the case of any Event of Default occurring by reason of any willful action (or inaction) taken (or not taken) by or on behalf of the Issuers with the intention of avoiding payment of the premium that the Issuers would have had to pay if the Issuers then had elected to redeem the Notes pursuant to the optional redemption provisions of the Indenture or were required to repurchase the Notes, an equivalent premium shall also become and be immediately due and payable to the extent permitted by law upon the acceleration of the Notes. If an Event of Default occurs prior to July 1, 2007 by reason of any willful action (or inaction) taken (or not taken) by or on behalf of the Issuers with the intention of avoiding the prohibition on redemption of the Notes prior to July 1, 2007, the premium specified in the Indenture for the period commencing July 1, 2007 shall also become immediately due and payable to the extent permitted by law upon the acceleration of the Notes.

Amendments and Waivers

Subject to certain exceptions, the Indenture may be amended with the consent of the holders of a majority in principal amount of the Notes then outstanding (including without limitation, consents obtained in connection with a purchase of, or tender offer or exchange offer for, Notes) and, subject to certain exceptions, any past default or compliance with any provisions may be waived with the consent of the holders of a majority in principal amount of the Notes then outstanding (including, without limitation, consents obtained in connection with a purchase of, or tender offer or exchange offer for, Notes). However, without the consent of each holder of an outstanding Note affected, no amendment may, among other things:

(1)    reduce the amount of Notes whose holders must consent to an amendment;

(2)    reduce the stated rate of or extend the stated time for payment of interest on any Note;

(3)    reduce the principal of or extend the Stated Maturity of any Note;

(4)    reduce the premium payable upon the redemption or repurchase of any Note or change the time at which any Note may be redeemed or repurchased as described above under “Optional Redemption,” “Change of Control,” “Certain Covenants—Limitation on Sales of Assets and Subsidiary Stock” or any similar provision, whether through an amendment or waiver of provisions in the covenants, definitions or otherwise;

(5)    make any Note payable in money other than that stated in the Note;

(6)    impair the right of any holder to receive payment of, premium, if any, principal of and interest on such holder’s Notes on or after the due dates therefor or to institute suit for the enforcement of any payment on or with respect to such holder’s Notes;

122

(7)    reduce the relative ranking of any Notes or Subsidiary Guarantees; or

(8)    make any change in the amendment provisions which require each holder’s consent or in the waiver provisions.

Without the consent of any holder, the Issuers, the Subsidiary Guarantors and the Trustee may amend the Indenture to:

(1)    cure any ambiguity, omission, defect or inconsistency;

(2)    provide for the assumption by a successor corporation, partnership, trust or limited liability company of the obligations of the Issuers under the Indenture;

(3)    provide for uncertificated Notes in addition to or in place of certificated Notes (provided that the uncertificated Notes are issued in registered form for purposes of Section 163(f) of the Code, or in a manner such that the uncertificated Notes are described in Section 163(f) (2) (B) of the Code);

(4)    add or release Subsidiary Guarantees pursuant to the terms of the Indenture;

(5)    secure the Notes;

(6)    add to the covenants of the Company and the Subsidiary Guarantors for the benefit of the holders or surrender any right or power conferred upon the Company;

(7)    make any change that does not adversely affect the rights of any holder; or

(8)    comply with any requirement of the Commission in connection with the qualification of the Indenture under the Trust Indenture Act.

However, no amendment may be made to the subordination provisions of the Indenture that adversely affects the rights of any holder of Senior Indebtedness then outstanding unless the holders of such Senior Indebtedness (or any group or representative thereof authorized to give a consent) consent to such change. In addition, any amendment to the subordination provisions of the Indenture that adversely affects the rights of any holder of the Notes will require the consent of the holders of at least 66 ²/3% in aggregate principal amount of the Notes then outstanding.

The consent of the holders is not necessary under the Indenture to approve the particular form of any proposed amendment. It is sufficient if such consent approves the substance of the proposed amendment. After an amendment under the Indenture becomes effective, the Company is required to mail to the holders a notice briefly describing such amendment. However, the failure to give such notice to all the holders, or any defect therein, will not impair or affect the validity of the amendment.

Defeasance

The Issuers at any time may terminate all their obligations under the Notes and the Indenture and all obligations of the Subsidiary Guarantors under the Subsidiary Guarantees and the Indenture (“legal defeasance”), except for certain obligations, including those respecting the defeasance trust and obligations to register the transfer or exchange of the Notes, to replace mutilated, destroyed, lost or stolen Notes and to maintain a registrar and paying agent in respect of the Notes.

The Issuers at any time may terminate their and the Subsidiary Guarantors obligations under covenants described under “Certain Covenants” (other than “Merger and Consolidation”), the operation of the cross-default upon a payment default, cross acceleration provisions, the bankruptcy provisions with respect to Significant Subsidiaries and the judgment default provision described under “Events of Default” above and the limitations contained in clause (3) under “Certain Covenants—Merger and Consolidation” above (“covenant defeasance”).

123

The Issuers may exercise their legal defeasance option notwithstanding the prior exercise of a covenant defeasance option. If the Issuers exercise their legal defeasance option, payment of the Notes may not be accelerated because of an Event of Default with respect thereto. If the Issuers exercise their covenant defeasance option, payment of the Notes may not be accelerated because of an Event of Default specified in clause (4), (5), (6), (8) (with respect only to Significant Subsidiaries) or (9) under “Events of Default” above or because of the failure of the Company to comply with clause (3) under “Certain Covenants—Merger and Consolidation” above.

In order to exercise either defeasance option, the Issuers or any Subsidiary Guarantor must irrevocably deposit in trust (the “defeasance trust”) with the Trustee money or U.S. Government Obligations for the payment of principal, premium, if any, and interest on the Notes to redemption or maturity, as the case may be, and must comply with certain other conditions, including delivery to the Trustee of an Opinion of Counsel (subject to customary exceptions and exclusions) to the effect that holders of the Notes will not recognize income, gain or loss for Federal income tax purposes as a result of such deposit and defeasance and will be subject to Federal income tax on the same amount and in the same manner and at the same times as would have been the case if such deposit and defeasance had not occurred. In the case of legal defeasance only, such Opinion of Counsel must be based on a ruling of the Internal Revenue Service or other change in applicable Federal income tax law.

Satisfaction and Discharge

The Indenture will be discharged and will cease to be of further effect (except as to surviving rights of registration of transfer or exchange of the Notes, as expressly provided for in the Indenture) as to all outstanding Notes and the Subsidiary Guarantees when:

(1)    either (a) all the Notes theretofore authenticated and delivered (except lost, stolen or destroyed Notes which have been replaced or paid and Notes for whose payment money or certain United States governmental obligations have theretofore been deposited in trust or segregated and held in trust by the Issuers and thereafter repaid to the Issuers or discharged from such trust) have been delivered to the Trustee for cancellation or (b) all Notes not theretofore delivered to the Trustee for cancellation have become due and payable or will become due and payable at their Stated Maturity within one year, or are to be called for redemption within one year under arrangements satisfactory to the Trustee for the giving of notice of redemption by the Trustee in the name, and at the expense, of the Issuers, and the Issuers or the Subsidiary Guarantors have irrevocably deposited or caused to be deposited with the Trustee funds or U.S. Government Obligations, or a combination thereof, in an amount sufficient to pay and discharge the entire indebtedness on the Notes not theretofore delivered to the Trustee for cancellation, for principal of and premium, if any, on and interest on the Notes to the date of deposit (in the case of Notes which have become due and payable) or to the Stated Maturity or redemption date, as the case may be, together with instructions from the Issuers irrevocably directing the Trustee to apply such funds to the payment thereof at maturity or redemption, as the case may be;

(2)    the Issuers or the Subsidiary Guarantors have paid all other sums then due and payable under the Indenture by the Issuers; and

(3)    the Issuers have delivered to the Trustee an Officers’ Certificate and an Opinion of Counsel, which, taken together, state that all conditions precedent under the Indenture relating to the satisfaction and discharge of the Indenture have been complied with.

No Personal Liability of Directors, Officers, Employees, Partners and Stockholders

No director, officer, employee, incorporator, partner or stockholder of the Company, Plains E&P Company or any Subsidiary Guarantor, as such, shall have any liability for any obligations of the Company, Plains E&P Company or the Subsidiary Guarantors under the Notes, the Indenture, the

124

Subsidiary Guarantees or for any claim based on, in respect of, or by reason of, such obligations or their creation. Each holder by accepting a Note waives and releases all such liability. The waiver and release are part of the consideration for issuance of the Notes. Such waiver may not be effective to waive liabilities under the federal securities laws and it is the view of the Commission that such a waiver is against public policy.

Concerning the Trustee

JPMorgan Chase Bank is the Trustee under the Indenture and has been appointed by the Issuers as Registrar and Paying Agent with regard to the Notes.

Governing Law

The Indenture provides that it, the Notes and the Subsidiary Guarantees will be governed by, and construed in accordance with, the laws of the State of New York.

Certain Definitions

“Additional Assets” means:

(1)    any property or assets (other than Indebtedness and Capital Stock) to be used by the Company or a Restricted Subsidiary in a Related Business;

(2)    the Capital Stock of a Person that becomes a Restricted Subsidiary as a result of the acquisition of such Capital Stock by the Company or a Restricted Subsidiary of the Company; or

(3)    Capital Stock constituting a minority interest in any Person that at such time is a Restricted Subsidiary of the Company;

provided, however, that, in the case of clauses (2) and (3), such Restricted Subsidiary is primarily engaged in a Related Business.

“Adjusted Consolidated Net Tangible Assets” means (without duplication), as of the date of determination, the remainder of:

(a)    the sum of:

(i)    discounted future net revenues from proved oil and gas reserves of the Company and its Restricted Subsidiaries calculated in accordance with SEC guidelines before any provincial, territorial, state, Federal or foreign income taxes, as estimated by the Company in a reserve report prepared as of the end of the Company’s most recently completed fiscal year for which audited financial statements are available and giving effect to applicable Commodity Agreements, as increased by, as of the date of determination, the estimated discounted future net revenues from

(A)    estimated proved oil and gas reserves acquired since such year end, which reserves were not reflected in such year end reserve report, and

(B)    estimated oil and gas reserves attributable to upward revisions of estimates of proved oil and gas reserves since such year end due to exploration, development or exploitation activities, in each case calculated in accordance with SEC guidelines (utilizing the prices for the fiscal quarter ending prior to the date of determination and giving effect to applicable Commodity Agreements),

and decreased by, as of the date of determination, the estimated discounted future net revenues from

125

(C)    estimated proved oil and gas reserves produced or disposed of since such year end, and

(D)    estimated oil and gas reserves attributable to downward revisions of estimates of proved oil and gas reserves since such year end due to changes in geological conditions or other factors which would, in accordance with standard industry practice, cause such revisions, in each case calculated on a pre-tax basis and substantially in accordance with SEC guidelines (utilizing the prices for the fiscal quarter ending prior to the date of determination and giving effect to applicable Commodity Agreements), in each case as estimated by the Company’s petroleum engineers or any independent petroleum engineers engaged by the Company for that purpose;

(ii)    the capitalized costs that are attributable to oil and gas properties of the Company and its Restricted Subsidiaries to which no proved oil and gas reserves are attributable, based on the Company’s books and records as of a date no earlier than the date of the Company’s latest available annual or quarterly financial statements;

(iii)    the Net Working Capital on a date no earlier than the date of the Company’s latest annual or quarterly financial statements; and

(iv)    the greater of

(A)    the net book value of other tangible assets of the Company and its Restricted Subsidiaries, as of a date no earlier than the date of the Company’s latest annual or quarterly financial statement, and

(B)    the appraised value, as estimated by independent appraisers, of other tangible assets of the Company and its Restricted Subsidiaries, as of a date no earlier than the date of the Company’s latest audited financial statements (provided that the Company shall not be required to obtain such appraisal solely for the purpose of determining this value); minus

(b)    the sum of:

(i)    Minority Interests;

(ii)    any net gas balancing liabilities of the Company and its Restricted Subsidiaries reflected in the Company’s latest audited financial statements;

(iii)    to the extent included in (a)(i) above, the discounted future net revenues, calculated in accordance with SEC guidelines (utilizing the prices utilized in the Company’s year end reserve report), attributable to reserves which are required to be delivered to third parties to fully satisfy the obligations of the Company and its Restricted Subsidiaries with respect to Volumetric Production Payments (determined, if applicable, using the schedules specified with respect thereto); and

(iv)    the discounted future net revenues, calculated in accordance with SEC guidelines, attributable to reserves subject to Dollar-Denominated Production Payments which, based on the estimates of production and price assumptions included in determining the discounted future net revenues specified in (a)(i) above, would be necessary to fully satisfy the payment obligations of the Company and its Subsidiaries with respect to Dollar-Denominated Production Payments (determined, if applicable, using the schedules specified with respect thereto).

If the Company changes its method of accounting from the full cost or a similar method to the successful efforts method of accounting, “Adjusted Consolidated Net Tangible Assets” will continue to be calculated as if the Company were still using the full cost or a similar method of accounting.

126

“Adjusted Net Assets” of a Subsidiary Guarantor at any date means the amount by which the fair value of the properties and assets of such Subsidiary Guarantor exceeds the total amount of liabilities, including, without limitation, contingent liabilities (after giving effect to all other fixed and contingent liabilities incurred or assumed on such date), but excluding liabilities under its Subsidiary Guarantee, of such Subsidiary Guarantor at such date.

“Affiliate” of any specified Person means any other Person, directly or indirectly, controlling or controlled by or under direct or indirect common control with such specified Person. For the purposes of this definition, “control” when used with respect to any Person means the power to direct the management and policies of such Person, directly or indirectly, whether through the ownership of voting securities, by contract or otherwise; and the terms “controlling” and “controlled” have meanings correlative to the foregoing.

“Asset Disposition” means any direct or indirect sale, lease (other than an operating lease entered into in the ordinary course of business), transfer, issuance or other disposition, or a series of related sales, leases, transfers, issuances or dispositions that are part of a common plan, of shares of Capital Stock of a Subsidiary (other than directors’ qualifying shares), property or other assets (each referred to for the purposes of this definition as a “disposition”) by the Company or any of its Restricted Subsidiaries, including any disposition by means of a merger, consolidation or similar transaction.

Notwithstanding the preceding, the following items shall not be deemed to be Asset Dispositions:

  (1)    a disposition by a Restricted Subsidiary to the Company or by the Company or a Restricted Subsidiary to a Wholly-Owned Subsidiary;

  (2)    the transfer of cash and Cash Equivalents in the ordinary course of business;

  (3)    a disposition of Hydrocarbons or mineral products inventory in the ordinary course of business;

  (4)    a disposition of obsolete or worn out equipment or equipment that is no longer useful in the conduct of the business of the Company and its Restricted Subsidiaries and that is disposed of in each case in the ordinary course of business;

  (5)    transactions permitted under “Certain Covenants—Merger and Consolidation;”

  (6)    an issuance of Capital Stock by a Restricted Subsidiary of the Company to the Company or to a Wholly-Owned Subsidiary;

  (7)    for purposes of “Certain Covenants—Limitation on Sales of Assets and Subsidiary Stock” only, the making of a Permitted Investment or a disposition that constitutes a Restricted Payment permitted under “Certain Covenants—Limitation on Restricted Payments;”

  (8)    dispositions of assets with an aggregate fair market value of less than $1.0 million;

  (9)    dispositions in connection with Permitted Liens;

(10)    any Change of Control;

(11)    dispositions of defaulted accounts receivable to any collection agency;

(12)    the licensing or sublicensing of intellectual property or other general intangibles and licenses, leases or subleases of other property in the ordinary course of business and which do not materially interfere with the business of the Company and its Restricted Subsidiaries;

(13)    foreclosure on assets;

(14)    the sale or transfer (whether or not in the ordinary course of business) of crude oil and natural gas properties or direct or indirect interests in real property; provided, that at the time of such sale or transfer such properties do not have associated with them any proved reserves; and

127

(15)    the farm-out, lease or sublease of developed or undeveloped crude oil and natural gas Property owned or held by the Company or such Restricted Subsidiary for crude oil and natural gas Property owned or held by another Person.

“Attributable Indebtedness” in respect of a Sale/Leaseback Transaction means, as at the time of determination, the present value (discounted at the interest rate borne by the Notes, compounded semi-annually) of the total obligations of the lessee for rental payments during the remaining term of the lease included in such Sale/Leaseback Transaction (including any period for which such lease has been extended).

“Average Life” means, as of the date of determination, with respect to any Indebtedness or Preferred Stock, the quotient obtained by dividing (1) the sum of the products of the numbers of years from the date of determination to the dates of each successive scheduled principal payment of such Indebtedness or redemption or similar payment with respect to such Preferred Stock multiplied by the amount of such payment by (2) the sum of all such payments.

“Bank Indebtedness” means any and all amounts, whether outstanding on the Issue Date or thereafter Incurred, payable by the Company or any Subsidiary Guarantor under or in respect of the Senior Credit Agreement and any related notes, collateral documents, letters of credit and guarantees and any Interest Rate Agreement entered into with any lender or affiliate of a lender, including principal, premium, if any, interest (including interest accruing on or after the filing of any petition in bankruptcy or for reorganization relating to the Company or any Subsidiary Guarantor at the rate specified therein whether or not a claim for post filing interest is allowed in such proceedings), fees, charges, expenses, reimbursement obligations, guarantees and all other amounts payable thereunder or in respect thereof.

“Board of Directors” means, as to any Person, the board of directors of such Person or any duly authorized committee thereof; provided that so long as the Company is a limited partnership, “Board of Directors” means the board of directors of Stocker Resources, Inc., its general partner, or any duly authorized committee thereof.

“Capital Stock” of any Person means any and all shares, interests, rights to purchase, warrants, options, participations or other equivalents of or interests in (however designated) equity of such Person, including any Preferred Stock, but excluding any debt securities convertible into such equity.

“Capitalized Lease Obligations” means an obligation that is required to be classified and accounted for as a capitalized lease for financial reporting purposes in accordance with GAAP, and the amount of Indebtedness represented by such obligation will be the capitalized amount of such obligation at the time any determination thereof is to be made as determined in accordance with GAAP, and the Stated Maturity thereof will be the date of the last payment of rent or any other amount due under such lease prior to the first date such lease may be terminated without penalty.

“Cash Equivalents” means:

(1)    securities issued or directly and fully guaranteed or insured by the United States Government or any agency or instrumentality thereof (provided that the full faith and credit of the United States is pledged in support thereof), having maturities of not more than one year from the date of acquisition;

(2)    marketable general obligations issued by any state of the United States of America or any political subdivision of any such state or any public instrumentality thereof maturing within one year from the date of acquisition thereof and, at the time of acquisition thereof, having a credit rating of “A” or better from either Standard & Poor’s Ratings Group or Moody’s Investors Service, Inc.;

128

(3)    certificates of deposit, time deposits, eurodollar time deposits, overnight bank deposits or bankers’ acceptances having maturities of not more than one year from the date of acquisition thereof issued by any commercial bank the long-term debt of which is rated at the time of acquisition thereof at least “A” or the equivalent thereof by Standard & Poor’s Ratings Group or “A” or the equivalent thereof by Moody’s Investors Service, Inc., and having combined capital and surplus in excess of $500.0 million;

(4)    repurchase obligations with a term of not more than seven days for underlying securities of the types described in clauses (1), (2) and (3) entered into with any bank meeting the qualifications specified in clause (3) above;

(5)    commercial paper rated at the time of acquisition thereof at least “A-2” or the equivalent thereof by Standard & Poor’s Ratings Group or “P-2” or the equivalent thereof by Moody’s Investors Service, Inc., or carrying an equivalent rating by a nationally recognized rating agency, if both of the two named rating agencies cease publishing ratings of investments, and in either case maturing within one year after the date of acquisition thereof; and

(6)    interests in any investment company or money market fund which invests solely in instruments of the type specified in clauses (1) through (5) above.

“Change of Control” means:

(1)    any “person” or “group” of related persons (as such terms are used in Sections 13(d) and 14(d) of the Exchange Act) other than Permitted Holders, is or becomes the beneficial owner (as defined in Rules 13d-3 and 13d-5 under the Exchange Act, except that such person or group shall be deemed to have “beneficial ownership” of all shares that any such person or group has the right to acquire, whether such right is exercisable immediately or only after the passage of time), directly or indirectly, of more than 40% of the total voting power of the Voting Stock of the Company (or its successor by merger, consolidation or purchase of all or substantially all of its assets) (for the purposes of this clause, such person or group shall be deemed to beneficially own any Voting Stock of the Company held by an entity, if such person or group “beneficially owns” (as defined above), directly or indirectly, more than 40% of the voting power of the Voting Stock of such entity);

(2)    the first day on which a majority of the members of the Board of Directors of the Company are not Continuing Directors;

(3)    the sale, lease, transfer, conveyance or other disposition (other than by way of merger or consolidation), in one or a series of related transactions, of all or substantially all of the assets of the Company and its Restricted Subsidiaries taken as a whole to any “person” (as such term is used in Sections 13(d) and 14(d) of the Exchange Act);

(4)    the adoption of a plan or proposal for the liquidation or dissolution of the Company or, for so long as the Company is a partnership, the general partner of the Company; or

(5)    for so long as the Company is a partnership, such time as Plains Resources Inc. or any of its Subsidiaries ceases to own, directly or indirectly, the general partner of the Company, or Plains Resources Inc. or its Subsidiaries, or their respective officers, employees or agents cease to serve as the only general partners of the Company.

Notwithstanding the foregoing, the conversion of the Company into a corporation will not be a Change of Control unless clause (1) above is applicable.

“Code” means the Internal Revenue Code of 1986, as amended.

“Commodity Agreements” means, in respect of any Person, any forward contract, commodity swap agreement, commodity option agreement or other similar agreement or arrangement designed to protect such Person against fluctuation in commodity prices.

129

“Consolidated Coverage Ratio” means as of any date of determination, with respect to any Person, the ratio of (x) the aggregate amount of Consolidated EBITDA of such Person for the period of the most recent four consecutive fiscal quarters ending prior to the date of such determination for which financial statements are in existence to (y) Consolidated Interest Expense for such four fiscal quarters, provided, however, that:

(1)    if the Company or any Restricted Subsidiary:

(a)    has Incurred any Indebtedness since the beginning of such period that remains outstanding on such date of determination or if the transaction giving rise to the need to calculate the Consolidated Coverage Ratio is an Incurrence of Indebtedness, Consolidated EBITDA and Consolidated Interest Expense (taking into account any Interest Rate Agreements applicable to such Indebtedness) for such period will be calculated after giving effect on a pro forma basis to such Indebtedness as if such Indebtedness had been Incurred on the first day of such period (except that in making such computation, the amount of Indebtedness under any revolving credit facility outstanding on the date of such calculation will be computed based on (i) the average daily balance of such Indebtedness during such four fiscal quarters or such shorter period for which such facility was outstanding or (ii) if such facility was created after the end of such four fiscal quarters, the average daily balance of such Indebtedness during the period from the date of creation of such facility to the date of such calculation) and the discharge of any other Indebtedness repaid, repurchased, defeased or otherwise discharged with the proceeds of such new Indebtedness as if such discharge had occurred on the first day of such period; or

(b)    has repaid, repurchased, defeased or otherwise discharged any Indebtedness since the beginning of the period that is no longer outstanding on such date of determination or if the transaction giving rise to the need to calculate the Consolidated Coverage Ratio involves a discharge of Indebtedness (in each case other than Indebtedness incurred under any revolving credit facility unless such Indebtedness has been permanently repaid and the related commitment terminated), Consolidated EBITDA and Consolidated Interest Expense for such period will be calculated after giving effect on a pro forma basis to such discharge of such Indebtedness, including with the proceeds of such new Indebtedness, as if such discharge had occurred on the first day of such period;

(2)    if since the beginning of such period the Company or any Restricted Subsidiary will have made any Asset Disposition or if the transaction giving rise to the need to calculate the Consolidated Coverage Ratio is an Asset Disposition:

(a)    the Consolidated EBITDA for such period will be reduced by an amount equal to the Consolidated EBITDA (if positive) directly attributable to the assets which are the subject of such Asset Disposition for such period or increased by an amount equal to the Consolidated EBITDA (if negative) directly attributable thereto for such period; and

(b)    Consolidated Interest Expense for such period will be reduced by an amount equal to the Consolidated Interest Expense directly attributable to any Indebtedness of the Company or any Restricted Subsidiary repaid, repurchased, defeased or otherwise discharged with respect to the Company and its continuing Restricted Subsidiaries in connection with such Asset Disposition for such period (or, if the Capital Stock of any Restricted Subsidiary is sold, the Consolidated Interest Expense for such period directly attributable to the Indebtedness of such Restricted Subsidiary to the extent the Company and its continuing Restricted Subsidiaries are no longer liable for such Indebtedness after such sale);

(3)    if since the beginning of such period the Company or any Restricted Subsidiary (by merger or otherwise) will have made an Investment in any Restricted Subsidiary (or any Person which becomes a Restricted Subsidiary or is merged with or into the Company) or an acquisition of assets, including any acquisition of assets occurring in connection with a transaction causing a

130

calculation to be made hereunder, including a single asset or all or substantially all of an operating unit, division or line of business, Consolidated EBITDA and Consolidated Interest Expense for such period will be calculated after giving pro forma effect thereto (including the Incurrence of any Indebtedness) as if such Investment or acquisition occurred on the first day of such period; and

(4)    if since the beginning of such period any Person (that subsequently became a Restricted Subsidiary or was merged with or into the Company or any Restricted Subsidiary since the beginning of such period) will have made any Asset Disposition or any Investment or acquisition of assets that would have required an adjustment pursuant to clause (2) or (3) above if made by the Company or a Restricted Subsidiary during such period, Consolidated EBITDA and Consolidated Interest Expense for such period will be calculated after giving pro forma effect thereto as if such Asset Disposition or Investment or acquisition of assets occurred on the first day of such period.

For purposes of this definition, whenever pro forma effect is to be given to any calculation under this definition, the pro forma calculations will be determined in good faith by a responsible financial or accounting officer of the Company (including pro forma expense and cost reductions calculated on a basis consistent with Regulation S-X under the Securities Act). If any Indebtedness bears a floating rate of interest and is being given pro forma effect, the interest expense on such Indebtedness will be calculated as if the rate in effect on the date of determination had been the applicable rate for the entire period (taking into account any Interest Rate Agreement applicable to such Indebtedness if such Interest Rate Agreement has a remaining term in excess of 12 months).

“Consolidated EBITDA” for any period means, without duplication, the Consolidated Net Income for such period, plus the following to the extent deducted in calculating such Consolidated Net Income:

(1)    Consolidated Interest Expense less the consolidated interest expense of such Person and its Restricted Subsidiaries that was capitalized and not deducted during such period;

(2)    Consolidated Income Taxes;

(3)    consolidated depreciation expense;

(4)    consolidated amortization of intangibles;

(5)    exploration and abandonment expense (if applicable); and

(6)    other non-cash charges reducing Consolidated Net Income (excluding any such non-cash charge to the extent it represents an accrual of or reserve for cash charges in any future period or amortization of a prepaid cash expense that was paid in a prior period not included in the prior period calculation),

and less, to the extent included in calculating such Consolidated Net Income and in excess of any costs or expenses attributable thereto and deducted in calculating such Consolidated Net Income, the sum of (x) the amount of deferred revenues that are amortized during such period and are attributable to reserves that are subject to Volumetric Production Payments, and (y) amounts recorded in accordance with GAAP as repayments of principal and interest pursuant to Dollar-Denominated Production Payments. Notwithstanding the preceding sentence, clauses (2) through (5) relating to amounts of a Restricted Subsidiary of a Person will be added to Consolidated Net Income to compute Consolidated EBITDA of such Person only to the extent (and in the same proportion) that the net income (loss) of such Restricted Subsidiary was included in calculating the Consolidated Net Income of such Person and, to the extent the amounts set forth in clauses (2) through (5) are in excess of those necessary to offset a net loss of such Restricted Subsidiary or if such Restricted Subsidiary has net income for such period included in Consolidated Net Income, only if a corresponding amount would be permitted at the date of determination to be dividended to the Company by such Restricted Subsidiary without prior approval (that has not been obtained), pursuant to the terms of its charter and all agreements, instruments, judgments, decrees, orders, statutes, rules and governmental regulations applicable to that Restricted Subsidiary or its stockholders.

131

“Consolidated Income Taxes” means, with respect to any Person for any period, taxes imposed upon such Person or other payments required to be made by such Person by any governmental authority which taxes or other payments are calculated by reference to the income or profits of such Person or such Person and its Restricted Subsidiaries (to the extent such income or profits were included in computing Consolidated Net Income for such period), regardless of whether such taxes or payments are required to be remitted to any governmental authority.

“Consolidated Interest Expense” means, for any period, the total interest expense of the Company and its consolidated Restricted Subsidiaries, whether paid or accrued (except to the extent accrued in a prior period), plus, to the extent not included in such interest expense:

(1)    interest expense attributable to Capitalized Lease Obligations and the interest portion of rent expense associated with Attributable Indebtedness in respect of the relevant lease giving rise thereto, determined as if such lease were a capitalized lease in accordance with GAAP and the interest component of any deferred payment obligations;

(2)    amortization of debt discount and debt issuance cost;

(3)    non-cash interest expense;

(4)    commissions, discounts and other fees and charges owed with respect to letters of credit and bankers’ acceptance financing;

(5)    the interest expense on Indebtedness of another Person that is Guaranteed by such Person or one of its Restricted Subsidiaries or secured by a Lien on assets of such Person or one of its Restricted Subsidiaries;

(6)    net payments pursuant to Hedging Obligations (including amortization of fees);

(7)    the consolidated interest expense of such Person and its Restricted Subsidiaries that was capitalized during such period;

(8)    the product of (a) all dividends paid or payable in cash, Cash Equivalents or Indebtedness or accrued during such period on any series of Disqualified Stock of such Person or on Preferred Stock of its Restricted Subsidiaries payable to a party other than the Company or a Restricted Subsidiary, times (b) a fraction, the numerator of which is one and the denominator of which is one minus the then current combined federal, state, provincial and local statutory tax rate of such Person, expressed as a decimal, in each case, on a consolidated basis and in accordance with GAAP; and

(9)    the cash contributions to any employee stock ownership plan or similar trust to the extent such contributions are used by such plan or trust to pay interest or fees to any Person (other than the Company) in connection with Indebtedness Incurred by such plan or trust; provided, however, that there will be excluded therefrom any such interest expense of any Unrestricted Subsidiary to the extent the related Indebtedness is not Guaranteed or paid by the Company or any Restricted Subsidiary.

For purposes of the foregoing, total interest expense will be determined after giving effect to any net payments made or received by the Company and its Subsidiaries with respect to Interest Rate Agreements; provided, however, that “Consolidated Interest Expense” shall not include (a) any Consolidated Interest Expense with respect to any Production Payments and Reserve Sales, (b) to the extent included in total interest expense, write-off of deferred financing costs of such Person or (c) accretion of interest charges on future plugging and abandonment obligations, future retirement benefits and other obligations that do not constitute Indebtedness.

132

“Consolidated Net Income” means, for any period, the net income (loss) of the Company and its consolidated Restricted Subsidiaries determined in accordance with GAAP; provided, however, that there will not be included in such Consolidated Net Income:

(1)    any net income (loss) of any Person if such Person is not a Restricted Subsidiary, except that:

(a)    subject to the limitations contained in clauses (4), (5) and (6) below, the Company’s equity in the net income of any such Person for such period will be included in such Consolidated Net Income up to the aggregate amount of cash actually distributed by such Person during such period to the Company or a Restricted Subsidiary as a dividend or other distribution (subject, in the case of a dividend or other distribution to a Restricted Subsidiary, to the limitations contained in clause (3) below); and

(b)    the Company’s equity in a net loss of any such Person (other than an Unrestricted Subsidiary) for such period will be included in determining such Consolidated Net Income to the extent such loss has been funded with cash from the Company or a Restricted Subsidiary;

(2)    any net income (loss) of any Person acquired by the Company or a Subsidiary in a pooling of interests transaction for any period prior to the date of such acquisition;

(3)    any net income (but not loss) of any Restricted Subsidiary if such Subsidiary is subject to restrictions, directly or indirectly, on the payment of dividends or the making of distributions by such Restricted Subsidiary, directly or indirectly, to the Company, except that:

(a)    subject to the limitations contained in clauses (4), (5) and (6) below, the Company’s equity in the net income of any such Restricted Subsidiary for such period will be included in such Consolidated Net Income up to the aggregate amount of cash that could have been distributed by such Restricted Subsidiary during such period to the Company or another Restricted Subsidiary as a dividend (subject, in the case of a dividend to another Restricted Subsidiary, to the limitation contained in this clause); and

(b)    the Company’s equity in a net loss of any such Restricted Subsidiary for such period will be included in determining such Consolidated Net Income;

(4)    any gain (loss) realized upon the sale or other disposition of any property, plant or equipment of the Company or its consolidated Restricted Subsidiaries (including pursuant to any Sale/Leaseback Transaction) which is not sold or otherwise disposed of in the ordinary course of business and any gain (loss) realized upon the sale or other disposition of any Capital Stock of any Person;

(5)    any extraordinary gain or loss;

(6)    the cumulative effect of a change in accounting principles;

(7)    any asset impairment writedowns on Oil and Gas Properties under GAAP or SEC guidelines; and

(8)    any unrealized non-cash gains or losses on charges in respect of Hedging Obligations (including those resulting from the application of SFAS 133).

“Consolidated Net Worth” of any Person means the stockholders’ equity of such Person and its Subsidiaries, as determined on a consolidated basis in accordance with GAAP, less (to the extent included in stockholders’ equity) amounts attributable to Disqualified Stock of such Person or its Subsidiaries.

133

“Continuing Directors” means, as of any date of determination after the Company is a corporation, any member of the Board of Directors of the Company who:

(1)    was a member of such Board of Directors on the date of conversion of the Company to a corporation; or

(2)    was nominated for election or elected to such Board of Directors with the approval of a majority of the Continuing Directors who were members of such Board at the time of such nomination or election.

“Currency Agreement” means in respect of a Person any foreign exchange contract, currency swap agreement or other similar agreement as to which such Person is a party or a beneficiary.

“Default” means any event which is, or after notice or passage of time or both would be, an Event of Default.

“Designated Senior Indebtedness” means (1) Bank Indebtedness (to the extent such Bank Indebtedness constitutes Senior Indebtedness) and (2) any other Senior Indebtedness which, at the date of determination, has an aggregate principal amount outstanding of, or under which, at the date of determination, the holders thereof are committed to lend up to, at least $25.0 million and is specifically designated in the instrument evidencing or governing such Senior Indebtedness as “Designated Senior Indebtedness” for purposes of the Indenture.

“Disqualified Stock” means, with respect to any Person, any Capital Stock of such Person which by its terms (or by the terms of any security into which it is convertible or for which it is exchangeable) or upon the happening of any event:

(1)    matures or is mandatorily redeemable pursuant to a sinking fund obligation or otherwise;

(2)    is convertible or exchangeable for Indebtedness or Disqualified Stock (excluding Capital Stock which is convertible or exchangeable solely at the option of the Company or a Restricted Subsidiary); or

(3)    is redeemable at the option of the holder thereof, in whole or in part,

in each case on or prior to the date that is 91 days after the date (a) on which the Notes mature or (b) on which there are no Notes outstanding; provided that only the portion of Capital Stock which so matures or is mandatorily redeemable, is so convertible or exchangeable or is so redeemable at the option of the holder thereof prior to such date will be deemed to be Disqualified Stock; provided further that any Capital Stock that would constitute Disqualified Stock solely because the holders thereof have the right to require the Company to repurchase such Capital Stock upon the occurrence of a change of control or asset sale (each defined in a substantially identical manner to the corresponding definitions in the Indenture) shall not constitute Disqualified Stock if the terms of such Capital Stock (and all such securities into which it is convertible or for which it is ratable or exchangeable) provide that the Company may not repurchase or redeem any such Capital Stock (and all such securities into which it is convertible or for which it is ratable or exchangeable) pursuant to such provision prior to compliance by the Company with the provisions of the Indenture described under the captions “Change of Control” and “Limitation on Sales of Assets and Subsidiary Stock” and such repurchase or redemption complies with “Certain Covenants—Restricted Payments.”

“Dollar-Denominated Production Payments” means production payment obligations recorded as liabilities in accordance with GAAP, together with all undertakings and obligations in connection therewith.

“Equity Offering” means an offering for cash by the Company of its common Capital Stock, or options, warrants or rights with respect to its common Capital Stock.

134

“Foreign Subsidiary” means any Restricted Subsidiary that is not organized under the laws of the United States of America or any state thereof or the District of Columbia.

“GAAP” means generally accepted accounting principles in the United States of America as in effect as of the date of the Indenture, including those set forth in the opinions and pronouncements of the Accounting Principles Board of the American Institute of Certified Public Accountants and statements and pronouncements of the Financial Accounting Standards Board or in such other statements by such other entity as approved by a significant segment of the accounting profession. All ratios and computations based on GAAP contained in the Indenture will be computed in conformity with GAAP.

“Guarantee” means any obligation, contingent or otherwise, of any Person directly or indirectly guaranteeing any Indebtedness of any other Person and any obligation, direct or indirect, contingent or otherwise, of such Person:

(1)    to purchase or pay (or advance or supply funds for the purchase or payment of) such Indebtedness of such other Person (whether arising by virtue of partnership arrangements, or by agreement to keep-well, to purchase assets, goods, securities or services, to take-or-pay, or to maintain financial statement conditions or otherwise); or

(2)    entered into for purposes of assuring in any other manner the obligee of such Indebtedness of the payment thereof or to protect such obligee against loss in respect thereof (in whole or in part);

provided, however, that the term “Guarantee” will not include endorsements for collection or deposit in the ordinary course of business. The term “Guarantee” used as a verb has a corresponding meaning.

“Guarantor Senior Indebtedness” means, with respect to a Subsidiary Guarantor, the following obligations, whether outstanding on the date of the Indenture or thereafter issued, without duplication:

(1)    any Guarantee of the Bank Indebtedness by such Subsidiary Guarantor and all other Guarantees by such Subsidiary Guarantor of Senior Indebtedness of the Issuers or Guarantor Senior Indebtedness of any other Subsidiary Guarantor; and

(2)    all obligations consisting of principal of and premium, if any, accrued and unpaid interest on, and fees and other amounts relating to, the Bank Indebtedness and all other Indebtedness of the Subsidiary Guarantor. Guarantor Senior Indebtedness includes interest accruing on or after the filing of any petition in bankruptcy or for reorganization relating to the Subsidiary Guarantor regardless of whether post-filing interest is allowed in such proceeding.

Notwithstanding anything to the contrary in the preceding paragraph, Guarantor Senior Indebtedness will not include:

(1)    any Indebtedness which, in the instrument creating or evidencing the same or pursuant to which the same is outstanding, it is provided that the obligations in respect of such Indebtedness are not superior in right of, or are subordinate to, payment of the Notes and the Subsidiary Guarantee;

(2)    any obligations of such Subsidiary Guarantor to another Subsidiary or the Company;

(3)    any liability for Federal, state, foreign, local or other taxes owed or owing by such Subsidiary Guarantor;

(4)    any accounts payable or other liability to trade creditors arising in the ordinary course of business (including Guarantees thereof or instruments evidencing such liabilities);

(5)    any Indebtedness, Guarantee or obligation of such Subsidiary Guarantor that is expressly subordinate or junior in right of payment to any other Indebtedness, Guarantee or obligation of

135

such Subsidiary Guarantor, including, without limitation, any Guarantor Senior Subordinated Indebtedness and Guarantor Subordinated Obligations of such Guarantor; or

(6)    any Capital Stock.

“Guarantor Senior Subordinated Indebtedness” means, with respect to a Subsidiary Guarantor, the obligations of such Subsidiary Guarantor under the Subsidiary Guarantee and any other Indebtedness of such Subsidiary Guarantor that specifically provides that such Indebtedness is to rank equally in right of payment with the obligations of such Subsidiary Guarantor under its Subsidiary Guarantee and is not expressly subordinated by its terms in right of payment to any Indebtedness of such Subsidiary Guarantor which is not Guarantor Senior Indebtedness of such Subsidiary Guarantor.

“Guarantor Subordinated Obligation” means any Indebtedness of a Subsidiary Guarantor (whether outstanding on the Issue Date or thereafter Incurred) which is subordinate or junior in right of payment to the Subsidiary Guarantee of such Subsidiary Guarantor pursuant to a written agreement.

“Hedging Obligations” of any Person means the obligations of such Person pursuant to any Interest Rate Agreement or Currency Agreement.

“Hydrocarbons” means oil, gas, casinghead gas, drip gasoline, natural gasoline, condensate, distillate, liquid hydrocarbons, gaseous hydrocarbons and all constituents, elements or compounds thereof and products refined or processed therefrom.

“Incur” means issue, create, assume, Guarantee, incur or otherwise become liable for; provided, however, that any Indebtedness or Capital Stock of a Person existing at the time such person becomes a Restricted Subsidiary (whether by merger, consolidation, acquisition or otherwise) will be deemed to be incurred by such Restricted Subsidiary at the time it becomes a Restricted Subsidiary; and the terms “Incurred” and “Incurrence” have meanings correlative to the foregoing.

“Indebtedness” means, with respect to any Person on any date of determination (without duplication):

(1)    the principal of and premium (if any) in respect of indebtedness of such Person for borrowed money;

(2)    the principal of and premium (if any) in respect of obligations of such Person evidenced by bonds, debentures, notes or other similar instruments;

(3)    the principal component of all obligations of such Person in respect of letters of credit, bankers’ acceptances or other similar instruments (including reimbursement obligations with respect thereto except to the extent such reimbursement obligation relates to a trade payable and such obligation is satisfied within 30 days of Incurrence);

(4)    the principal component of all obligations of such Person to pay the deferred and unpaid purchase price of property (except trade payables), which purchase price is due more than nine months after the date of placing such property in service or taking delivery and title thereto;

(5)    Capitalized Lease Obligations and all Attributable Indebtedness of such Person;

(6)    the principal component or liquidation preference of all obligations of such Person with respect to the redemption, repayment or other repurchase of any Disqualified Stock or, with respect to any Subsidiary, any Preferred Stock (but excluding, in each case, any accrued dividends);

(7)    the principal component of all Indebtedness of other Persons secured by a Lien on any asset of such Person, whether or not such Indebtedness is assumed by such Person; provided, however, that the amount of such Indebtedness will be the lesser of (a) the fair market value of

136

such asset at such date of determination and (b) the amount of such Indebtedness of such other Persons;

(8)    the principal component of Indebtedness of other Persons to the extent Guaranteed by such Person; and

(9)    to the extent not otherwise included in this definition, net obligations of such Person under Currency Agreements and Interest Rate Agreements (the amount of any such obligations to be equal at any time to the termination value of such agreement or arrangement giving rise to such obligation that would be payable by such Person at such time).

The amount of Indebtedness of any Person at any date will be the outstanding balance at such date of all unconditional obligations as described above and the maximum liability, upon the occurrence of the contingency giving rise to the obligation, of any contingent obligations at such date.

In addition, “Indebtedness” of any Person shall include Indebtedness described in the preceding paragraph that would not appear as a liability on the balance sheet of such Person if:

(1)    such Indebtedness is the obligation of a partnership or joint venture that is not a Restricted Subsidiary (a “Joint Venture”);

(2)    such Person or a Restricted Subsidiary of such Person is a general partner of the Joint Venture (a “General Partner”); and

(3)    there is recourse, by contract or operation of law, with respect to the payment of such Indebtedness to property or assets of such Person or a Restricted Subsidiary of such Person; and then such Indebtedness shall be included in an amount not to exceed:

(a)    the lesser of (i) the net assets of the General Partner and (ii) the amount of such obligations to the extent that there is recourse, by contract or operation of law, to the property or assets of such Person or a Restricted Subsidiary of such Person; or

(b)    if less than the amount determined pursuant to clause (a) immediately above, the actual amount of such Indebtedness that is recourse to such Person or a Restricted Subsidiary of such Person, if the Indebtedness is evidenced by a writing and is for a determinable amount and the related interest expense shall be included in Consolidated Interest Expense to the extent actually paid by the Company or its Restricted Subsidiaries.

Notwithstanding the preceding, Indebtedness shall not include (a) accounts payable arising in the ordinary course of business, (b) any obligations in respect of prepayments for gas or oil production or gas or oil imbalances, and (c) Production Payments and Reserve Sales.

“Interest Rate Agreement” means with respect to any Person any interest rate protection agreement, interest rate future agreement, interest rate option agreement, interest rate swap agreement, interest rate cap agreement, interest rate collar agreement, interest rate hedge agreement or other similar agreement or arrangement as to which such Person is party or a beneficiary.

“Investment” means, with respect to any Person, all investments by such Person in other Persons (including Affiliates) in the form of any direct or indirect advance, loan (other than advances to customers in the ordinary course of business) or other extension of credit (including by way of Guarantee or similar arrangement, but excluding any debt or extension of credit represented by a bank deposit other than a time deposit) or capital contribution to (by means of any transfer of cash or other property to others or any payment for property or services for the account or use of others), or any purchase or acquisition of Capital Stock, Indebtedness or other similar instruments issued by, such

137

Person and all other items that are or would be classified as investments on a balance sheet prepared in accordance with GAAP; provided that:

(1)    Hedging Obligations entered into in the ordinary course of business and in compliance with the Indenture;

(2)    endorsements of negotiable instruments and documents in the ordinary course of business; and

(3)    an acquisition of assets, Capital Stock or other securities by the Company or a Subsidiary for consideration consisting exclusively of common equity securities of the Company,

shall in each case not be deemed to be an Investment.

For purposes of “Certain Covenants—Limitation on Restricted Payments,”

(1)    “Investment” will include the portion (proportionate to the Company’s equity interest in a Restricted Subsidiary to be designated as an Unrestricted Subsidiary) of the fair market value of the net assets of such Restricted Subsidiary of the Company at the time that such Restricted Subsidiary is designated an Unrestricted Subsidiary; provided, however, that upon a redesignation of such Subsidiary as a Restricted Subsidiary, the Company will be deemed to continue to have a permanent “Investment” in an Unrestricted Subsidiary in an amount (if positive) equal to (a) the Company’s “Investment” in such Subsidiary at the time of such redesignation less (b) the portion (proportionate to the Company’s equity interest in such Subsidiary) of the fair market value of the net assets (as conclusively determined by the Board of Directors of the Company in good faith) of such Subsidiary at the time that such Subsidiary is so re-designated a Restricted Subsidiary; and

(2)    any property transferred to or from an Unrestricted Subsidiary will be valued at its fair market value at the time of such transfer, in each case as determined in good faith by the Board of Directors of the Company.

If the Company or any Restricted Subsidiary of the Company sells or otherwise disposes of any Voting Stock of any Restricted Subsidiary of the Company such that, after giving effect to any such sale or disposition, such entity is no longer a Subsidiary of the Company, the Company shall be deemed to have made an Investment on the date of any such sale or disposition equal to the fair market value (as conclusively determined by the Board of Directors of the Company in good faith) of the Capital Stock of such Subsidiary not sold or disposed of.

“Investment Grade Rating” means a rating equal to or higher than Baa3 (or the equivalent) by Moody’s Investors Service, Inc. or BBB- (or the equivalent) by Standard & Poor’s Ratings Group.

“Issue Date” means the date on which the Initial Notes are originally issued.

“Junior Securities” means securities that are subordinated to the Senior Indebtedness at least to the same extent as the Notes.

“Lien” means any mortgage, pledge, security interest, encumbrance, lien or charge of any kind (including any conditional sale or other title retention agreement or lease in the nature thereof).

“Minority Interest” means the percentage interest represented by any shares of stock of any class of Capital Stock of a Restricted Subsidiary of the Company that are not owned by the Company or a Restricted Subsidiary of the Company.

“Net Available Cash” from an Asset Disposition means cash payments received (including any cash payments received by way of deferred payment of principal pursuant to a note or installment receivable or otherwise, but only as and when received, but excluding any other consideration received

138

in the form of assumption by the acquiring Person of Indebtedness or other obligations relating to the properties or assets that are the subject of such Asset Disposition or received in any other noncash form) therefrom, in each case net of:

(1)    all legal, accounting, investment banking, title and recording tax expenses, commissions and other fees and expenses incurred, and all Federal, state, provincial, foreign and local taxes required to be paid or accrued as a liability under GAAP (after taking into account any available tax credits or deductions and any tax sharing agreements), as a consequence of such Asset Disposition;

(2)    all payments made on any Indebtedness which is secured by any assets subject to such Asset Disposition, in accordance with the terms of any Lien upon such assets, or which must by its terms, or in order to obtain a necessary consent to such Asset Disposition, or by applicable law be repaid out of the proceeds from such Asset Disposition;

(3)    all distributions and other payments required to be made to minority interest holders in Subsidiaries or joint ventures as a result of such Asset Disposition; and

(4)    the deduction of appropriate amounts to be provided by the seller as a reserve, in accordance with GAAP, against any liabilities associated with the assets disposed of in such Asset Disposition and retained by the Company or any Restricted Subsidiary after such Asset Disposition.

“Net Cash Proceeds,” with respect to any issuance or sale of Capital Stock, means the cash proceeds of such issuance or sale net of attorneys’ fees, accountants’ fees, underwriters’ or placement agents’ fees, listing fees, discounts or commissions and brokerage, consultant and other fees and charges actually incurred in connection with such issuance or sale and net of taxes paid or payable as a result of such issuance or sale (after taking into account any available tax credit or deductions and any tax sharing arrangements).

“Net Working Capital” means (a) all current assets of the Company and its Restricted Subsidiaries except current assets from commodity price risk management activities arising in the ordinary course of business, less (b) all current liabilities of the Company and its Restricted Subsidiaries, except current liabilities included in Indebtedness and any current liabilities from commodity price risk management activities arising in the ordinary course of business, in each case as set forth in the consolidated financial statements of the Company prepared in accordance with GAAP.

“Non-Recourse Debt” means Indebtedness:

(1)    as to which neither the Company nor any Restricted Subsidiary (a) provides any Guarantee or credit support of any kind (including any undertaking, guarantee, indemnity, agreement or instrument that would constitute Indebtedness) or (b) is directly or indirectly liable (as a guarantor or otherwise);

(2)    no default with respect to which (including any rights that the holders thereof may have to take enforcement action against an Unrestricted Subsidiary) would permit (upon notice, lapse of time or both) any holder of any other Indebtedness of the Company or any Restricted Subsidiary to declare a default under such other Indebtedness or cause the payment thereof to be accelerated or payable prior to its stated maturity; and

(3)    the explicit terms of which provide there is no recourse against any of the assets of the Company or its Restricted Subsidiaries.

“Officer” means the Chairman of the Board, the President, any Vice President, the Treasurer or the Secretary of an Issuer or, so long as the Company is a limited partnership, of its general partner.

139

“Officers’ Certificate” means a certificate signed by two Officers or by an Officer and either an Assistant Treasurer or an Assistant Secretary of an Issuer or, so long as the Company is a limited partnership, of its general partner.

“Oil and Gas Properties” means all Properties, including equity or other ownership interests therein, owned by such Person which contain “proved oil and gas reserves” as defined in Rule 4-10 of Regulation S-X of the Securities Act.

“Opinion of Counsel” means a written opinion from legal counsel who is acceptable to the Trustee. The counsel may be an employee of or counsel to the Company or the Trustee.

“PAA” means Plains All American Pipeline, L.P., a Delaware limited partnership.

“Permitted Acquisition Indebtedness” means Indebtedness of the Company or any Restricted Subsidiary to the extent such Indebtedness is incurred to finance the acquisition of Oil and Gas Properties (and development costs related thereto) and does not exceed the principal amount of $50.0 million with respect to any such acquisition transaction or series of related acquisition transactions if on the date of the incurrence (i) (A) the Adjusted Consolidated Net Tangible Assets acquired are equal to or greater than 200% of the Indebtedness incurred, and (B) the Adjusted Consolidated Net Tangible Assets of Company (after giving effect to such acquisition) are equal to or greater than 125% of the consolidated Indebtedness of the Company and its Restricted Subsidiaries or (ii) (A) the Property Net Revenue Coverage Ratio would have been equal to or greater than 2.5 to 1.0, (B) the Adjusted Consolidated Net Tangible Assets acquired are equal to or greater than 150% of the Indebtedness incurred, and (C) the Adjusted Consolidated Net Tangible Assets of the Company (after giving effect to such acquisition) are equal to or greater than 125% of the consolidated Indebtedness of the Company and its Restricted Subsidiaries.

“Permitted Business Investment” means any investment made in the ordinary course of, and of a nature that is or shall have become customary in, the Related Business including investments or expenditures for actively exploiting, exploring for, acquiring, developing, producing, processing, gathering, marketing or transporting oil and gas through agreements, transactions, interests or arrangements which permit one to share risks or costs, comply with regulatory requirements regarding local ownership or satisfy other objectives customarily achieved through the conduct of the Related Business jointly with third parties, including (i) ownership interests in oil and gas properties, processing facilities, gathering systems, pipelines or ancillary real property interests and (ii) Investments in the form of or pursuant to operating agreements, processing agreements, farm-in agreements, farm-out agreements, development agreements, area of mutual interest agreements, unitization agreements, pooling agreements, joint bidding agreements, service contracts, joint venture agreements, partnership agreements (whether general or limited), subscription agreements, stock purchase agreements and other similar agreements (including for limited liability companies) with third parties, excluding, however, Investments in corporations other than Restricted Subsidiaries.

“Permitted Holders” means (a) prior to the Spin-off, Plains Resources Inc. and its Subsidiaries or (b) (i) James C. Flores and his spouse and lineal descendants, their respective estates or legal representatives, (ii) trusts created for the benefit of such Persons and (iii) entities 80% or more of the Voting Stock of which is directly or indirectly owned by any of the preceding Persons.

“Permitted Investment” means an Investment by the Company or any Restricted Subsidiary in:

(1)    a Restricted Subsidiary or a Person which will, upon the making of such Investment, become a Restricted Subsidiary; provided, however, that the primary business of such Restricted Subsidiary is a Related Business;

140

(2)    another Person if as a result of such Investment such other Person is merged or consolidated with or into, or transfers or conveys all or substantially all its assets to, the Company or a Restricted Subsidiary; provided, however, that such Person’s primary business is a Related Business;

(3)    cash and Cash Equivalents;

(4)    receivables owing to the Company or any Restricted Subsidiary created or acquired in the ordinary course of business and payable or dischargeable in accordance with customary trade terms; provided, however, that such trade terms may include such concessionary trade terms as the Company or any such Restricted Subsidiary deems reasonable under the circumstances;

(5)    payroll, travel and similar advances to cover matters that are expected at the time of such advances ultimately to be treated as expenses for accounting purposes and that are made in the ordinary course of business;

(6)    loans or advances to employees made in the ordinary course of business consistent with past practices of the Company or such Restricted Subsidiary;

(7)    stock, obligations or securities received in settlement of debts created in the ordinary course of business and owing to the Company or any Restricted Subsidiary or in satisfaction of judgments or pursuant to any plan of reorganization or similar arrangement upon the bankruptcy or insolvency of a debtor;

(8)    Investments made as a result of the receipt of non-cash consideration from an Asset Disposition that was made pursuant to and in compliance with “Certain Covenants—Limitation on Sales of Assets and Subsidiary Stock;”

(9)    Investments in existence on the Issue Date;

(10)    Currency Agreements, Interest Rate Agreements and related Hedging Obligations, which transactions or obligations are Incurred in compliance with “Certain Covenants—Limitation on Indebtedness;”

(11)    Investments by the Company or any of its Restricted Subsidiaries, together with all other Investments pursuant to this clause (11), in an aggregate amount at the time of such Investment not to exceed $20.0 million outstanding at any one time;

(12)    Guarantees issued in accordance with “Certain Covenants—Limitations on Indebtedness;”

(13)    prepaid expenses, lease, utilities, workers’ compensation performance and similar deposits made in the ordinary course of business;

(14)    Investments owned by a Person if and when it is acquired by the Company and becomes a Restricted Subsidiary; provided, however, that such Investments are not made in contemplation of such acquisition;

(15)    Permitted Business Investments; and

(16)    Investments in any units of any oil and gas royalty trust.

“Permitted Liens” means, with respect to any Person:

(1)    Liens securing Indebtedness and other obligations of the Company under the Senior Credit Agreement, Interest Rate Agreements, Currency Agreements and other Senior Indebtedness and liens on assets of Restricted Subsidiaries securing Guarantees of Indebtedness and other obligations of the Company under the Senior Credit Agreement and other Senior Indebtedness;

(2)    pledges or deposits by such Person under workmen’s compensation laws, unemployment insurance laws or similar legislation, or good faith deposits in connection with bids, tenders,

141

contracts (other than for the payment of Indebtedness) or leases to which such Person is a party, or deposits to secure public or statutory obligations of such Person or deposits or cash or United States government bonds to secure surety or appeal bonds to which such Person is a party, or deposits as security for contested taxes or import or customs duties or for the payment of rent, in each case Incurred in the ordinary course of business;

(3)    Liens imposed by law, including carriers’, warehousemen’s and mechanics’ Liens, in each case for sums not yet due or being contested in good faith by appropriate proceedings if a reserve or other appropriate provisions, if any, as shall be required by GAAP shall have been made in respect thereof;

(4)    Liens for taxes, assessments or other governmental charges not yet subject to penalties for non-payment or which are being contested in good faith by appropriate proceedings provided appropriate reserves required pursuant to GAAP have been made in respect thereof;

(5)    Liens in favor of issuers of surety or performance bonds or letters of credit or bankers’ acceptances issued pursuant to the request of and for the account of such Person in the ordinary course of its business; provided, however, that such letters of credit do not constitute Indebtedness;

(6)    encumbrances, easements or reservations of, or rights of others for, licenses, rights of way, sewers, electric lines, telegraph and telephone lines and other similar purposes, or zoning or other restrictions as to the use of real properties or Liens incidental to the conduct of the business of such Person or to the ownership of its properties which do not in the aggregate materially adversely affect the value of said properties or materially impair their use in the operation of the business of such Person;

(7)    Liens securing Hedging Obligations so long as the related Indebtedness is, and is permitted to be under the Indenture, secured by a Lien on the same property securing such Hedging Obligation;

(8)    leases and subleases of real property which do not materially interfere with the ordinary conduct of the business of the Company or any of its Restricted Subsidiaries;

(9)    judgment Liens not giving rise to an Event of Default so long as such Lien is adequately bonded and any appropriate legal proceedings which may have been duly initiated for the review of such judgment have not been finally terminated or the period within which such proceedings may be initiated has not expired;

(10)    Liens for the purpose of securing the payment of all or a part of the purchase price of, or Capitalized Lease Obligations with respect to, assets or property acquired or constructed in the ordinary course of business; provided that:

(a)    the aggregate principal amount of Indebtedness secured by such Liens is otherwise permitted to be Incurred under the Indenture and does not exceed the cost of the assets or property so acquired or constructed; and

(b)    such Liens are created within 180 days of construction or acquisition of such assets or property and do not encumber any other assets or property of the Company or any Restricted Subsidiary other than such assets or property and assets affixed or appurtenant thereto;

(11)    Liens arising solely by virtue of any statutory or common law provisions relating to banker’s Liens, rights of set-off or similar rights and remedies as to deposit accounts or other funds maintained with a depositary institution; provided that:

(a)    such deposit account is not a dedicated cash collateral account and is not subject to restrictions against access by the Company in excess of those set forth by regulations promulgated by the Federal Reserve Board; and

142

(b)    such deposit account is not intended by the Company or any Restricted Subsidiary to provide collateral to the depository institution;

(12)    Liens arising from Uniform Commercial Code financing statement filings regarding operating leases entered into by the Company and its Restricted Subsidiaries in the ordinary course of business;

(13)    Liens existing on the Issue Date;

(14)    Liens on property at the time the Company acquired the property, including any acquisition by means of a merger or consolidation with or into the Company; provided, however, that such Liens are not created, incurred or assumed in connection with, or in contemplation of, such acquisition; provided further, however, that such Liens may not extend to any other property owned by the Company or any Restricted Subsidiary;

(15)    Liens securing Indebtedness or other obligations of a Restricted Subsidiary owing to the Company or a Wholly Owned Subsidiary;

(16)    Liens securing the Notes, the Subsidiary Guarantees and other obligations arising under the Indenture;

(17)    Liens securing Refinancing Indebtedness of the Company or a Restricted Subsidiary Incurred to refinance Indebtedness of the Company that was previously so secured; provided that any such Lien is limited to all or part of the same property or assets (plus improvements, accessions, proceeds or dividends or distributions in respect thereof) that secured (or, under the written arrangements under which the original Lien arose, could secure) the Indebtedness being refinanced or is in respect of property or assets that is the security for a Permitted Lien hereunder;

(18)    Liens in respect of Production Payments and Reserve Sales;

(19)    Liens on pipelines and pipeline facilities that arise by operation of law; and

(20)    farmout, carried working interest, joint operating, unitization, royalty, sales and similar agreements relating to the exploration or development of, or production from, oil and gas properties entered into in the ordinary course of business.

“Person” means any individual, corporation, partnership, joint venture, association, joint-stock company, trust, unincorporated organization, limited liability company, government or any agency or political subdivision hereof or any other entity.

“Point Arguello Partnerships” means the following partnerships of which Arguello Inc. is a managing general partner: (a) Gaviota Gas Plant Company, (b) Point Arguello Natural Gas Line Company, (c) Point Arguello Pipeline Company and (d) Point Arguello Terminal Company.

“Preferred Stock,” as applied to the Capital Stock of any corporation, means Capital Stock of any class or classes (however designated) which is preferred as to the payment of dividends, or as to the distribution of assets upon any voluntary or involuntary liquidation or dissolution of such corporation, over shares of Capital Stock of any other class of such corporation.

“Principal Property” means any property owned or leased by the Company or any Subsidiary of the Company, the gross book value of which exceeds one percent of Consolidated Net Worth.

“Production Payments and Reserve Sales” means the grant or transfer by the Company or a Subsidiary of the Company to any Person of a royalty, overriding royalty, net profits interest, production payment (whether volumetric or dollar denominated), partnership or other interest in oil and gas properties, reserves or the right to receive all or a portion of the production or the proceeds from the sale of production attributable to such properties, including any such grants or transfers pursuant to

143

incentive compensation programs on terms that are reasonably customary in the oil and gas business for geologists, geophysicists and other providers of technical services to the Company or a Subsidiary of the Company.

“Property” means, with respect to any Person, any interest of such Person in any kind of property or asset, whether real, personal or mixed, or tangible or intangible, including Capital Stock and other securities issued by any other Person (but excluding Capital Stock or other securities issued by such first mentioned Person).

“Property Net Revenue Coverage Ratio” means, with respect to Property to be acquired by the Company or any Restricted Subsidiary, the ratio of (i) the amount equal to (A) the revenues attributable to the sale of Hydrocarbons from such Property for the most recent four full fiscal quarters for which financial information is available immediately prior to the acquisition date (the “Pro Forma Period”), minus (B) the production and general and administrative expenses attributable to such Property during the Pro Forma Period (the “Property Net Revenue”) to (ii) the aggregate Consolidated Interest Expense which the Company or any Restricted Subsidiary will accrue during the fiscal quarter in which the acquisition date occurs and the three fiscal quarters immediately subsequent to such fiscal quarter as a result of Indebtedness incurred for the purpose of making such acquisition (as though all such Indebtedness was incurred or repaid on the first day of the quarter in which the acquisition date occurs). For purposes of this definition, Property Net Revenue shall be calculated, after giving effect on a pro forma basis for the Pro Forma Period, to (a) any adjustments in revenues from the sale of Hydrocarbons as a result of fixed price or other contract arrangements entered into as of the acquisition date and (b) any adjustments in production and general and administrative expenses which are fixed or determinable as of the acquisition date.

“Refinancing Indebtedness” means Indebtedness that is Incurred to refund, refinance, replace, renew, repay or extend (including pursuant to any defeasance or discharge mechanism) (collectively, “refinance,” “refinances,” and “refinanced” shall have a correlative meaning) any Indebtedness existing on the date of the Indenture or Incurred in compliance with the Indenture (including Indebtedness of the Company that refinances Indebtedness of any Restricted Subsidiary and Indebtedness of any Restricted Subsidiary that refinances Indebtedness of another Restricted Subsidiary) including Indebtedness that refinances Refinancing Indebtedness; provided, however, that:

(1)    (a) if the Stated Maturity of the Indebtedness being refinanced is earlier than the Stated Maturity of the Notes, the Refinancing Indebtedness has a Stated Maturity no earlier than the Stated Maturity of the Indebtedness being refinanced or (b) if the Stated Maturity of the Indebtedness being refinanced is later than the Stated Maturity of the Notes, the Refinancing Indebtedness has a Stated Maturity at least 91 days later than the Stated Maturity of the Notes;

(2)    the Refinancing Indebtedness has an Average Life at the time such Refinancing Indebtedness is Incurred that is equal to or greater than the Average Life of the Indebtedness being refinanced;

(3)    such Refinancing Indebtedness is Incurred in an aggregate principal amount (or if issued with original issue discount, an aggregate issue price) that is equal to or less than the sum of the aggregate principal amount (or if issued with original issue discount, the aggregate accreted value) then outstanding (plus, without duplication, accrued interest, fees and expenses, including any premium and defeasance costs) of the Indebtedness being refinanced; and

(4)    if the Indebtedness being refinanced is subordinated in right of payment to the Notes, such Refinancing Indebtedness is subordinated in right of payment to the Notes on terms at least as favorable to the holders as those contained in the documentation governing the Indebtedness being extended, refinanced, renewed, replaced, defeased or refunded.

144

“Registration Rights Agreement” means that certain registration rights agreement dated as of the date of the Indenture by and between the Issuers, the Subsidiary Guarantors and the initial purchaser set forth therein and future registration rights agreements with respect to the New Notes.

“Related Business” means any business which is the same as or related, ancillary or complementary to any of the businesses of the Company on the date of the Indenture, which includes (a) the acquisition, exploration, exploitation, development, production, operation and disposition of interests in oil, gas and other hydrocarbon properties, and the utilization of the Company’s properties, (b) the gathering, marketing, treating, processing, storage, refining, selling and transporting of any production from such interests or properties and products produced in association therewith, (c) any power generation and electrical transmission business and (d) any business or activity relating to, arising from, or necessary, appropriate or incidental to the activities described in the foregoing clauses (a) through (c) of this definition.

“Representative” means any trustee, agent or representative (if any) of an issue of Senior Indebtedness.

“Restricted Investment” means any Investment other than a Permitted Investment.

“Restricted Subsidiary” means any Subsidiary of the Company other than an Unrestricted Subsidiary.

“Sale/Leaseback Transaction” means an arrangement relating to property now owned or hereafter acquired whereby the Company or a Restricted Subsidiary transfers such property to a Person and the Company or a Restricted Subsidiary leases it from such Person.

“Senior Credit Agreement” means, with respect to the Company, one or more debt facilities (including, without limitation, the Credit Agreement, dated as of July 3, 2002, among the Company, JPMorgan Chase Bank, as administrative agent, and the lenders and agents parties thereto from time to time) or commercial paper facilities providing for revolving credit loans, term loans, receivables financing (including through the sale of receivables to such lenders or to special purpose entities formed to borrow from such lenders against such receivables) or letters of credit, in each case, as amended, restated, modified, renewed, refunded, replaced or refinanced in whole or in part from time to time (and whether or not with the original administrative agent and lenders or another administrative agent or agents or other lenders and whether provided under the original Senior Credit Agreement or any other credit or other agreement or indenture).

“Senior Indebtedness” means, whether outstanding on the Issue Date or thereafter issued, created, Incurred or assumed, the Bank Indebtedness and all other Indebtedness of an Issuer, including accrued and unpaid interest (including interest accruing on or after the filing of any petition in bankruptcy or for reorganization relating to such Issuer at the rate specified in the documentation with respect thereto whether or not a claim for post filing interest is allowed in such proceeding) and fees relating thereto; provided, however, that Senior Indebtedness will not include:

(1)    any Indebtedness which, in the instrument creating or evidencing the same or pursuant to which the same is outstanding, it is provided that the obligations in respect of such Indebtedness are not superior in right of, or are subordinate to, payment of the Notes;

(2)    any obligation of the Company to any Subsidiary;

(3)    any liability for Federal, state, foreign, local or other taxes owed or owing by the Company;

(4)    any accounts payable or other liability to trade creditors arising in the ordinary course of business (including Guarantees thereof or instruments evidencing such liabilities);

145

(5)    any Indebtedness, Guarantee or obligation of the Company that is expressly subordinate or junior in right of payment to any other Indebtedness, Guarantee or obligation of the Company, including, without limitation, any Senior Subordinated Indebtedness and any Subordinated Obligations; or

(6)    any Capital Stock.

“Senior Subordinated Indebtedness” means the Notes and any other Indebtedness of the Company that specifically provides that such Indebtedness is to rank equally with the Notes in right of payment and is not subordinated by its terms in right of payment to any Indebtedness or other obligation of the Company which is not Senior Indebtedness.

“Significant Subsidiary” means any Restricted Subsidiary that would be a “Significant Subsidiary” of the Company within the meaning of Rule 1-02 under Regulation S-X promulgated by the SEC.

“Spin-off” means any distribution of Voting Stock then owned by Plains Resources Inc. and its Subsidiaries of the Company to Plains Resources Inc.’s shareholders.

“Stated Maturity” means, with respect to any security, the date specified in such security as the fixed date on which the payment of principal of such security is due and payable, including pursuant to any mandatory redemption provision, but shall not include any contingent obligations to repay, redeem or repurchase any such principal prior to the date originally scheduled for the payment thereof.

“Subordinated Obligation” means any Indebtedness of the Company (whether outstanding on the Issue Date or thereafter Incurred) which is subordinate or junior in right of payment to the Notes pursuant to a written agreement.

“Subsidiary” of any Person means any corporation, association, partnership, joint venture, limited liability company or other business entity of which more than 50% of the total voting power of shares of Capital Stock or other interests (including partnership and joint venture interests) entitled (without regard to the occurrence of any contingency) to vote in the election of directors, managers or trustees thereof is at the time owned or controlled, directly or indirectly, by (1) such Person, (2) such Person and one or more Subsidiaries of such Person or (3) one or more Subsidiaries of such Person. Unless otherwise specified herein, each reference to a Subsidiary will refer to a Subsidiary of the Company. The Point Arguello Partnerships are not Subsidiaries of the Company.

“Subsidiary Guarantee” means any guarantee of the Notes by any Subsidiary Guarantor in accordance with the provisions set forth in “—Senior Subordinated Guarantee of Notes.”

“Subsidiary Guarantor” means each Restricted Subsidiary of the Company that has issued a Subsidiary Guarantee.

“Transition Agreements” mean the Master Separation Agreement, between Plains Resources Inc. and the Company, dated as of July 3, 2002, the Employee Matters Agreement, between Plains Resources Inc. and the Company, dated as of July 3, 2002, the Plains Exploration & Production transition services agreement, between Plains Resources Inc. and the Company, dated as of July 3, 2002, the Plains Resources transition services agreement, between Plains Resources Inc. and the Company, dated as of July 3, 2002, the Technical Services Agreement, among Plains Resources Inc., Calumet Florida, LLC and the Company, dated as of July 3, 2002, the Intellectual Property Agreement, between Plains Resources Inc. and the Company, dated as of July 3, 2002 and the Tax Allocation Agreement, between Plains Resources Inc. and the Company, dated as of July 3, 2002, each as amended or supplemented from time to time in compliance with the terms of the Indenture.

146

“Unrestricted Subsidiary” means:

(1)    any Subsidiary of the Company that at the time of determination shall be designated an Unrestricted Subsidiary by the Board of Directors of the Company in the manner provided below; and

(2)    any Subsidiary of an Unrestricted Subsidiary.

The Board of Directors of the Company may designate any Subsidiary of the Company (including any newly acquired or newly formed Subsidiary or a Person becoming a Subsidiary through merger or consolidation or Investment therein) to be an Unrestricted Subsidiary only if:

(1)    such Subsidiary or any of its Subsidiaries does not own any Capital Stock or Indebtedness of or have any Investment in, or own or hold any Lien on any property of, any other Subsidiary of the Company which is not a Subsidiary of the Subsidiary to be so designated or otherwise an Unrestricted Subsidiary;

(2)    all the Indebtedness of such Subsidiary and its Subsidiaries shall, at the date of designation, and will at all times thereafter, consist of Non-Recourse Debt;

(3)    such designation and the Investment of the Company in such Subsidiary complies with “Certain Covenants—Limitation on Restricted Payments;”

(4)    such Subsidiary, either alone or in the aggregate with all other Unrestricted Subsidiaries, does not operate, directly or indirectly, all or substantially all of the business of the Company and its Subsidiaries taken as a whole;

(5)    such Subsidiary is a Person with respect to which neither the Company nor any of its Restricted Subsidiaries has any direct or indirect obligation:

(a)    to subscribe for additional Capital Stock of such Person; or

(b)    to maintain or preserve such Person’s financial condition or to cause such Person to achieve any specified levels of operating results; and

(6)    on the date such Subsidiary is designated an Unrestricted Subsidiary, such Subsidiary is not a party to any agreement, contract, arrangement or understanding with the Company or any Restricted Subsidiary with terms substantially less favorable to the Company than those that might have been obtained from Persons who are not Affiliates of the Company.

Any such designation by the Board of Directors of the Company shall be evidenced to the Trustee by filing with the Trustee a resolution of the Board of Directors of the Company giving effect to such designation and an Officers’ Certificate certifying that such designation complies with the foregoing conditions. If, at any time, any Unrestricted Subsidiary would fail to meet the foregoing requirements as an Unrestricted Subsidiary, it shall thereafter cease to be an Unrestricted Subsidiary for purposes of the Indenture and any Indebtedness of such Subsidiary shall be deemed to be Incurred as of such date.

The Board of Directors of the Company may designate any Unrestricted Subsidiary to be a Restricted Subsidiary; provided that immediately after giving effect to such designation, no Default or Event of Default shall have occurred and be continuing or would occur as a consequence thereof and the Company could incur at least $1.00 of additional Indebtedness under the first paragraph of the “Limitation on Indebtedness” covenant on a pro forma basis taking into account such designation.

“Volumetric Production Payments” means production payment obligations recorded as defined revenue in accordance with GAAP, together with all undertakings and obligations in connection therewith.

147

“Voting Stock” of a Person means all classes of Capital Stock of such Person then outstanding and normally entitled to vote in the election of directors.

“Wholly-Owned Subsidiary” means a Restricted Subsidiary of the Company, all of the Capital Stock of which (other than directors’ qualifying shares) is owned by the Company or another Wholly-Owned Subsidiary.

148

UNITED STATES FEDERAL INCOME AND ESTATE TAX CONSIDERATIONS

The following is a general discussion of material United States federal income tax considerations applicable to initial investors who purchase, hold and sell the notes as “capital assets” within the meaning of Section 1221 of the Internal Revenue Code of 1986, as amended (the “Code”). This summary is based upon provisions of the Code, regulations, rulings and decisions currently in effect, all of which are subject to change, possibly with retroactive effect. The discussion does not purport to deal with all aspects of the United States federal taxation that may be relevant to particular investors in light of their particular circumstances (for example, to persons holding notes as part of a conversion transaction or as part of a hedge or hedging transaction, or as a position in a straddle for tax purposes), nor does it discuss the United States federal income tax considerations applicable to certain types of investors subject to special treatment under the federal income tax laws (for example, insurance companies, tax-exempt organizations and financial institutions). In addition, the discussion does not consider the effect of any foreign, state, local or other tax laws that may be applicable to a particular investor.

We urge prospective investors considering the exchange of notes should consult their tax advisors with regard to the application of the United States federal income tax laws to their particular situations as well as any tax consequences arising under the laws of any state, local or foreign taxing jurisdiction.

Tax Consequences to United States Holders

As used in this tax discussion, the term “United States holder” means a beneficial owner of a note that is, for United States federal income tax purposes,

• a citizen or resident of the United States,

• a corporation, partnership or other entity created or organized in or under the laws of the United States or of any political subdivision thereof,

• an estate, the income of which is subject to United States federal income taxation regardless of its source, or

• a trust if (1) a court within the United States is able to exercise primary supervision over the administration of the trust and one or more United States persons have the authority to control all substantial decisions of the trust or (2) it has a valid election in effect under applicable U.S. Treasury regulations to be treated as a U.S. person.

The term also includes certain former citizens and certain former long-term residents of the United States. If a partnership holds notes, the tax treatment of a partner will generally depend on the status of the partner and on the activities of the partnership. Partners of partnerships holding notes should consult their tax advisors.

Payment of Interest on the Notes.    The notes were not issued with original issue discount for United States federal income tax purposes. Accordingly, interest on a note will generally be taxable to a United States holder as ordinary interest income at the time it accrues or is received in accordance with the United States holder’s method of accounting for United States federal income tax purposes.

Amortizable Bond Premium.     A United States holder whose basis in a note exceeds the amount due on maturity of the note may elect to amortize that excess (“bond premium”) over the remaining maturity of the note, by claiming an interest offset for the bond premium for the first taxable year in which the holder desires the election to be applicable. A United States holder electing to amortize bond premium is, however, required to make a corresponding reduction in the holder’s basis

149

in the note. Each United States holder must calculate the portion of bond premium allocable to each payment on a note based on its yield to maturity with respect to the note. United States Treasury Regulations provide that a United States holder electing to amortize bond premium should attach a statement to the holder’s return for that year showing the computation of the bond premium amortization. In general, once an election is made to amortize bond premium with respect to any debt instrument held by a United States holder, it applies to all debt instruments with bond premium owned by the taxpayer during that taxable year and all subsequent years. The election may be revoked only with the consent of the Commissioner of the Internal Revenue Service.

Sale or Retirement of a Note.    Upon the sale or retirement of a note, a United States holder will recognize a taxable gain or loss equal to the difference between the amount realized on the sale or retirement and the holder’s adjusted tax basis in the note. A holder’s adjusted tax basis in a note generally will be the cost for the note decreased by any amortized bond premium and any principal payments the holder receives on the note. This gain or loss generally will be capital gain or loss, and will be long-term capital gain or loss if the note have been held for more than one year. To the extent the amount realized represents accrued but unpaid interest, that amount must be taken into account as interest income, if it was not previously included in income of the holder.

Exchange Offer.    The exchange of the Series A notes for Series B notes pursuant to the Registration Rights Agreement will not result in any United States federal income tax consequences to the United States holders. When a United States holder exchanges a Series A note for a Series B note pursuant to the Registration Rights Agreement, the holder will have the same adjusted tax basis and holding period in the exchange note as in the Series B note immediately before the exchange.

Payments Under Registration Rights Agreement.    As more fully discussed under “Exchange and Registration Rights,” we may be required to pay liquidated damages to holders in the event we do not comply with certain covenants. Although the matter is not free from doubt, we intend to take the position that a holder should be required to report any liquidated damages as ordinary income for United States federal income tax purposes at the time it accrues or is received in accordance with the holder’s regular method of accounting. It is possible, however, that the Internal Revenue Service may take a different position, in which case the timing and amount of income may be different.

Backup Withholding and Information Reporting.    Information reporting will apply to payments of principal, premium and interest on, and the proceeds of disposition of, a note with respect to certain noncorporate United States holders and backup unitholding may also apply. Backup withholding will apply only if the United States holder (i) fails to furnish its Taxpayer Identification Number (“TIN”) which, for an individual, would be his Social Security number, (ii) furnishes an incorrect TIN, (iii) is notified by the Internal Revenue Service that it has failed to properly report payments of interest or dividends or (iv) under certain circumstances, fails to certify, under penalties of perjury, that it has not been notified by the IRS that it is subject to backup withholding for failure to report interest and dividend payments. The backup withholding rate is currently 30%. After December 31, 2010, the backup withholding rate will be increased to 31%. United States holders should consult their tax advisors regarding their qualification for exemption from backup withholding and the procedure for obtaining such an exemption if applicable.

The amount of any backup withholding from a payment to a United States holder will be allowed as a credit against the holder’s United States federal income tax liability and may entitle the holder to a refund, provided that the required information is furnished to the Internal Revenue Service.

Tax Consequences to Non-United States Holders

As used in this tax discussion, a non-United States holder means any beneficial owner of a note that is not a United States holder. The rules governing the United States federal income and estate

150

taxation of a non-United States holder are complex, and no attempt will be made herein to provide more than a summary of those rules.

Special rules may apply to a non-United States holder if that holder is a controlled foreign corporation, passive foreign investment company or foreign personal holding company and therefore subject to special treatment under the Code. Non-United States holders should consult with their own tax advisors to determine the effect of federal, state, local and foreign tax laws with regard to an investment in the New Notes, including any reporting requirements.

Payment of Interest.    Generally, payment of interest on a note to a non-United States holder will qualify for the “portfolio interest” exemption and, therefore, will not be subject to United States federal income tax or withholding tax, provided that this interest income is not effectively connected with a United States trade or business of the non-United States holder and provided that the non-United States holder:

• does not actually or constructively own 10% or more of the combined voting power of all classes of voting stock,

• is not, for United States federal income tax purposes, a controlled foreign corporation related to us through stock ownership within the meaning of the Code,

• is not a bank receiving interest on a loan entered into in the ordinary course of its business within the meaning of the Code and

• either:

(a)    provides a Form W-8BEN or W-8IMY, as appropriate (or a suitable substitute form), signed under penalties of perjury that includes its name and address and certifies as to its non-United States holder status in compliance with applicable law and regulations or

(b)    holds its notes through a securities clearing organization, bank or other financial institution that holds customers’ securities in the ordinary course of its trade or business and that provides a statement signed under penalties of perjury in which it certifies to the issuers or the issuers’ agent that a Form W-8BEN or W-8IMY, as appropriate (or suitable substitute), has been received by it from the non-United States holder or qualifying intermediary and furnishes the issuers or the issuers’ agent with a copy thereof.

United States Treasury Regulations provide special certification requirements for certain non-United States holders that are entities rather than individuals. For example, in the case of notes held by a foreign partnership, the regulations require that the certification described above be provided by the partners rather than by the partnership and that the partnership provide certain information, including a U.S. taxpayer identification number. A look-through rule applies in the case of tiered partnerships. Non-United States holders are urged to consult their own tax advisors regarding these regulations.

Except to the extent that an applicable treaty otherwise provides, a non-United States holder generally will be taxed in the same manner as a United States holder with respect to interest if the interest income is effectively connected with a United States trade or business of the non-United States holder. Effectively connected interest received by a corporate non-United States holder may also, under certain circumstances, be subject to an additional “branch profits tax” at a 28% rate (or, if applicable, a lower treaty rate). Even though this effectively connected interest is subject to income tax, and may be subject to the branch profits tax, it is generally not subject to withholding tax if the non-United States holder delivers IRS Form W-8ECI (or successor form) annually to the payor.

Interest income of a non-United States holder that is not effectively connected with a United States trade or business and that does not qualify for the portfolio interest exemption described above

151

will generally be subject to a withholding tax at a 28% rate unless that rate is reduced or eliminated pursuant to an applicable tax treaty. Non-United States holders can claim such treaty benefits on IRS Form W-8 BEN (or other applicable form).

As described above under “Payments Under Registration Rights Agreement” we may be required to pay you liquidated damages in certain circumstances. Such payments may be subject to United States federal withholding tax.

Sale, Exchange or Redemption of the Notes.    A non-United States holder of a note will generally not be subject to United States federal income tax or withholding tax on any gain realized on the sale, exchange, redemption or other disposition of the New Note unless:

• the gain is effectively connected with a United States trade or business of the non-United States holder,

• in the case of a non-United States holder who is an individual, the holder is present in the United States for a period or periods aggregating 183 days or more during the taxable year of the disposition, and either the holder has a “tax home” in the United States or the disposition is attributable to an office or other fixed place of business maintained by that holder in the United States or

• the non-United States holder is subject to tax pursuant to the provisions of the Code applicable to certain United States expatriates.

U.S. Federal Estate Tax Considerations.    A note beneficially owned by an individual who is not a citizen or resident of the United States at the time of death will generally not be includable in the decedent’s gross estate for United States federal estate tax purposes, provided that at the time of death the beneficial owner satisfied the requirements of the “portfolio interest” exemption described above (without regard to the certification requirement) and provided that, at the time of the holder’s death, payments with respect to that note would not have been effectively connected with the holder’s conduct of a trade or business within the United States.

Information Reporting and Backup Withholding Tax.    If you are a non-United States holder of notes, we must report annually to the IRS and to you the amount of payments we make to you and the tax withheld with respect to such payments, regardless of whether withholding was required. Copies of the information returns reporting such payments and withholding may also be made available to the tax authorities in the country in which you reside under the provisions of an applicable tax treaty. Backup withholding tax generally will not apply to payments of interest, premium and principal on a New Note made by us to a non-United States holder if the statement described in “—Payment of Interest” is duly provided by the holder or the holder otherwise establishes an exemption, provided that the issuers do not have actual knowledge that the holder is a United States person.

Information reporting requirements and backup withholding tax generally will not apply to any payment on a note or the proceeds of the sale of a note effected outside the United States by a foreign office of a “broker” (as defined in applicable United States Treasury Regulations) provided that the payor does not have actual knowledge or reason to know that the holder is a United States person. However, if the broker:

• is a United States person,

• is a foreign person that derives 50% or more of its gross income from all sources for certain periods from the conduct of a United States trade or business,

• is a controlled foreign corporation for United States tax purposes or

152

• is a foreign partnership in which one or more United States persons, in the aggregate, own more than 50% of the income or capital interests in the partnership or a foreign partnership that is engaged in a trade or business in the United States,

such payments will be subject to information reporting requirements unless the broker has documentary evidence in its records that the beneficial owner is a non-United States holder and certain other conditions are met, or the beneficial owner otherwise establishes an exemption.

Payments on a note or the proceeds of any sale of a note made to or through the United States office of a broker, whether foreign or United States, is subject to information reporting and backup withholding requirements, unless the beneficial owner of the note provides the statement described in “—Payment of Interest” or otherwise establishes an exemption and the broker does not have actual knowledge that the payee is a United States person or that the exemption conditions are not satisfied.

Any amounts withheld from a payment to a non-United States holder under the backup withholding rules will be allowed as a credit against the holder’s United States federal income tax liability and may entitle the non-United States holder to a refund, provided that the required information is provided to the IRS.

The federal tax discussion set forth above is included for general information only and may not be applicable depending upon a holder’s particular situation. We urge you to consult your tax advisors with respect to the tax consequences to you of the purchase, ownership and disposition of the notes, including the tax consequences under state, local, foreign and other tax laws and the possible effects of changes in federal or other tax laws.

CERTAIN ERISA CONSIDERATIONS

The following is a summary of certain considerations associated with the purchase of the notes and exchange notes by employee benefit plans that are subject to Title I of ERISA, plans, individual retirement accounts and other arrangements that are subject to Section 4975 of the Code or provisions under any federal, state, local, non U.S. or other laws or regulations that are similar to such provisions of ERISA or the Code (collectively, “Similar Laws”), and entities whose underlying assets are considered to include “plan assets” of such plans, accounts and arrangements (each, a “Plan”).

General Fiduciary Matters

ERISA and the Code impose certain duties on persons who are fiduciaries of a Plan subject to Title I of ERISA or Section 4975 of the Code (an “ERISA Plan”) and prohibit certain transactions involving the assets of an ERISA Plan and its fiduciaries or other interested parties. Under ERISA and the Code, any person who exercises any discretionary authority or control over the administration of such an ERISA Plan or the management or disposition of the assets of such an ERISA Plan, or who renders investment advice for a fee or other compensation to such an ERISA Plan, is generally considered to be a fiduciary of the ERISA Plan.

In considering an investment in the notes of a portion of the assets of any Plan, a fiduciary should determine whether the investment is in accordance with the documents and instruments governing the Plan and the applicable provisions of ERISA, the Code or any Similar Law relating to a fiduciary’s duties to the Plan including, without limitation, the prudence, diversification, delegation of control and prohibited transaction provisions of ERISA, the Code and any other applicable Similar Laws.

Any insurance company proposing to invest assets of its general account in the notes should consider the extent that such investment would be subject to the requirements of ERISA in light of the

153

U.S. Supreme Court’s decision in John Hancock Mutual Life Insurance Co. v. Harris Trust and Savings Bank and under any subsequent legislation or other guidance that has or may become available relating to that decision, including the enactment of Section 401(c) of ERISA by the Small Business Job Protection Act of 1996 and the regulations promulgated thereunder.

Prohibited Transaction Issues

Section 406 of ERISA and Section 4975 of the Code prohibit ERISA Plans from engaging in specified transactions involving plan assets with persons or entities who are “parties in interest,” within the meaning of ERISA or “disqualified persons,” within the meaning of Section 4975 of the Code, unless an exemption is available. A party in interest or disqualified person who ‘engages in a nonexempt prohibited transaction may be subject to excise taxes and other penalties and liabilities under ERISA and the Code. In addition, the fiduciary of the ERISA Plan that engages in such a nonexempt prohibited transaction may be subject to penalties and liabilities under ERISA and the Code. The acquisition and/or holding of Notes by an ERISA Plan with respect to which we or the initial purchaser are considered a party in interest or disqualified person may constitute or result in a direct or indirect prohibited transaction under Section 406 of ERISA and/or Section 4975 of the Code, unless the investment is acquired and is held in accordance with an applicable statutory, class or individual prohibited transaction exemption. In this regard, the U.S. Department of Labor has issued prohibited transaction class exemptions (“PTCEs”) that may apply to the acquisition and holding of the notes. These class exemptions include, without limitation, PTCE 84-14, respecting transactions determined by independent qualified professional asset managers, PTCE 90-1, respecting insurance company pooled separate accounts, PTCE 91-38, respecting bank collective investment funds, PTCE 95-60, respecting life insurance company general accounts and PTCE 96-23, respecting transactions determined by in-house asset managers, although there can be no assurance that all of the conditions of any such exemptions will be satisfied.

Because of the foregoing, the notes should not be purchased or held by any person investing “plan assets” of any Plan, unless such purchase and holding (and the exchange of notes for exchange notes) will not constitute a non-exempt prohibited transaction under ERISA and the Code or similar violation of any applicable Similar Laws.

Representation

Accordingly, by acceptance of a notes or an exchange note, each purchaser and subsequent transferee will be deemed to have represented and warranted that either (i) no portion of the assets used by such purchaser or transferee to acquire and hold the notes constitutes assets of any Plan or (ii) the purchase and holding of the notes (and the exchange of notes for exchange notes) by such purchaser or transferee will not constitute a nonexempt prohibited transaction under Section 406 of ERISA or Section 4975 of the Code or similar violation under any applicable Similar Laws.

This discussion is general in nature and is not intended to be all inclusive. Due to the complexity of these rules and penalties that may be imposed upon persons involved in non-exempt prohibited transactions, it is particularly important that fiduciaries or other persons considering purchasing the notes (and holding the notes or exchange notes) on behalf of, or with the assets of, any Plan, consult with their counsel regarding the potential applicability of ERISA, Section 4975 of the Code and any Similar Laws to such transactions and whether an exemption would be applicable.

154

PLAN OF DISTRIBUTION

Based on interpretations by the staff of the SEC set forth in no-action letters issued to third parties, we believe that you may freely transfer Series B notes issued under the exchange offer in exchange for the Series A notes, unless you are:

• our “affiliate” within the meaning of Rule 405 under the Securities Act;

• a broker-dealer or an initial purchaser that acquired Series A notes directly from us; or

• a broker-dealer that acquired Series A notes as a result of market-making or other trading activities without compliance with the registration and prospectus delivery provisions of the Securities Act;

provided that you acquire the Series B notes in the ordinary course of your business and you are not engaged in, and do not intend to engage in, and have no arrangement or understanding with any person to participate in, a distribution of the Series B notes. Broker-dealers receiving Series B notes in the exchange offer in exchange for Series A notes that were acquired in market-making or other trading activities will be subject to a prospectus delivery requirement with respect to resales of the Series B notes.

To date, the staff of the SEC has taken the position that participating broker-dealers may fulfill their prospectus delivery requirements with respect to transactions involving an exchange of securities such as this exchange offer, other than a resale of an unsold allotment from the original sale of the Series A notes, with the prospectus contained in the exchange offer registration statement. Pursuant to the registration rights agreement, we have agreed to permit such participating broker-dealers to use this prospectus in connection with the resale of the Series B notes.

If you wish to exchange your Series A notes for Series B notes in the exchange offer, you will be required to make certain representations to us as set forth in “The Exchange Offer—Registration Rights” and “—Procedures for Tendering Series A Notes—Determination of Validity” of this prospectus beginning on pages 30 and 37 and in the letter of transmittal. In addition, if you are a broker-dealer who receives Series B notes for your own account in exchange for Series A notes that were acquired by you as a result of market-making activities or other trading activities, you will be required to acknowledge that you will deliver a prospectus in connection with any resale by you of those Series B notes. See “The Exchange Offer—Resale of Series B Notes; Plan of Distribution” beginning on page 40.

We will not receive any proceeds from any sale of Series B notes by broker-dealers. Broker-dealers who receive Series B notes for their own account in the exchange offer may sell them from time to time in one or more transactions in the over-the-counter market:

• in negotiated transactions;

• through the writing of options on the Series B notes or a combination of such methods of resale;

• at market prices prevailing at the time of resale; or

• at prices related to the prevailing market prices or negotiated prices.

Any resale may be made directly to purchasers or to or through brokers or dealers who may receive compensation in the form of commissions or concessions from any broker-dealer or the purchasers of any Series B notes. Any broker-dealer that resells Series B notes it received for its own account pursuant to the exchange offer and any broker or dealer that participates in a distribution of Series B notes may be deemed to be an “underwriter” within the meaning of the Securities Act, and any profit on any resale of Series B notes and any commissions or concessions received by any such persons may be deemed to be underwriting compensation under the Securities Act. Although the letter of transmittal requires a broker dealer to deliver a prospectus, a broker-dealer will not be deemed to admit that it is an “underwriter” within the meaning of the Securities Act as a result of such delivery.

155

We have agreed to pay all expenses incidental to the exchange offer other than commissions and concessions of any brokers or dealers and will indemnify holders of the Series A notes, including any broker-dealers, against certain liabilities, including liabilities under the Securities Act, as set forth in the registration rights agreement.

VALIDITY OF THE SERIES B NOTES

Akin Gump Strauss Hauer & Feld LLP will pass upon the validity of the Series B notes we are offering.

EXPERTS

The consolidated financial statements of Plains Exploration & Production Company as of December 31, 2002 and 2001 and for each of the three years in the period ended December 31, 2002, included in this prospectus have been so included in reliance on the report of PricewaterhouseCoopers LLP, independent accountants, given on the authority of said firm as experts in auditing and accounting.

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

The consolidated financial statements of 3TEC Energy Corporation and subsidiaries as of December 31, 2002 and 2001, and for each of the three years in the period ended December 31, 2002, have been included herein in reliance upon the report of KPMG LLP, independent auditors, appearing elsewhere herein, and upon the authority of said firm as experts in accounting and auditing. The audit report refers to a change in the method of accounting for derivative instruments and hedging activities effective January 1, 2001.

Certain information with respect to the oil and gas reserves associated with 3TEC’s oil and gas properties is derived from the reports of Ryder Scott Company, L.P., an independent petroleum consulting firm, and has been included in this prospectus upon the authority of said firms as experts with respect to the matters covered by such reports and in giving such reports.

WHERE YOU CAN FIND MORE INFORMATION

Plains files annual, quarterly and special reports, proxy statements and other information with the SEC. You may read and copy any reports, statements or other information Plains files at the SEC’s public reference room located at 450 Fifth Street, N.W., Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on the public reference room. These SEC filings are also available to the public at the web site maintained by the SEC at http://www.sec.gov and by Plains at www.plainsxp.com.

This prospectus is part of the registration statement and does not contain all of the information you can find in the registration statement or the exhibits to the registration statement. Although we have discussed the material provisions of our contracts and other documents in this prospectus, whenever a reference is made in this prospectus to any of our contracts or other documents, you should refer to the exhibits that are a part of the registration statement for a copy of the contract or document.

156

We will provide you without charge a copy of the notes, the indenture governing the notes and the registration rights agreement relating to the notes. You may request copies of these documents by contacting us at:

Plains Exploration & Production Company

700 Milam, Suite 3100

Houston, Texas 77002

Attention: Investor Relations

(832) 239-6000

157

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

	Page
Plains Exploration & Production Company
Consolidated Balance Sheets (Unaudited) as of June 30, 2003 and December 31, 2002	F-2
Consolidated Statements of Income (Unaudited) for the six months ended June 30, 2003 and 2002	F-3
Consolidated Statements of Cash Flows (Unaudited) for the six months ended June 30, 2003 and 2002	F-4
Consolidated Statements of Comprehensive Income (Unaudited) for the six months ended June 30, 2003 and 2002	F-5
Consolidated Statement of Stockholders’ Equity (Unaudited) for the six months ended June 30, 2003	F-6
Notes to Consolidated Financial Statements	F-7
Report of Independent Accountants	F-23
Consolidated Balance Sheets as of December 31, 2002 and 2001	F-24
Consolidated Statements of Income for the years ended December 31, 2002, 2001 and 2000	F-25
Consolidated Statements of Cash Flows for the years ended December 31, 2002, 2001 and 2000	F-26
Consolidated Statements of Comprehensive Income for the years ended December 31, 2002, 2001, and 2000	F-27
Consolidated Statements of Stockholders’ Equity for the years ended December 31, 2002, 2001, and 2000	F-28
Notes to Consolidated Financial Statements	F-29
3TEC Energy Corporation and Subsidiaries
Consolidated Balance Sheets as of March 31, 2003 and December 31, 2002	F-59
Consolidated Statements of Operations for the three months ended March 31, 2003 and 2002	F-60
Consolidated Statements of Cash Flows for the three months ended March 31, 2003 and 2002	F-61
Notes to Consolidated Financial Statements	F-62
Report of Independent Auditors	F-68
Consolidated Balance Sheets as of December 31, 2002 and 2001	F-69
Consolidated Statements of Operations for the years ended December 31, 2002, 2001 and 2000	F-70
Consolidated Statements of Cash Flows for the years ended December 31, 2002, 2001 and 2000	F-71
Consolidated Statements of Changes in Stockholders’ Equity for the years ended December 31, 2002, 2001 and 2000	F-72
Notes to Consolidated Financial Statements	F-73

F-1

PLAINS EXPLORATION & PRODUCTION COMPANY

CONSOLIDATED BALANCE SHEETS (Unaudited)

(in thousands of dollars)

	June 30, 2003			December 31, 2002
ASSETS
Current Assets
Cash and cash equivalents	$	3,466		$	1,028
Accounts receivable—Plains All American Pipeline, L.P.		23,103			22,943
Other accounts receivable		20,179			5,925
Commodity hedging contracts		1,675			2,594
Inventories		7,706			5,198
Other current assets		8,215			1,051
		64,344			38,739
Property and Equipment, at cost
Oil and gas properties—full cost method
Subject to amortization		978,202			629,454
Not subject to amortization		85,268			30,045
Other property and equipment		3,165			2,207
		1,066,635			661,706
Less allowance for depreciation, depletion and amortization		(154,996	)		(168,494	)
		911,639			493,212
Goodwill		143,962			—
Other Assets		18,616			18,929
	$	1,138,561		$	550,880
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts payable and other current liabilities	$	74,586		$	40,012
Commodity hedging contracts		39,748			24,572
Royalties payable		14,993			11,873
Interest payable		9,974			9,207
Current maturities of long-term debt		511			511
		139,812			86,175
Long-Term Debt
8.75% senior subordinated notes		276,991			196,855
Revolving credit facility		233,000			35,800
Other		511			511
		510,502			233,166
Asset Retirement Obligation		31,411			—
Other Long-Term Liabilities		17,577			6,303
Deferred Income Taxes		99,226			51,416
Commitments and Contingencies (Note 6)
Stockholders’ Equity
Common stock		405			244
Additional paid-in capital		327,705			174,279
Retained earnings		40,312			12,155
Accumulated other comprehensive income		(28,389	)		(12,858	)
		340,033			173,820
	$	1,138,561		$	550,880

See notes to consolidated financial statements.

F-2

PLAINS EXPLORATION & PRODUCTION COMPANY

CONSOLIDATED STATEMENTS OF INCOME (Unaudited)

(in thousands, except per share data)

	Six Months Ended June 30,
	2003			2002
Revenues
Oil sales to Plains All American Pipeline, L.P.	$	119,593		$	81,676
Other oil sales		1,636			—
Oil hedging		(26,255	)		(454	)
Gas sales		20,229			4,578
Gas hedging		(1,448	)		—
Other operating revenues		407			13
		114,162			85,813
Costs and Expenses
Production expenses		42,351			32,754
Production and ad valorem taxes		2,856			2,328
Gathering and transportation expenses		327			—
General and administrative
G&A excluding items below		8,757			4,726
Stock appreciation rights		2,647			—
Merger related costs		1,097			—
Depreciation, depletion and amortization		17,868			13,507
Accretion of asset retirement obligation		1,176			—
		77,079			53,315
Income from Operations		37,083			32,498
Other Income (Expense)
Interest expense		(10,194	)		(9,418	)
Interest and other income (expense)		(167	)		36
Income Before Income Taxes and Cumulative Effect of Accounting Change		26,722			23,116
Income tax expense
Current		(2,429	)		(4,018	)
Deferred		(8,460	)		(5,016	)
Income Before Cumulative Effect of Accounting Change		15,833			14,082
Cumulative effect of accounting change, net of tax		12,324			—
Net Income	$	28,157		$	14,082
Earnings Per Share (in dollars)
Basic
Income before cumulative effect of accounting change	$	0.60		$	0.58
Cumulative effect of accounting change		0.47			—
	$	1.07		$	0.58
Diluted
Income before cumulative effect of accounting change	$	0.59		$	0.58
Cumulative effect of accounting change		0.47			—
	$	1.06		$	0.58
Weighted Average Shares Outstanding
Basic		26,414			24,200
Diluted		26,682			24,200

See notes to consolidated financial statements.

F-3

PLAINS EXPLORATION & PRODUCTION COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(in thousands of dollars)

	Six Months Ended June 30,
	2003			2002
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	28,157		$	14,082
Items not affecting cash flows from operating activities
Depreciation, depletion and amortization		17,868			13,507
Accretion of asset retirement obligation		1,176			—
Deferred income taxes		8,460			5,016
Cumulative effect of adoption of accounting change		(12,324	)		—
Noncash compensation		2,685			—
Other noncash items		377			324
Change in assets and liabilities from operating activities, net of effect of acquisition
Accounts receivable and other assets		3,047			(2,839	)
Inventories		(2,297	)		(384	)
Accounts payable and other liabilities		(19,235	)		(9,930	)
Net cash provided by operating activities		27,914			19,776
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to oil and gas properties		(46,780	)		(42,341	)
Acquisition of 3TEC Energy Corporation, net of cash acquired		(251,883	)		—
Other		(740	)		(17	)
Net cash used in investing activities		(299,403	)		(42,358	)
CASH FLOWS FROM FINANCING ACTIVITIES
Change in revolving credit facility		197,200			—
Proceeds from debt issuance		80,061			—
Debt issuance costs		(4,069	)		—
Receipts from Plains Resources Inc.		510			22,576
Other		225			—
Net cash provided by financing activities		273,927			22,576
Net increase (decrease) in cash and cash equivalents		2,438			(6	)
Cash and cash equivalents, beginning of period		1,028			13
Cash and cash equivalents, end of period	$	3,466		$	7

See notes to consolidated financial statements.

F-4

PLAINS EXPLORATION & PRODUCTION COMPANY

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited)

(in thousands of dollars)

	Three Months Ended June 30,						Six Months Ended June 30,
	2003			2002			2003			2002
Net Income	$	7,230		$	8,218		$	28,157		$	14,082
Other Comprehensive Income (Loss)
Commodity hedging contracts, net of tax
Change in fair value		(19,130	)		(3,973	)		(32,021	)		(24,980	)
Reclassification adjustment for settled contracts		6,157			2,112			16,414			(59	)
Interest rate swap, net of tax		10			—			16			—
Minimum pension liability adjustment, net of tax		60			—			60			—
		(12,903	)		(1,861	)		(15,531	)		(25,039	)
Comprehensive Income (Loss)	$	(5,673	)	$	6,357		$	12,626		$	(10,957	)

See notes to consolidated financial statements.

F-5

PLAINS EXPLORATION & PRODUCTION COMPANY

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY (Unaudited)

(share and dollar amounts in thousands)

	Common Stock			Additional Paid-in Capital		Contribution Receivable			Retained Earnings		Accumulated Other Comprehensive Income			Total
	Shares	Amount
Balance at December 31, 2002	24,224	$	244	$	174,789	$	(510	)	$	12,155	$	(12,858	)	$	173,820
Net income	—		—		—		—			28,157		—			28,157
Contributions by Plains Resources Inc.	—		—				510					—			510
Issuance of common stock
Acquisition of 3TEC Energy Corporation	16,070		161		152,025		—			—		—			152,186
Other	1		—		9		—			—		—			9
Restricted stock awards
Deferred compensation	17		—		882		—			—		—			882
Other comprehensive income	—		—		—		—			—		(15,531	)		(15,531	)
Balance at June 30, 2003	40,312	$	405	$	327,705	$	—		$	40,312	$	(28,389	)	$	340,033

See notes to consolidated financial statements.

F-6

PLAINS EXPLORATION & PRODUCTION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

Note 1—Organization and Significant Accounting Policies

Organization

The consolidated financial statements of Plains Exploration & Production Company (“Plains”, “PXP”, “us”, “our”, or “we”) include the accounts of our wholly-owned subsidiaries. We are an independent energy company engaged in the “upstream” oil and gas business of acquiring, exploiting, developing, exploring for and producing oil and gas. Our activities are all located in the United States.

Under the terms of a Master Separation Agreement between us and Plains Resources Inc. (“Plains Resources”), on July 3, 2002 Plains Resources contributed to us: (i) 100% of the capital stock of its wholly-owned subsidiaries that owned oil and gas properties offshore California and in Illinois; and (ii) all amounts payable to it by us and our subsidiary companies (the “reorganization”). In September 2002 we were converted from a limited partnership to a Delaware corporation and capitalized with 24.2 million shares of common stock, all of which were owned by Plains Resources. On December 18, 2002 Plains Resources distributed 24.1 million of the issued and outstanding shares of our common stock to its stockholders (the “spin-off”) and contributed the remaining 0.1 million shares to us.

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

These financial statements include allocations of direct and indirect corporate and administrative costs of Plains Resources made prior to the reorganization. The methods by which such costs were estimated and allocated to us were deemed reasonable by Plains Resources’ management; however, such allocations and estimates are not necessarily indicative of the costs and expenses that would have been incurred had we operated as a separate entity. Allocations of such costs are considered to be related party transactions and are discussed in Note 5.

These consolidated financial statements and related notes present our consolidated financial position as of June 30, 2003 and December 31, 2002, the results of our operations and our comprehensive income for the six months ended June 30, 2003 and 2002, our cash flows for the six months ended June 30, 2003 and 2002 and the changes in our stockholders’ equity for the six months ended June 30, 2003. All adjustments, consisting only of normal recurring adjustments, that in the opinion of management were necessary for a fair statement of the results for the interim periods, have been reflected. All significant intercompany transactions have been eliminated. Certain reclassifications have been made to prior year statements to conform to the current year presentation. The results for the six months ended June 30, 2003, are not necessarily indicative of the final results to be expected for the full year.

These financial statements have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (SEC) regarding interim financial reporting. Accordingly, they do not include all of the information and notes required by accounting principles generally accepted in the United States of America for complete financial statements and should be read in conjunction with the audited consolidated financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2002.

Accounting Policies

Asset Retirement Obligations. Effective January 1, 2003 we adopted Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations” (SFAS 143). SFAS 143 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,

F-7

statute, ordinance or contract. When the liability is initially recorded, the entity is required to capitalize the retirement cost of the related long-lived asset. Each period the liability is accreted to its then present value, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized. In prior periods we included estimated future costs of abandonment and dismantlement in our full cost amortization base and these costs were amortized as a component of our depletion expense.

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 does not impact our cash flows.

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

	Six Months Ended June 30,
	2003			2002
				Pro forma
Asset retirement obligation—beginning of period	$	26,540		$	21,278
Liabilities incurred		5,014
Accretion expense		1,176			932
Asset retirement costs incurred		(143	)
Asset retirement obligation—end of period	$	32,587	(1)	$	22,210

(1) $1,176 included in current liabilities.

The following table illustrates on a pro forma basis the effect on our net income and earnings per share as if SFAS 143 had been applied during the six months ended June 30, 2002 (thousands of dollars, except per share data):

	Pro forma Six Months Ended June 30, 2002
Net income—as reported	$	14,082
Adjustment for effect of change in accounting that is retroactively applied, net of tax		498
Pro forma net income	$	14,580
Earnings per share:
Basic—as reported	$	0.58
Adjustment for effect of change in accounting that is retroactively applied, net of tax		0.02
Basic—pro forma	$	0.60
Diluted—as reported	$	0.58
Adjustment for effect of change in accounting that is retroactively applied, net of tax		0.02
Diluted—pro forma	$	0.60

F-8

Stock-based Employee Compensation.    Statement of Financial Accounting Standards No. 123 “Accounting for Stock-Based Compensation” (SFAS 123) established financial accounting and reporting standards for stock-based employee compensation. SFAS 123 defines a fair value based method of accounting for an employee stock option or similar equity instrument. SFAS 123 also allows an entity to continue to measure compensation cost for those instruments using the intrinsic value-based method of accounting prescribed by Accounting Principles Bulletin No. 25 “Accounting for Stock Issued to Employees” (APB 25). We have elected to follow APB 25 and related interpretations in accounting for our stock-based employee compensation. The compensation expense recorded under APB 25 for our stock appreciation rights and restricted stock awards is the same as that determined under SFAS 123.

Earnings Per Share.    In September 2002 we were capitalized with 24,200,000 shares of common stock, all of which were owned by Plains Resources. In accordance with SEC Staff Accounting Bulletin No. 98, this capitalization has been retroactively reflected for purposes for calculating earnings per share for the six months ended June 30, 2002. The weighted average shares outstanding for computing both basic and diluted earnings per share was 24,200,000 shares for such period in 2002.

For the six months ended June 30, 2003 the weighted average shares outstanding for computing basic and diluted earnings per share were 26,414,000 and 26,682,000, respectively. The weighted average shares outstanding for computing diluted earnings per share in 2003 include the effect of unvested restricted stock and restricted stock units. In computing EPS, no adjustments were made to reported net income.

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

Inventory.    Oil inventories are carried at the lower of the cost to produce or market value. Reinjected gas inventories are carried at the lower of cost 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):

	June 30, 2003		December 31, 2002
Oil	$	776	$	730
Reinjected gas		1,812		—
Materials and supplies		5,118		4,468
	$	7,706	$	5,198

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

	June 30, 2003		December 31, 2002
Land	$	8,853	$	8,853
Commodity hedging contracts		712		1,432
Debt issue costs, net		8,759		5,485
Other		292		3,159
	$	18,616	$	18,929

F-9

Recent Accounting Pronouncements.    The Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards No. 149 “Amendment of Statement 133 on Derivative Instruments and Hedging Activities” (SFAS 149) on April 30, 2003. SFAS 149 amends and clarifies accounting for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities under SFAS No. 133. The statement is effective for contracts entered into or modified after June 30, 2003 and for hedging relationships designated after June 30, 2003. The adoption of SFAS No. 149 will have no effect on either our financial position or results of operations.

In May 2003, the FASB issued Statement No. 150 “Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity.” (SFAS 150). SFAS 150 establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. SFAS 150 is effective for financial instruments entered into or modified after May 31, 2003, and otherwise is effective at the beginning of the first interim period beginning after June 15, 2003. The adoption of SFAS 150 will not have an impact on our financial statements.

Statement of Financial Accounting Standards No. 141, Business Combinations (SFAS 141) and Statement of Financial Accounting Standards, No. 142, Goodwill and Intangible Assets (SFAS 142) were issued by the FASB in June 2001 and became effective for us on July 1, 2001 and January 1, 2002, respectively. SFAS 141 requires all business combinations initiated after June 30, 2001 to be accounted for using the purchase method. Additionally, SFAS 141 requires companies to disaggregate and report separately from goodwill certain intangible assets. SFAS 142 establishes new guidelines for accounting for goodwill and other intangible assets. Under SFAS 142, goodwill and certain other intangible assets are not amortized, but rather are reviewed annually for impairment. The FASB, the SEC and others continue to discuss the appropriate application of SFAS 141 and 142 to oil and gas mineral rights held under lease and other contractual arrangements representing the right to extract such reserves. Depending on the outcome of such discussions, these oil and gas mineral rights held under lease and other contractual arrangements representing the right to extract such reserves for both undeveloped and developed leaseholds may be classified separately from oil and gas properties, as intangible assets on our balance sheets. In addition, the disclosures required by SFAS 141 and 142 relative to intangibles would be included in the notes to financial statements. Historically, we, like many other oil and gas companies, have included these oil and gas mineral rights held under lease and other contractual arrangements representing the right to extract such reserves as part of the oil and gas properties, even after SFAS 141 and 142 became effective.

As applied to companies like us that have adopted full cost accounting for oil and gas activities, we understand that this interpretation of SFAS 141 and 142 would only affect our balance sheet classification of proved oil and gas leaseholds acquired after June 30, 2001 and our unproved oil and gas leaseholds. Our results of operations and cash flows would not be affected, since these oil and gas mineral rights held under lease and other contractual arrangements representing the right to extract such reserves would continue to be amortized in accordance with full cost accounting rules.

As of June 30, 2003, we had undeveloped leaseholds of approximately $74 million that would be classified on our balance sheet as “intangible undeveloped leasehold” and developed leaseholds of an estimated $256 million that would be classified as “intangible developed leasehold” if we applied the interpretations currently being discussed. The amounts that would be subject to this classification included in our historical balance sheet prior to the acquisition of 3TEC is not material.

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

Note 2—Acquisition of 3TEC Energy Corporation

On June 4, 2003 we acquired 3TEC (the “merger”), for approximately $312.9 million in cash and common stock plus $90.0 million to retire 3TEC’s outstanding debt. In the transaction, each 3TEC common share was converted in to 0.85 of a share of our common stock and $8.50 in cash. In connection with the merger, we paid

F-10

cash consideration to the common shareholders of approximately $152.4 million and issued 15.3 million shares. In addition, we paid cash consideration of $8.3 million and issued 0.8 million common shares to redeem outstanding warrants. The cash portion of the purchase price was funded by the issuance of $75.0 million of senior subordinated notes and amounts borrowed under our revolving credit facility. We have accounted for the acquisition of 3TEC as a purchase with effect from June 1, 2003.

The calculation of the purchase price and the preliminary allocation to assets and liabilities as of June 4, 2003 are shown below. The average PXP common stock price is based on the average closing price of PXP common stock during the five business days commencing two days before the merger was announced. The purchase price allocation is preliminary because certain items such as the determination of the final tax bases and fair value of the assets and liabilities as of the acquisition date have not been completed.

	(in thousands, except share price)
Calculation and preliminary allocation of purchase price:
Shares of PXP common stock issued to 3TEC stockholders		16,070
Average PXP stock price	$	9.47
Fair value of common stock issued	$	152,186
Cash to 3TEC stockholders and warrantholders		160,720
3TEC debt retired in the merger (including accrued interest)		90,065
Merger costs incurred by PXP		4,269
Total purchase price	$	407,240
Fair value of assets acquired and liabilities assumed:
Current assets	$	24,773
Oil and gas properties and equipment
Subject to amortization		267,765
Not subject to amortization		61,116
Other properties and equipment		218
Goodwill		143,962
Current liabilities		(47,893	)
Deferred tax liability related to the merger		(42,447	)
Other long-term liabilities		(254	)
Total purchase price	$	407,240

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

Pro Forma Information

The following unaudited pro forma information for the six months ended June 30, 2003 and 2002 has been prepared based on our historical consolidated statements of income and the historical consolidated statements of income of 3TEC. Such pro forma information for 2003 and 2002 assumes the merger and the issuance of $75.0 million of 8.75% senior subordinated notes on May 31, 2003 occurred on January 1, 2003 and January 1, 2002,

F-11

respectively. Such pro forma information for 2002 also assumes the following 2002 transactions occurred on January 1, 2002: (i) the reorganization and spin-off, discussed in Note 1; and (ii) the July 3, 2002 issuance of $200.0 million of 8.75% senior subordinated notes, discussed in Note 4.

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

	Pro forma Six Months Ended June 30,
(in thousands, except per share data)	2003		2002
Revenues	$	187,757	$	132,212
Income from operations		81,480		47,855
Income before the cumulative effect of accounting change		17,771		16,456
Net income		30,095		16,456
Earnings per share
Basic
Before cumulative effect of accounting change	$	0.44	$	0.41
Cumulative effect of accounting change		0.31		—
Net income		0.75		0.41
Diluted
Before cumulative effect of accounting change	$	0.44	$	0.41
Cumulative effect of accounting change		0.31		—
Net income		0.75		0.41
Weighted average shares outstanding
Basic		40,087		40,263
Diluted		40,355		40,271

Prior to the merger, 3TEC held certain derivative instruments that had not been qualified for hedge accounting under the provisions of SFAS 133. Accordingly, unrealized gains and losses with respect to such derivatives were recognized currently in 3TEC’s results of operations and are reflected in this manner in the proforma information presented above. Unrealized gains (losses) included in 3TEC’s results of operations totaled ($22.4) million and ($12.4) million for the six months ended June 30, 2003 and 2002, respectively. At the time of the merger such derivative instruments were assigned to us and in accordance with the provisions of SFAS 133 were qualified for hedge accounting.

Note 3—Derivative Instruments and Hedging Activities

We have entered into various derivative instruments to reduce our exposure to fluctuations in the market price of oil and gas. The derivative instruments consist primarily of swap and option contracts entered into with financial institutions. Derivative instruments are accounted for in accordance with SFAS No. 133 “Accounting for Derivative Instruments and Hedging Activities” as amended by SFAS 137, SFAS 138 and SFAS 149 (SFAS 133). All derivative instruments are recorded on the balance sheet at fair value. If the derivative does not qualify as a hedge or is not designated as a hedge, the gain or loss on the derivative is recognized currently in earnings. If the derivative qualifies for hedge accounting, the unrealized gain or loss on the derivative is deferred in Accumulated Other Comprehensive Income (OCI), a component of Stockholder’s Equity. At June 30, 2003 all open positions qualified for hedge accounting.

Unrealized gains and losses on hedging instruments reflected in OCI, and adjustments to carrying amounts on hedged volumes, are included in oil and gas revenues in the period that the related volumes are delivered. Gains and losses on hedging instruments that represent hedge ineffectiveness, as well as any amounts excluded from the assessment of hedge effectiveness, are recognized currently in oil and gas revenues.

F-12

At June 30, 2003, OCI consisted of $47.5 million ($28.1 million net of tax) of unrealized losses on our oil and gas hedging instruments, $0.3 million ($0.2 million, net of tax) loss related to our interest rate swap and $0.1 million ($0.1 million, net of tax) related to pension liabilities. The assets and liabilities related to our open commodity hedging instruments were included in current assets ($1.7 million), other assets ($0.7 million), current liabilities ($39.5 million), other long-term liabilities ($10.4 million) and deferred income taxes (a tax benefit of $19.4 million).

During the six months ended June 30, 2003, $27.7 million ($16.4 million net of tax) in losses from the settlement of oil and gas hedging instruments were reclassified from OCI and charged to income as a reduction of oil and gas revenues. As of June 30, 2003, $37.9 million ($22.5 million, net of tax) of deferred net losses on oil and gas hedging instruments recorded in OCI are expected to be reclassified to earnings during the next twelve-month period.

At June 30, 2003 we had the following open hedge positions:

	Bbls / MMBtu Per Day
	2003	2004	2005
Crude Oil Swaps
Average price $24.10 per Bbl	20,250	—	—
Average price $23.89 per Bbl	—	18,500	—
Average price $23.57 per Bbl	—	—	5,000
Natural Gas Swaps
Average price $5.02 per MMBtu	50,000	—	—
Average price $4.45 per MMBtu	—	20,000	—
Natural Gas Costless Collars	—	20,000	—
Floor price of $4.00 per MMBtu
Cap price of $5.15 per MMBtu

Our average realized price for oil is sensitive to changes in location and quality differential adjustments as set forth in our oil sales contracts. At June 30, 2003 we had basis risk swap contracts on our Illinois Basin production through December 31, 2003. The swaps fix the location differential portion of 2,600 barrels per day at $0.39 per barrel for the third quarter of 2003, and 2,500 barrels per day at $0.31 per barrel for the fourth quarter of 2003.

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.

We utilize interest rate swaps to manage the interest rate exposure on our long-term debt. We currently have an interest rate swap agreement that expires in October 2004 that fixes the interest rate on $7.5 million of borrowings under our credit facility at 3.9% plus the LIBOR margin set forth in the credit facility (1.625% at June 30, 2003).

Note 4—Long-Term Debt

At June 30, 2003 long-term debt consisted of:

	Current		Long-Term
Revolving credit facility	$	—	$	233,000
8.75% senior subordinated notes, including unamortized premium of $2.0 million		—		276,991
Other		511		511
	$	511	$	510,502

F-13

Revolving credit facility

On May 30, 2003, $30.1 million in borrowings outstanding under our $300.0 million revolving credit facility were repaid and the facility was terminated.

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

Amounts borrowed under the credit facility bear an annual interest rate, at our election, equal to either: (i) the Eurodollar rate, plus from 1.375% to 2.00%; or (ii) the greatest of (1) the prime rate, as determined by JP Morgan Chase Bank, (2) the certificate of deposit rate, plus 1.0%, or (3) the federal funds rate, plus 0.5%; plus an additional 0.125% to 0.75% for each of (1)-(3). The amount of interest payable on outstanding borrowings is based on (1) the utilization rate as a percentage of the total amount of funds borrowed under the credit facility to the borrowing base and (2) our long-term debt rating. Commitment fees and letter of credit fees under the credit facility are based on the utilization rate and long-term debt rating. Commitment fees range from 0.375% to 0.5% of the unused portion of the borrowing base. Letter of credit fees range from 1.375% to 2.0%. The issuer of any letter of credit receives an issuing fee of 0.125% of the undrawn amount.

The credit facility contains negative covenants that limit our ability, as well as the ability of our subsidiaries, among other things, to incur additional debt, pay dividends on stock, make distributions of cash or property, change the nature of our business or operations, redeem stock or redeem subordinated debt, make investments, create liens, enter into leases, sell assets, sell capital stock of subsidiaries, create subsidiaries, guarantee other indebtedness, enter into agreements that restrict dividends from subsidiaries, enter into certain types of swap agreements, enter into gas imbalance or take-or-pay arrangements, merge or consolidate and enter into transactions with affiliates. In addition, the credit facility requires us to maintain a current ratio, which includes availability, of at least 1.0 to 1.0 and a minimum tangible net worth (as defined). At June 30, 2003, we were in compliance with the covenants contained in our credit facility and could have borrowed the full amount available under the credit facility.

8.75% senior subordinated notes

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

At June 30, 2003 we had $275.0 million principal amount of 8.75% notes outstanding. The 8.75% notes are our unsecured general obligations, are subordinated in right of payment to all of our existing and future senior indebtedness and are jointly and severally guaranteed on a full, unconditional basis by all of our existing and future domestic restricted subsidiaries. The indenture governing the 8.75% notes contains covenants that limit our ability, as well as the ability of our subsidiaries, among other things, to incur additional indebtedness, make certain investments, make restricted payments, sell assets, enter into agreements containing dividends and other payment restrictions affecting subsidiaries, enter into transactions with affiliates, create liens, merge, consolidate and transfer assets and enter into different lines of business. In the event of a change of control, as defined in the indenture, we will be required to make an offer to repurchase the notes at 101% of the principal amount thereof, plus accrued and unpaid interest to the date of the repurchase. The indenture governing the 8.75% notes permitted the spin-off and the spin-off did not, in itself, constitute a change of control for purposes of the indenture. The merger did not constitute a change of control for purposes of the indenture.

F-14

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.

Note 5—Related Party Transactions

In connection with the reorganization and the spin-off we entered into certain agreements with Plains Resources, including a master separation agreement; an intellectual property agreement; the Plains Exploration & Production transition services agreement; the Plains Resources transition services agreement; and a technical services agreement. For the six months ended June 30, 2003 we billed Plains Resources $0.3 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.

We charter private aircraft from Gulf Coast Aviation Inc. (“Gulf Coast”), a corporation that from time-to-time leases aircraft owned by our Chief Executive Officer. In the first six months of 2003, we paid Gulf Coast $0.6 million in connection with charter services in which our Chief Executive Officer’s aircraft were used. The charter services were arranged through arms-length dealings and the rates were market-based.

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 first six months of 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, we were allocated direct and indirect corporate and administrative costs of Plains Resources. Such costs for the first six months of 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.

Plains All American Pipeline, L.P. (“PAA”), a publicly-traded master limited partnership, is an affiliate of Plains Resources. Certain of our officers and directors are officers and directors of Plains Resources. PAA is the exclusive marketer/purchaser for all of our equity oil production, including the royalty share of production, from properties owned prior to the merger. The marketing agreement provides that PAA will purchase for resale at market prices all of our equity oil production for which PAA charges a fee of $0.20 per barrel. During the six months ended June 30, 2003 and 2002, the following amounts were recorded with respect to such transactions (in thousands of dollars).

	Six Months Ended June 30,
	2003		2002
Sales of oil to PAA
PXP’s share	$	119,593	$	81,676
Royalty owners’ share		22,785		14,935
	$	142,378	$	96,611
Charges for PAA marketing fees	$	857	$	797

F-15

Note 6—Commitments and Contingencies

In the ordinary course of business, we are a claimant and/or defendant in various legal proceedings. In particular, we are required to indemnify Plains Resources for any liabilities it incurs in connection with a lawsuit it (through a predecessor interest in Stocker Resources, Inc.) has regarding an electric services contract with Commonwealth Energy Corporation. In this lawsuit, Plains Resources is seeking a declaratory judgment that it was entitled to terminate the contract and that Commonwealth has no basis for proceeding against a related $1.5 million performance bond. In a countersuit against Plains Resources, Commonwealth is seeking unspecified damages. The two cases have been consolidated and set for trial in December 2003. We understand that Plains Resources intends to defend its rights vigorously in this matter. 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.

Note 7—Supplemental Cash Flow Information

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

	Six Months Ended June 30,
	2003		2002
Cash payments for interest	$	741	$	—
Cash payments for taxes	$	2,802	$	326

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

Common stock issued	$	152,186
Current liabilities assumed		47,893
Other long-term liabilities assumed		254
Deferred income tax liability		42,447
	$	242,780

Note 8—Consolidating Financial Statements

We and Plains E&P Company are the co-issuers of the 8.75% notes discussed in Note 4. The 8.75% notes are jointly and severally guaranteed on a full and unconditional basis by 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

• the Company on a consolidated basis.

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

F-16

PLAINS EXPLORATION & PRODUCTION COMPANY

CONSOLIDATING BALANCE SHEET (Unaudited)

JUNE 30, 2003

(in thousands)

	Issuer			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
ASSETS
Current Assets
Cash and cash equivalents	$	1,003		$	2,463		$	—		$	3,466
Accounts receivable and other current assets		24,650			26,847			—			51,497
Commodity hedging contracts		1,167			508			—			1,675
Inventories		6,032			1,674			—			7,706
		32,852			31,492			—			64,344
Property and Equipment, at cost
Oil and natural gas properties—full cost method
Subject to amortization		549,920			428,282			—			978,202
Not subject to amortization		21,746			63,522			—			85,268
Other property and equipment		2,745			420			—			3,165
		574,411			492,224			—			1,066,635
Less allowance for depreciation, depletion and amortization		(57,864	)		(97,132	)		—			(154,996	)
		516,547			395,092			—			911,639
Goodwill		—			143,962			—			143,962
Investment in and Advances to Subsidiaries		451,823			—			(451,823	)		—
Other Assets		19,207			(591	)		—			18,616
	$	1,020,429		$	569,955		$	(451,823	)	$	1,138,561
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts payable and other current liabilities	$	60,070		$	39,483		$	—		$	99,553
Commodity hedging contracts		16,648			23,100			—			39,748
Current maturities on long-term debt		511			—			—			511
		77,229			62,583			—			139,812
Long-Term Debt		510,502			—			—			510,502
Asset Retirement Obligation		16,307			15,104			—			31,411
Other Long-Term Liabilities		8,761			8,816			—			17,577
Payable to Parent		—			484,191			(484,191	)		—
Deferred Income Taxes		67,597			31,629			—			99,226
Stockholders’ Equity
Stockholders’ equity		368,422			(15,300	)		15,300			368,422
Accumulated other comprehensive income		(28,389	)		(17,068	)		17,068			(28,389	)
		340,033			(32,368	)		32,368			340,033
	$	1,020,429		$	569,955		$	(451,823	)	$	1,138,561

F-17

PLAINS EXPLORATION & PRODUCTION COMPANY

CONSOLIDATING BALANCE SHEET

DECEMBER 31, 2002

(in thousands)

	Issuer			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
ASSETS
Current Assets
Cash and cash equivalents	$	1,004		$	24		$	—		$	1,028
Accounts receivable and other current assets		21,273			8,646			—			29,919
Commodity hedging contracts		2,594			—			—			2,594
Inventories		4,009			1,189			—			5,198
		28,880			9,859			—			38,739
Property and Equipment, at cost
Oil and natural gas properties—full cost method
Subject to amortization		507,501			121,953			—			629,454
Not subject to amortization		17,621			12,424			—			30,045
Other property and equipment		2,008			199			—			2,207
		527,130			134,576			—			661,706
Less allowance for depreciation, depletion and amortization		(75,007	)		(93,487	)		—			(168,494	)
		452,123			41,089			—			493,212
Investment in and Advances to Subsidiaries		33,243						(33,243	)		—
Other Assets		19,221			(292	)		—			18,929
	$	533,467		$	50,656		$	(33,243	)	$	550,880
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts payable and other current liabilities	$	50,996		$	10,096		$	—		$	61,092
Commodity hedging contracts		15,188			9,384			—			24,572
Current maturities on long-term debt		511			—			—			511
		66,695			19,480			—			86,175
Long-Term Debt		233,166			—			—			233,166
Other Long-Term Liabilities		4,101			2,202			—			6,303
Payable to Parent		—			61,179			(61,179	)		—
Deferred Income Taxes		55,685			(4,269	)		—			51,416
Stockholders’ Equity
Stockholders’ equity		186,678			(22,240	)		22,240			186,678
Accumulated other comprehensive income		(12,858	)		(5,696	)		5,696			(12,858	)
		173,820			(27,936	)		27,936			173,820
	$	533,467		$	50,656		$	(33,243	)	$	550,880

F-18

PLAINS EXPLORATION & PRODUCTION COMPANY

CONSOLIDATING STATEMENTS OF INCOME (Unaudited)

SIX MONTHS ENDED JUNE 30, 2003

(in thousands)

	Issuer			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
Revenues
Oil sales to Plains All American Pipeline, L.P.	$	79,921		$	39,672		$	—		$	119,593
Other oil sales		—			1,636			—			1,636
Gas sales		8,229			12,000			—			20,229
Hedging		(16,122	)		(11,581	)		—			(27,703	)
Other operating revenues		—			407			—			407
		72,028			42,134			—			114,162
Costs and Expenses
Production expenses		23,286			19,065			—			42,351
Production and ad valorem taxes		1,904			952			—			2,856
Transportation expenses		—			327			—			327
General and administrative
G&A, excluding items below		7,746			1,011			—			8,757
Stock appreciation rights		2,647			—			—			2,647
Merger related costs		1,097			—						1,097
Depreciation, depletion and amortization		10,934			6,934			—			17,868
Accretion of asset retirement obligation		718			458			—			1,176
		48,332			28,747			—			77,079
Income from Operations		23,696			13,387			—			37,083
Other Income (Expense)
Equity in earnings of subsidiaries		6,939			—			(6,939	)		—
Interest expense		(7,374	)		(2,820	)		—			(10,194	)
Interest and other income		(176	)		9			—			(167	)
Income Before Income Taxes and Cumulative Effect of Accounting Change		23,085			10,576			(6,939	)		26,722
Income tax expense
Current		870			(3,299	)		—			(2,429	)
Deferred		(7,477	)		(983	)		—			(8,460	)
Income Before Cumulative Effect of Accounting Change		16,478			6,294			(6,939	)		15,833
Cumulative effect of accounting change, net of tax benefit		11,679			645			—			12,324
Net Income	$	28,157		$	6,939		$	(6,939	)	$	28,157

F-19

PLAINS EXPLORATION & PRODUCTION COMPANY

CONSOLIDATING STATEMENTS OF INCOME (Unaudited)

SIX MONTHS ENDED JUNE 30, 2002

(in thousands)

	Issuer			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
Revenues
Oil sales to Plains All American Pipeline, L.P.	$	60,718		$	20,958		$	—		$	81,676
Gas sales		4,578			—			—			4,578
Hedging		(698	)		244			—			(454	)
Other operating revenues		—			13			—			13
		64,598			21,215			—			85,813
Costs and Expenses
Production expenses		21,952			10,802			—			32,754
Production and ad valorem taxes		2,197			131			—			2,328
General and administrative		3,945			781			—			4,726
Depreciation, depletion and amortization		9,985			3,522			—			13,507
		38,079			15,236			—			53,315
Income from Operations		26,519			5,979			—			32,498
Other Income (Expense)
Equity in earnings of subsidiaries		1,590			—			(1,590	)		—
Interest expense		(6,003	)		(3,415	)		—			(9,418	)
Interest and other income		23			13			—			36
Income Before Income Taxes		22,129			2,577			(1,590	)		23,116
Income tax expense
Current		(2,886	)		(1,132	)		—			(4,018	)
Deferred		(5,161	)		145			—			(5,016	)
Net Income	$	14,082		$	1,590		$	(1,590	)	$	14,082

F-20

PLAINS EXPLORATION & PRODUCTION COMPANY

CONSOLIDATING STATEMENTS OF CASH FLOWS (Unaudited)

SIX MONTHS ENDED JUNE 30, 2003

(in thousands of dollars)

	Issuer			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	28,157		$	6,939		$	(6,939	)	$	28,157
Items not affecting cash flows from operating activities
Depreciation, depletion and amortization		10,934			6,934			—			17,868
Accretion of asset retirement obligation		718			458			—			1,176
Equity in earnings of subsidiaries		(6,939	)		—			6,939			—
Deferred income taxes		7,478			982			—			8,460
Cumulative effect of adoption of accounting change		(11,679	)		(645	)		—			(12,324	)
Noncash compensation		2,685			—			—			2,685
Other noncash items		377			—			—			377
Change in assets and liabilities from operating activities					—
Accounts receivable and other assets		(693	)		3,740			—			3,047
Inventories		(2,024	)		(273	)		—			(2,297	)
Accounts payable and other liabilities		9,350			(28,585	)		—			(19,235	)
Net cash provided by (used in) operating activities		38,364			(10,450	)		—			27,914
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to oil and gas properties		(37,275	)		(9,505	)		—			(46,780	)
Acquisition of 3TEC Energy Corporation, net of cash acquired		—			(251,883	)		—			(251,883	)
Other		(737	)		(3	)		—			(740	)
Net cash used in investing activities		(38,012	)		(261,391	)		—			(299,403	)
CASH FLOWS FROM FINANCING ACTIVITIES
Change in revolving credit facility		197,200			—			—			197,200
Proceeds from debt issuance		80,061			—			—			80,061
Debt issuance costs		(4,069	)		—			—			(4,069	)
Advances/investments with affiliates		(274,279	)		274,279			—			—
Receipts from (payments to) Plains Resources Inc.		510			—			—			510
Other		225			—			—			225
Net cash provided by (used in) financing activities		(352	)		274,279			—			273,927
Net increase (decrease) in cash and cash equivalents		—			2,438			—			2,438
Cash and cash equivalents, beginning of period		1,004			24			—			1,028
Cash and cash equivalents, end of period	$	1,004		$	2,462		$	—		$	3,466

F-21

PLAINS EXPLORATION & PRODUCTION COMPANY

CONSOLIDATING STATEMENTS OF CASH FLOWS (Unaudited)

SIX MONTHS ENDED JUNE 30, 2002

(in thousands of dollars)

	Issuer			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	14,082		$	1,590		$	(1,590	)	$	14,082
Items not affecting cash flows from operating activities
Depreciation, depletion and amortization		9,985			3,522			—			13,507
Equity in earnings of subsidiaries		(1,590	)		—			1,590			—
Deferred income taxes		5,161			(145	)		—			5,016
Other noncash items		277			47						324
Change in assets and liabilities from operating activities
Accounts receivable and other assets		(5,833	)		2,994			—			(2,839	)
Inventories		(244	)		(140	)		—			(384	)
Accounts payable and other liabilities		(2,990	)		(6,940	)		—			(9,930	)
Net cash provided by operating activities		18,848			928			—			19,776
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to oil and gas properties		(34,902	)		(7,439	)		—			(42,341	)
Additions to other property and equipment		(15	)		(2	)		—			(17	)
Net cash used in investing activities		(34,917	)		(7,441	)		—			(42,358	)
CASH FLOWS FROM FINANCING ACTIVITIES
Receipts from Plains Resources Inc.		16,058			6,518			—			22,576
Net cash provided by financing activities		16,058			6,518			—			22,576
Net increase (decrease) in cash and cash equivalents		(11	)		5			—			(6	)
Cash and cash equivalents, beginning of period		11			2			—			13
Cash and cash equivalents, end of period	$	—		$	7		$	—		$	7

F-22

REPORT OF INDEPENDENT ACCOUNTANTS

To the Board of Directors of Plains Exploration & Production Company

In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of Plains Exploration & Production Company and its subsidiaries at December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2002, in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

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

PricewaterhouseCoopers LLP

Houston, Texas

March 10, 2003

F-23

PLAINS EXPLORATION & PRODUCTION COMPANY

CONSOLIDATED BALANCE SHEETS

(in thousands of dollars)

	December 31,
	2002			2001
ASSETS
Current Assets
Cash and cash equivalents	$	1,028		$	13
Accounts receivable—Plains All American Pipeline, L.P.		22,943			12,331
Other accounts receivable		5,925			3,091
Commodity hedging contracts		2,594			21,787
Inventories		5,198			4,629
Other current assets		1,051			960
		38,739			42,811
Property and Equipment, at cost
Oil and natural gas properties—full cost method
Subject to amortization		629,454			561,034
Not subject to amortization		30,045			33,371
Other property and equipment		2,207			1,516
		661,706			595,921
Less allowance for depreciation, depletion and amortization		(168,494	)		(140,804	)
		493,212			455,117
Other Assets		18,929			18,827
	$	550,880		$	516,755
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts payable and other current liabilities	$	38,577		$	34,056
Commodity hedging contracts		24,572			—
Royalties payable		11,873			7,271
Interest payable		9,207			41
Payable to Plains Resources Inc.		1,435			—
Current maturities of long-term debt		511			511
		86,175			41,879
Payable to Plains Resources Inc.		—			235,161
Long-Term Debt
8.75% Senior Subordinated Notes		196,855			—
Revolving credit facility		35,800			—
Other		511			1,022
		233,166			1,022
Other Long-Term Liabilities		6,303			1,413
Deferred Income Taxes		51,416			57,193
Commitments and Contingencies (Note 8)
Stockholders’ Equity
Common stock, $0.01 par value, 100,000,000 shares authorized, 24,224,448 shares issued and outstanding		244			—
Additional paid-in capital		174,279			—
Retained earnings		12,155			—
Combined owner’s equity		—			164,203
Accumulated other comprehensive income		(12,858	)		15,884
		173,820			180,087
	$	550,880		$	516,755

See notes to consolidated financial statements.

F-24

PLAINS EXPLORATION & PRODUCTION COMPANY

CONSOLIDATED STATEMENTS OF INCOME

(in thousands of dollars, except per share data)

	Year Ended December 31,
	2002			2001			2000
Revenues
Oil sales to Plains All American Pipeline, L.P.	$	178,038		$	174,895		$	126,434
Gas sales		10,299			28,771			16,017
Other operating revenues		226			473			—
		188,563			204,139			142,451
Costs and Expenses
Production expenses		78,451			63,795			56,228
General and administrative
Stock appreciation rights		3,653			—			—
Spin-off costs		777			—			—
Other		10,756			10,210			6,308
Depreciation, depletion and amortization		30,359			24,105			18,859
		123,996			98,110			81,395
Income from Operations		64,567			106,029			61,056
Other Income (Expense)
Expenses of terminated public equity offering		(2,395	)		—			—
Interest expense		(19,377	)		(17,411	)		(15,885	)
Interest and other income		174			463			343
Income Before Income Taxes and Cumulative Effect of Accounting Change		42,969			89,081			45,514
Income tax expense
Current		(6,353	)		(6,014	)		(2,431	)
Deferred		(10,379	)		(28,374	)		(14,334	)
Income Before Cumulative Effect of Accounting Change		26,237			54,693			28,749
Cumulative effect of accounting change, net of tax benefit		—			(1,522	)		—
Net Income	$	26,237		$	53,171		$	28,749
Basic and Diluted Earnings Per Share
Income before cumulative effect of accounting change	$	1.08		$	2.26		$	1.19
Cumulative effect of accounting change		—			(0.06	)		—
Net income	$	1.08		$	2.20		$	1.19
Weighted Average Shares Outstanding
Basic		24,193			24,200			24,200
Diluted		24,201			24,200			24,200

See notes to consolidated financial statements.

F-25

PLAINS EXPLORATION & PRODUCTION COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands of dollars)

	Year Ended December 31,
	2002			2001			2000
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	26,237		$	53,171		$	28,749
Items not affecting cash flows from operating activities
Depreciation, depletion and amortization		30,359			24,105			18,859
Deferred income taxes		10,379			28,374			14,334
Cumulative effect of adoption of accounting change		—			1,522			—
Change in derivative fair value		—			1,055			—
Other noncash items		457			996			—
Change in assets and liabilities from operating activities
Accounts receivable and other assets		(11,964	)		9,197			7,597
Inventories		(576	)		(591	)		(195	)
Payable to Plains Resources Inc.		4,946			—			—
Accounts payable and other liabilities		18,988			(1,021	)		10,120
Net cash provided by operating activities		78,826			116,808			79,464
CASH FLOWS FROM INVESTING ACTIVITIES
Acquisition, exploration and development costs		(64,497	)		(125,753	)		(70,505	)
Additions to other property and equipment		(190	)		(127	)		(366	)
Proceeds from property sales		529			—			—
Net cash used in investing activities		(64,158	)		(125,880	)		(70,871	)
CASH FLOWS FROM FINANCING ACTIVITIES
Principal payments of long-term debt		(511	)		(511	)		(511	)
Change in revolving credit facility		35,800			—			—
Proceeds from debt issuance		196,752			—			—
Debt issuance costs		(5,936	)		—			—
Contribution from Plains Resources Inc.		52,200			—			—
Distribution to Plains Resources Inc.		(311,964	)		—			—
Receipts from (payments to) Plains Resources Inc.		20,363			9,060			(12,621	)
Other		(357	)		—			—
Net cash provided by (used in) financing activities		(13,653	)		8,549			(13,132	)
Net increase (decrease) in cash and cash equivalents		1,015			(523	)		(4,539	)
Cash and cash equivalents, beginning of period		13			536			5,075
Cash and cash equivalents, end of period	$	1,028		$	13		$	536

See notes to consolidated financial statements.

F-26

PLAINS EXPLORATION & PRODUCTION COMPANY

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(in thousands of dollars)

	Year Ended December 31,
	2002			2001			2000
Net Income	$	26,237		$	53,171		$	28,749
Other Comprehensive Income (Loss)
Commodity hedging contracts:
Cumulative effect of accounting change, net of taxes of $4,454		—			6,967			—
Change in fair value, net of taxes of $(24,970) and $7,634		(37,298	)		10,978			—
Reclassification adjustment for settled contracts, net of taxes of $(5,897) and $1,388		8,850			(2,061	)		—
Interest rate swap, net of tax benefit of $119		(178	)		—			—
Minimum pension liability adjustment, net of tax benefit of $77		(116	)		—			—
		(28,742	)		15,884			—
Comprehensive Income (Loss)	$	(2,505	)	$	69,055		$	28,749

See notes to consolidated financial statements.

F-27

PLAINS EXPLORATION & PRODUCTION COMPANY

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(share and dollar amounts in thousands)

	Combined Owner’s Equity			Common Stock				Additional Capital Paid-in			Contribution Receivable			Retained Earnings		Accumulated Other Comprehensive Income			Total
				Shares		Amount
Balance at December 31, 1999	$	82,283		—		$	—	$	—		$	—		$	—	$	—		$	82,283
Net income		28,749		—			—		—			—			—		—			28,749
Other comprehensive income		—		—			—		—			—			—		—			—
Balance at December 31, 2000		111,032		—			—		—			—			—		—			111,032
Net income		53,171		—			—		—			—			—		—			53,171
Other comprehensive income		—		—			—		—			—			—		15,884			15,884
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
Receivable		—		—			—		510			(510	)		—		—			—
Other		—		—			—		4,314			—			—		—			4,314
Spin-off by Plains Resources Inc.		—		(141	)		—		(4,335	)		—			—		—			(4,335	)
Restricted stock awards
Issuance of restricted stock		—		165			2		1,500			—			—		—			1,502
Deferred compensation		—		—			—		(1,470	)		—			—		—			(1,470	)
Other comprehensive income		—		—			—		—			—			—		(28,742	)		(28,742	)
Balance at December 31, 2002	$	—		24,224		$	244	$	174,789		$	(510	)	$	12,155	$	(12,858	)	$	173,820

See notes to consolidated financial statements.

F-28

PLAINS EXPLORATION & PRODUCTION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1—Organization and Significant Accounting Policies

Organization

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

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

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

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

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

In June 2002 we filed a registration statement on Form S-1 with the Securities and Exchange Commission 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 at 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 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 in cash capital contribution to us and transferred to us certain assets and

F-29

PLAINS EXPLORATION & PRODUCTION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

liabilities of Plains Resources ($4.3 million, net), primarily related to land, unproved oil and gas properties, office equipment and pension 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.

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 4.

Significant Accounting Policies

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

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

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

Cash and Cash Equivalents.    Cash and cash equivalents consist of all demand deposits and funds invested in highly liquid instruments with original maturities of three months or less. At December 31, 2002 and 2001, the

F-30

PLAINS EXPLORATION & PRODUCTION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

majority of cash and cash equivalents is concentrated in one institution and at times may exceed federally insured limits. We periodically assess the financial condition of the institution and believe that any possible credit risk is minimal.

Inventory.    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,
	2002		2001
Oil	$	730	$	428
Materials and supplies		4,468		4,201
	$	5,198	$	4,629

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

	December 31,
	2002		2001
Land	$	8,853	$	8,103
Commodity hedging contracts		1,432		5,627
Debt issue costs, net		5,485		—
Other		3,159		5,097
	$	18,929	$	18,827

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

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

Under the terms of a tax allocation agreement, our taxable income or loss prior to the spin-off is included in the consolidated income tax returns filed by Plains Resources. Each member of a consolidated group is jointly and severally liable for the federal income tax liability of each other member of the consolidated group. Accordingly, although this agreement allocates tax liabilities between us and Plains Resources during the period in which we are included in Plains Resources’ consolidated group, we could be liable if any federal tax liability is incurred, but not discharged, by any other member of Plains Resources’ consolidated group. In addition, to the extent Plains Resources’ net operating losses are used in the consolidated return to offset our taxable income 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. Such amount will be paid to Plains Resources in periods in which it makes federal income tax payments.

F-31

PLAINS EXPLORATION & PRODUCTION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Income tax obligations reflected in these financial statements are calculated assuming we filed a separate consolidated income tax return. Income taxes currently payable at December 31, 2001, which were forgiven in the reorganization, are included in Payable to Plains Resources in the consolidated balance sheet at December 31, 2001. At December 31, 2002 current liabilities and other long-term liabilities include $0.2 million and $3.2 million, respectively, of income taxes payable to Plains Resources with respect to periods subsequent to the reorganization and the reimbursement due Plains Resources with respect to state taxes and the utilization of net operating losses.

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

Derivative Financial Instruments (Hedging).    We utilize various derivative instruments to reduce our exposure to fluctuations in the market price of oil. The derivative instruments consist primarily of oil swap and option contracts entered into with financial institutions. See Note 2.

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

Earnings Per Share.    In September 2002 we were capitalized with 24,200,000 shares of common stock, all of which were owned by Plains Resources. In accordance with SEC Staff Accounting Bulletin No. 98, this capitalization has been retroactively reflected for purposes for calculating earnings per share for the years ended December 31, 2001 and 2000. The weighted average shares outstanding for computing both basic and diluted earnings per share was 24,200,000 shares for the years ended December 31, 2001 and 2000. For the year ended December 31, 2002 weighted average shares outstanding for computing basic and diluted earnings per share were 24,193,000 and 24,201,000, respectively. In computing EPS, no adjustments were made to reported net income, and no potential common stock existed during the periods.

Recent Accounting Pronouncements.    Statement of Accounting Standards, or SFAS, No. 143, “Accounting for Asset Retirement Obligations” becomes effective January 1, 2003. SFAS No. 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. 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. For all historical periods presented, we have included estimated future costs of abandonment and dismantlement in our full cost amortization base and these costs have been amortized as a component of our depletion expense.

We have completed our assessment of SFAS No. 143 and we estimate that at January 1, 2003 the present value of our future Asset Retirement Obligation (“ARO”) for oil and gas properties and equipment is approximately $26.5 million. We estimate that the cumulative effect of our adoption of SFAS No. 143 and the change in accounting principle will result in an increase in net income during the first quarter of 2003 of $20.2 million (reflecting a $30.8 million decrease in accumulated depreciation, depletion and amortization, partially offset by $10.6 million in accretion expense), $12.3 million net of taxes. We estimate that we will record a liability of $26.5 million and an asset of $15.9 million in connection with the adoption of SFAS 143. There will be no impact on our cash flows as a result of adopting SFAS No. 143.

In April 2002, SFAS No. 145, “Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13 and Technical Corrections,” was issued. SFAS 145 rescinds SFAS 4 and SFAS 64 related to classification of gains and losses on debt extinguishment such that most debt extinguishment gains and losses

F-32

PLAINS EXPLORATION & PRODUCTION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

will no longer be classified as extraordinary. SFAS 145 also amends SFAS 13 with respect to sales-leaseback transactions. The provisions of SFAS 145 have no effect on our financial statements.

In July 2002, SFAS No. 146, “Accounting For Costs Associated with Exit or Disposal Activities” was issued. SFAS 146 is effective for exit or disposal activities initiated after December 31, 2002 and does not require previously issued financial statements to be restated. We will account for exit or disposal activities initiated after December 31, 2002 in accordance with the provisions of SFAS 146.

In December 2002, SFAS No. 148, “Accounting for Stock-Based Compensation—Transition and Disclosure—an amendment of FASB Statement No. 123” was issued. SFAS 148 amends SFAS 123, “Accounting for Stock-Based Compensation”, to provide alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. In addition, this Statement amends the disclosure requirements of SFAS 123 to require prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on reported results. The provisions of SFAS 148 are effective for financial statements for fiscal years ending after December 15, 2002. SFAS 148 does not change the provisions of SFAS 123 that permit entities to continue to apply the intrinsic value method of Accounting Principles Bulletin No. 25, “Accounting for Stock Issued to Employees”. We will continue to account for stock-based compensation in accordance with the provisions of APB No. 25. We will provide the disclosures required by SFAS 148 in our financial statements.

In November 2002 FASB interpretation, or FIN 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantee of Indebtedness of Others” was issued. FIN 45 requires that upon issuance of a guarantee, the guarantor must recognize a liability for the fair value of the obligation it assumes under that guarantee. FIN 45’s provisions for initial recognition and measurement should be applied on a prospective basis to guarantees issued or modified after December 31, 2002. The guarantor’s previous accounting for guarantees that were issued before the date of FIN 45’s initial application may not be revised or restated to reflect the effect of the recognition and measurement provisions of FIN 45. The disclosure requirements are effective for financial statements of both interim and annual periods that end after December 15, 2002. The disclosures required by FIN 45 are included in these financial statements.

In January 2003 FASB Interpretation 46, or FIN 46, “Consolidation of Variable Interest Entities” was issued. FIN 46 identifies certain off-balance sheet arrangements that meet the definition of a variable interest entity (VIE). The primary beneficiary of a VIE is the party that is exposed to the majority of the risks and/or returns of the VIE. In future accounting periods, the primary beneficiary will be required to consolidated the VIE. In addition, more extensive disclosure requirements apply to the primary beneficiary, as well as other significant investors. We do not believe we participate in any arrangement that would be subject to the provisions of FIN 46.

Note 2—Derivative Instruments and Hedging Activities

We have entered into various derivative instruments to reduce our exposure to fluctuations in the market price of oil. The derivative instruments consist primarily of oil swap and option contracts entered into with financial institutions. On January 1, 2001 we adopted SFAS No. 133 “Accounting for Derivative Instruments and Hedging Activities” as amended by SFAS 137 and SFAS 138 (“SFAS 133”). Under SFAS 133, all derivative instruments are recorded on the balance sheet at fair value. If the derivative does not qualify as a hedge or is not designated as a hedge, the gain or loss on the derivative is recognized currently in earnings. If the derivative qualifies for hedge accounting, the unrealized gain or loss on the derivative is deferred in accumulated Other Comprehensive Income (“OCI”), a component of Stockholder’s Equity. On January 1, 2001, in accordance with the transition provisions of SFAS 133, we recorded a gain of $7.0 million in OCI, representing the cumulative

F-33

PLAINS EXPLORATION & PRODUCTION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

effect of an accounting change to recognize at fair value all cash flow derivatives. We recorded cash flow hedge derivative assets and liabilities of $9.7 million and $4.2 million, respectively, and a net-of-tax non-cash charge of $1.5 million was recorded in earnings as a cumulative effect adjustment. At December 31, 2002 all open positions qualified for hedge accounting.

Gains and losses on oil hedging instruments related to OCI and adjustments to carrying amounts on hedged volumes are included in oil and gas revenues in the period that the related volumes are delivered. Gains and losses on oil hedging instruments representing hedge ineffectiveness, which is measured on a quarterly basis, are included in oil and gas revenues in the period in which they occur. No ineffectiveness was recognized in 2002 or 2001.

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

At December 31, 2001, OCI consisted of $26.6 million ($15.9 million, net of tax) of unrealized gains on our open oil hedging instruments. As oil prices increased significantly during 2002, the fair value of our open oil hedging positions decreased $62.3 million ($37.3 million, net of tax). At December 31, 2002, OCI consisted of $20.9 million ($12.6 million net of tax) of unrealized losses on our oil 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) related to pension liabilities. At December 31, 2002, the assets and liabilities related to our open oil hedging instruments were included in current assets ($2.6 million), other assets ($1.4 million), current liabilities ($24.4 million), other long-term liabilities ($0.6 million) and deferred income taxes (a tax benefit of $8.4 million).

During 2002, $14.7 million ($8.9 million net of tax) in losses from the settlement of oil hedging instruments were reclassified from OCI and charged to income as a reduction of oil sales revenues. Oil sales revenues for the period have also been reduced by a $0.9 million non-cash expense related to the amortization of option premiums. As of December 31, 2002, $21.8 million ($13.1 million, net of tax) of deferred net losses on derivative instruments recorded in OCI are expected to be reclassified to earnings during the next twelve-month period.

Our average realized price for oil is sensitive to changes in location and quality differential adjustments as set forth in our oil sales contracts. At December 31, 2002 we had basis risk swap contracts on our Illinois Basin production through September 30, 2003. The swaps fix the location differential portion of 2,600 barrels per day at $0.43, $0.57 and $0.39 per barrel for the first, second and third quarters of 2003, respectively.

F-34

PLAINS EXPLORATION & PRODUCTION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

At December 31, 2002 we had the following open oil hedge positions:

	Bbls Per Day
	2003	2004
Swaps
Average price $23.81 per Bbl	19,250	—
Average price $23.53 per Bbl	—	12,500

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

We utilize interest rate swaps to manage the interest rate exposure on our long-term debt. We currently have an interest rate swap agreement that expires in October 2004, under which we receive LIBOR and pay 3.9% on a notional amount of $7.5 million. The interest rate swap fixes the interest rate on $7.5 million of borrowings under our credit facility at 3.9% plus the LIBOR margin set forth in the credit facility (5.3% at December 31, 2002).

Note 3—Long-Term Debt

At December 31, 2002 long-term debt consisted of:

	Current		Long- Term
Revolving credit facility	$	—	$	35,800
8.75% senior subordinated notes, net of unamortized discount of $3.1 million		—		196,855
Other		511		511
	$	511	$	233,166

Revolving credit facility

As of December 31, 2002 we had $35.8 million in borrowings, bearing interest at 3.0% and $5.2 million in letters of credit outstanding under our $300.0 million revolving credit facility. The credit facility provides for a borrowing base of $225.0 million that will be reviewed every six months, with the lenders and us each having the right to one annual interim unscheduled redetermination, and adjusted based on our oil and gas properties, reserves, other indebtedness and other relevant factors, and matures in 2005. The credit facility contains a $30.0 million sub-limit on letters of credit. To secure borrowings, we pledged 100% of the shares of stock of our domestic subsidiaries, who also guaranteed payments under the credit facility, and gave mortgages covering 80% of the total present value of our domestic oil and gas properties.

Amounts borrowed under the credit facility bear an annual interest rate, at our election, equal to either: (i) the Eurodollar rate, plus from 1.375% to 1.75%; or (ii) the greatest of (1) the prime rate, as determined by JPMorgan Chase Bank, (2) the certificate of deposit rate, plus 1.0%, or (3) the federal funds rate, plus 0.5%; plus an additional 0.125% to 0.5% for each of (1)-(3). The amount of interest payable on outstanding borrowings is based on (1) the utilization rate as a percentage of the total amount of funds borrowed under the credit facility to the borrowing base and (2) our long-term debt rating. Commitment fees and letter of credit fees under the credit facility are based on the utilization rate and long-term debt rating. Commitment fees range from 0.375% to 0.5% of the unused portion of the borrowing base. Letter of credit fees range from 1.375% to 1.75%. The issuer of any letter of credit receives an issuing fee of 0.125% of the undrawn amount. In 2002 we made cash payments for interest and fees totalling $1.2 million.

F-35

PLAINS EXPLORATION & PRODUCTION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

The credit facility contains negative covenants that limit our ability, as well as the ability of our subsidiaries, among other things, to incur additional debt, pay dividends on stock, make distributions of cash or property, change the nature of our business or operations, redeem stock or redeem subordinated debt, make investments, create liens, enter into leases, sell assets, sell capital stock of subsidiaries, create subsidiaries, guarantee other indebtedness, enter into agreements that restrict dividends from subsidiaries, enter into certain types of swap agreements, enter into gas imbalance or take-or-pay arrangements, merge or consolidate and enter into transactions with affiliates. In addition, the credit facility requires us to maintain a current ratio, which includes availability, of at least 1.0 to 1.0 and a ratio of total debt to earnings before interest, depreciation, depletion, amortization and income taxes of no more than 4.5 to 1.0. At December 31, 2002, we were in compliance with the covenants contained in the credit facility and could have borrowed the full $225.0 million available under the credit facility.

8.75% notes

On July 3, 2002, we and Plains E&P Company, our wholly owned subsidiary that has no material assets and was formed for the sole purpose of being a corporate co-issuer of certain notes, issued $200.0 million principal amount of 8.75% notes at an issue price of 98.376%. The 8.75% notes are our unsecured general obligations, are subordinated in right of payment to all of our existing and future senior indebtedness and are jointly and severally guaranteed on a full, unconditional basis by all of our existing and future domestic restricted subsidiaries. The indenture also limits our ability, as well as the ability of our subsidiaries, among other things, to incur additional indebtedness, make certain investments, make restricted payments, sell assets, enter into agreements containing dividends and other payment restrictions affecting subsidiaries, enter into transactions with affiliates, create liens, merge, consolidate and transfer assets and enter into different lines of business. In the event of a change of control, as defined in the indenture, we will be required to make an offer to repurchase the notes at 101% of the principal amount thereof, plus accrued and unpaid interest to the date of the repurchase. The indenture governing the 8.75% notes permitted the spin-off and the spin-off did not, in itself, constitute a change of control for purposes of the indenture.

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

Other

We also have a note with an outstanding principal balance of $1.0 million at December 31, 2002 that was issued in connection with the purchase of a production payment on certain of our producing properties. The note bears interest at 8%, payable annually, and requires an annual principal payment of $511,000 through 2004.

Aggregate total maturities of long-term debt in the next five years are as follows: 2003—$0.5 million; 2004—$0.5 million; and 2005—$35.8 million.

Note 4—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

F-36

PLAINS EXPLORATION & PRODUCTION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

effective interest rate of Plains Resources long-term debt. For the years ended December 31, 2002, 2001 and 2000 we were charged $10.7 million, $20.4 million and $19.5 million, respectively, of interest on amounts payable to Plains Resources. Of such amounts, $9.3 million, $17.3 million and $15.7 million was included in interest expense in 2002, 2001 and 2000, respectively, and $1.4 million, $3.1 million and $3.8 million was capitalized in oil and gas properties in 2002, 2001 and 2000, respectively.

To compensate Plains Resources for services rendered under the Services Agreement, we are allocated direct and indirect corporate and administrative costs of Plains Resources. Such costs for the years ended December 31, 2002, 2001 and 2000 totaled $4.4 million, $8.2 million and $3.9 million, respectively. Of such amounts, $3.1 million, $6.1 million and $2.8 million was included in general and administrative expense in 2002, 2001 and 2000, respectively, and $1.3 million, $2.1 million and $1.1 million was capitalized in oil and gas properties in 2002, 2001 and 2000, respectively.

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

In connection with the reorganization and the spin-off we entered into certain agreements with Plains Resources, including a master separation agreement; an intellectual property agreement; the Plains Exploration & Production transition services agreement; the Plains Resources transition services agreement; and a technical services agreement.

Master separation agreement.    The master separation agreement provides for the separation of substantially all of the upstream assets and liabilities of Plains Resources, other than its Florida operations. The master separation agreement provides for, among other things: the separation; cross-indemnification provisions; allocation of fees related to these transactions between us and Plains Resources; other provisions governing our relationship with Plains Resources, including mandatory dispute arbitration, sharing information, confidentiality and other covenants; and a noncompetition provision.

Intellectual property agreement.    The intellectual property agreement provides that Plains Resources will transfer to us ownership and all rights associated with certain trade names, trademarks and service marks. We will grant to Plains Resources a full license to use certain trade names subject to certain limitations.

Plains Exploration & Production transition services agreement.    This agreement provides that Plains Resources will provide us management, tax, accounting, payroll, insurance, employee benefits, legal and financial services on an interim basis. Through December 31, 2002 Plains Resources has charged us $10.8 million of the $30.0 million maximum amount allowed under the agreement to reimburse it for its costs of providing such services. We do not expect to incur significant additional charges under this agreement.

Plains Resources transition services agreement.    This agreement became effective as of the date of the spin-off and provides that we will provide Plains Resources tax, accounting, payroll, employee benefits, legal and financial services on an interim basis. We will charge Plains Resources on a monthly basis our costs of providing such services. No charges were made to Plains Resources in 2002 under the terms of this agreement.

Technical services agreement.    The technical services agreement provides that we will provide Calumet Florida, a subsidiary of Plains Resources, certain engineering and technical support services required to support operation and maintenance of the oil and gas properties owned by Calumet, including geological, geophysical, surveying, drilling and operations services, environmental and other governmental or regulatory compliance

F-37

PLAINS EXPLORATION & PRODUCTION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

related to oil and gas activities and other oil and gas engineering services as requested, and accounting services. We will charge Plains Resources on a monthly basis our costs of providing such services. No charges were made to Plains Resources in 2002 under the terms of this agreement.

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

Note 5—Benefit Plans

We have adopted a nonqualified retirement plan (the “Plan”) for certain of our officers who were formerly officers of Plains Resources. Benefits under the Plan are based on salary at the time of adoption of the Plains Resources plan, vest over the 15-year period designated by the Plains Resources plan and are payable over a 15-year period commencing at age 60. The Plan is unfunded.

The following table summarizes our unfunded pension obligation at December 31, 2002 (in thousands):

Projected benefit obligation for service rendered to date	$	510
Plan assets at fair value		—
Benefit obligation in excess of fair value of plan assets		(510	)
Unrecognized (gain) loss		193
Unrecognized prior service costs		75
Adjustment to recognize minimum liability		(268	)
Net amount recognized	$	(510	)

The weighted-average discount rate used in determining the projected benefit obligation at December 31, 2002 was 6.75%.

We also adopted 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.

Note 6—Stock Compensation Plans

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

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

F-38

PLAINS EXPLORATION & PRODUCTION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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. We recognized a $2.7 million accounting charge as compensation expense equal to the aggregate in-the-money value of the SARs deemed vested at the spin-off date and an additional $1.0 million accounting charge to reflect the movement in our common stock price and the vesting deemed to have occurred from the spin-off date to December 31, 2002.

The following table reflects the SARs outstanding at December 31, 2002 (share amounts in thousands):

Range of Exercise Price	Number Outstanding at 12/31/02	Weighted Average Remaining Contractual Life	Weighted Average Exercise Price		Weighted Number Exercisable at 12/31/02	Weighted Average Exercise Price
$2.46—$8.33	719	1.7 years	$	5.18	632	$	5.12
9.08—  9.08	1,000	8.4 years		9.08	—		—
9.10—  9.36	884	4.3 years		9.27	60		9.36
9.37—  9.76	571	3.6 years		9.44	180		9.52
9.97—10.50	873	4.1 years		10.01	619		10.03
2.46—10.50	4,047	4.7 years		8.68	1,491		7.86

Also at the time of the spin-off we granted an award of 165,000 restricted shares of common stock to certain of our officers that vest in three equal annual installments beginning on the first annual anniversary of the date of grant. We will recognize total compensation expense of $1.5 million ratably over the life of the grant.

Note 7—Income Taxes

Until the date of the spin-off, our taxable income or loss was included in the consolidated income tax returns filed by Plains Resources. Income tax obligations reflected in these financial statements with respect to such returns are based on the tax sharing agreement that provides that income taxes are calculated assuming we filed a separate combined income tax return. Currently payable income taxes at December 31, 2001 are included in Payable to Plains Resources Inc. in the consolidated balance sheet at December 31, 2001.

F-39

PLAINS EXPLORATION & PRODUCTION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Our deferred income tax assets and liabilities at December 31, 2002 and 2001 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,
	2002			2001
U.S. Federal
Deferred tax assets:
Net operating losses	$	846		$	—
Alternative minimum tax credit		106			—
Commodity hedging contracts and other		8,572			658
		9,524			658
Deferred tax liabilities:
Net oil & gas acquisition, exploration and development costs		(48,715	)		(36,520	)
Commodity hedging contracts and other		—			(10,700	)
		(48,715	)		(47,220	)
Net U.S. Federal deferred tax asset (liability)		(39,191	)		(46,562	)
States
Deferred tax liability		(12,225	)		(10,631	)
Net deferred tax assets (liability)	$	(51,416	)	$	(57,193	)

At December 31, 2002, for federal income tax purposes, we had carryforwards of approximately $2.4 million of regular tax net operating losses, and $0.1 million of enhanced oil recovery credits. The NOL carryforwards expire in 2019.

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

	Year Ended December 31,
	2002			2001			2000
U.S. federal income tax provision at statutory rate	$	15,039		$	31,101		$	15,935
State income taxes, net of federal benefit		2,409			4,758			2,232
Other		(716	)		(1,471	)		(1,402	)
Income tax expense on income before income taxes and cumulative effect of accounting change		16,732			34,388			16,765
Income tax benefit allocated to cumulative effect of accounting change		—			(1,042	)		—
Income tax provision	$	16,732		$	33,346		$	16,765

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

F-40

PLAINS EXPLORATION & PRODUCTION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Plains Resources of nationally recognized tax counsel to the effect that the proposed transaction would not adversely affect the tax treatment of the spin-off or provide adequate economic security to Plains Resources to ensure we would be able to comply with our obligation under this agreement. We may not be able to control some of the events that could trigger this indemnification obligation.

Note 8—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 total $0.9 million in each of 2003, 2004 and 2005, $0.4 million in 2006, $0.3 million in 2007 and $0.4 million thereafter. Total expenses related to operating lease obligations were less than $0.1 million in each of 2002, 2001 and 2000.

Environmental matters.    As an owner or lessee and operator of oil and gas properties, we are subject to various federal, state, and local laws and regulations relating to discharge of materials into, and protection of, the environment. Typically when producing oil and gas assets are purchased, one assumes the obligation to plug and abandon wells that are part of such assets. However, in some instances, we have received an indemnity in connection with such purchase. There can be no assurance that we will be able to collect on these indemnities. Often these regulations are more burdensome on older properties that were operated before the regulations came into effect such as some of our properties in California and Illinois that have operated for over 90 years. We have established policies for continuing compliance with environmental laws and regulations. We also maintain insurance coverage for environmental matters, which we believe is customary in the industry, but we are not fully insured against all environmental risks. There can be no assurance that current or future local, state or federal rules and regulations will not require us to spend material amounts to comply with such rules and regulations.

Plugging, Abandonment and Remediation Obligations.    Consistent with normal industry practices, substantially all of our oil and gas leases require that, upon termination of economic production, the working interest owners plug and abandon non-producing wellbores, remove tanks, production equipment and flow lines and restore the wellsite. Typically, when producing oil and gas assets are purchased the purchaser assumes the obligation to plug and abandon wells that are part of such assets. However, in some instances, we received an indemnity with respect to those costs.

We estimate at December 31, 2002 our future costs related to plugging, abandonment and remediation (including our commitments related to the purchase of certain of our onshore California properties) will be approximately $0.8 million, net of salvage and other considerations including the fair value of fee lands on which we conduct certain of our production operations ($104.9 million before salvage value and other considerations). Effective January 1, 2003, upon adoption of SFAS No. 143 “Accounting for Asset Retirement Obligations”, we will record the fair value of liabilities associated with our asset retirement obligations. See Note 1—Recent Accounting Pronouncements.

In connection with the purchase of certain of our onshore California properties, each year we are required to plug and abandon 20% of the then remaining inactive wells (there were 154 inactive wells at December 31, 2002). If we do not meet this commitment, and the requirement is not waived, we must escrow funds to cover the cost of the wells that were not abandoned. To date we have not been required to escrow any funds. In addition, until the end of 2005, we are required to spend at least $600,000 per year (and $300,000 per year from 2006 through 2010) to remediate oil contaminated soil from existing well sites that require remediation.

F-41

PLAINS EXPLORATION & PRODUCTION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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. 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.

In the ordinary course of business, we are a claimant and/or defendant in various other legal proceedings. In particular, we are required to indemnify Plains Resources for any liabilities it incurs in connection with a lawsuit it (through a predecessor interest in Stocker Resources, Inc.) has regarding an electric services contract with Commonwealth Energy Corporation. In this lawsuit, Plains Resources is seeking a declaratory judgment that it was entitled to terminate the contract and that Commonwealth has no basis for proceeding against a related $1.5 million performance bond. In a counter suit against Plains Resources, Commonwealth is seeking unspecified damages. We understand that Plains Resources intends to defend its rights vigorously in this matter. 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.

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

Industry Concentration

Financial instruments which potentially subject us to concentrations of credit risk consist principally of accounts receivable with respect to our oil and gas operations and derivative instruments related to our hedging activities. Plains All American Pipeline, L.P. (“PAA”), in which Plains Resources held a 25% interest at December 31, 2002, is the exclusive marketer/purchaser for all of our equity oil production. This concentration has the potential to impact our overall exposure to credit risk, either positively or negatively, in that PAA may be affected by changes in economic, industry or other conditions. We do not believe the loss of PAA as the exclusive purchaser of our equity production would have a material adverse affect on our results of operations. We believe PAA could be replaced by other purchasers under contracts with similar terms and conditions.

The contract counterparties for our derivative commodity contracts are all major financial institutions with Standard & Poor’s ratings of A or better. Three of the financial institutions are participating lenders in the credit facility, with one such counterparty holding contracts that represent approximately 33% of the fair value of all of our open positions at December 31, 2002.

There are a limited number of alternative methods of transportation for our production. Substantially all of our oil and gas production is transported by pipelines and trucks owned by third parties. The inability or

F-42

PLAINS EXPLORATION & PRODUCTION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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 9—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 other assets and other long-term liabilities are stated at fair value. The carrying amounts and fair values of our other financial instruments are as follows (in thousands):

	December 31, 2002
	Carrying Amount		Fair Value
Long-Term Debt
Bank debt	$	35,800	$	35,800
Senior subordinated debt		196,855		208,000
Other long-term debt		1,022		1,022

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

Note 10—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,
	2002			2001		2000
Property acquisitions costs
Unproved properties	$	65		$	44	$	73
Proved properties(1)		(4,516	)		1,645		1,953
Exploration costs		602			286		293
Exploitation and development costs(2)		68,346			123,778		68,186
	$	64,497		$	125,753	$	70,505

F-43

PLAINS EXPLORATION & PRODUCTION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(1) 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) Includes capitalized general and administrative expense of $6.0 million, $6.2 million and $5.2 million in 2002, 2001 and 2000, respectively, and capitalized interest expense of $2.4 million, $3.1 million and $3.8 million in 2002, 2001 and 2000, 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,
	2002			2001
Proved properties	$	629,454		$	561,034
Accumulated DD&A		(167,278	)		(139,797	)
	$	462,176		$	421,237

The average DD&A rate per equivalent unit of production was $3.17, $2.70 and $2.25 in 2002, 2001 and 2000, respectively.

Costs not subject to amortization

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

	December 31,
	2002		2001		2000
Acquisition costs	$	24,612	$	27,523	$	31,090
Exploration costs		—		—		425
Capitalized interest		5,433		5,848		3,222
	$	30,045	$	33,371	$	34,737

Unproved property costs not subject to amortization consist primarily of acquisition costs related to unproved areas and capitalized interest. Costs are transferred into the amortization base on an ongoing basis as the properties are evaluated and proved reserves established or impairment determined. We will continue to evaluate these properties and costs will be transferred into the amortization base as the undeveloped areas are tested. Our onshore properties and one offshore property consist of mature but underdeveloped oil properties that were acquired from major or large independent oil and gas companies. 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 70% of the costs not subject to amortization at December 31, 2002 will be transferred to the amortization base over the next three years and the remainder within the next ten years. The leases covering the properties are held by production and will not limit the time period for evaluation.

F-44

PLAINS EXPLORATION & PRODUCTION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Approximately 10%, 9% and 11% of the balance in unproved properties at December 31, 2002, related to additions made in 2002, 2001 and 2000, 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,
	2002			2001			2000
Revenues from oil and gas producing activities	$	188,563		$	204,139		$	142,451
Production costs		(78,451	)		(63,795	)		(56,228	)
Depreciation, depletion and amortization		(29,632	)		(23,707	)		(18,395	)
Income tax expense		(31,307	)		(45,022	)		(24,981	)
Results of operations from producing activities (excluding corporate overhead and interest costs)	$	49,173		$	71,615		$	42,847

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, 2002. The following reserve information is based upon reports of the independent petroleum consulting firms of Netherland, Sewell & Associates, Inc., and Ryder Scott Company in 2002 and 2001 and H.J. Gruy and Associates, Inc., Netherland, Sewell & Associates, Inc., and Ryder Scott Company in 2000. 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 gas have had, and could have in the future, an adverse effect on the carrying value of our proved reserves and our revenues, profitability and cash flow. Almost all of our reserve base (approximately 95% of year-end 2002 reserve volumes) is comprised of oil properties that are sensitive to oil price volatility.

F-45

PLAINS EXPLORATION & PRODUCTION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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, 2002 (in thousands).

	As of or for the Year Ended December 31,
	2002				2001				2000
	Oil (MBbl)		Gas (MMcf)		Oil (MBbl)		Gas (MMcf)		Oil (MBbl)		Gas (MMcf)
Proved Reserves
Beginning balance	223,293		96,217		204,387		93,486		195,213		90,873
Revision of previous estimates	8,897		(19,827	)	(13,093	)	(5,485	)	(5,601	)	(3,597	)
Extensions, discoveries, improved recovery and other additions	15,049		6,661		40,218		11,571		22,429		9,252
Purchase of reserves in-place	2,635		—		—		—		—		—
Sale of reserves in-place	(930	)	(2,535	)	—		—		—		—
Production	(8,783	)	(3,362	)	(8,219	)	(3,355	)	(7,654	)	(3,042	)
Ending balance	240,161		77,154		223,293		96,217		204,387		93,486
Proved Developed Reserves
Beginning balance	119,248		59,101		105,679		52,184		100,758		49,255
Ending balance	127,415		53,317		119,248		59,101		105,679		52,184

Standardized measure of discounted future net cash flows (unaudited)

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

	December 31,
	2002			2001			2000
Future cash inflows	$	6,819,645		$	3,662,137		$	5,850,215
Future development costs		(431,841	)		(305,261	)		(249,319	)
Future production expense		(2,528,065	)		(1,714,132	)		(2,748,492	)
Future income tax expense		(1,446,528	)		(537,252	)		(1,030,400	)
Future net cash flows		2,413,211			1,105,492			1,822,004
Discounted at 10% per year		(1,529,704	)		(721,025	)		(1,032,566	)
Standardized measure of discounted future net cash flows	$	883,507		$	384,467		$	789,438

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 NYMEX oil price for a significant portion of our oil production. Arrangements in effect at December 31, 2002 are discussed in Note 2. Such

F-46

PLAINS EXPLORATION & PRODUCTION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

arrangements are not reflected in the reserve reports. The overall average year-end prices used in the reserve reports as of December 31, 2002, 2001 and 2000 were $26.91, $15.31 and $21.93 per barrel of oil, respectively, and $4.63, $2.56 and $14.63 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. Future development costs do not include any amounts for capitalized general and administrative costs or capitalized interest.

4.    The reports reflect the pre-tax Present Value of Proved Reserves to be $1.5 billion, $0.6 billion and $1.3 billion at December 31, 2002, 2001 and 2000, respectively. SFAS No. 69 requires us to further reduce these estimates by an amount equal to the present value of estimated income taxes which might be payable by us in future years to arrive at the Standardized Measure. Future income taxes were calculated by applying the statutory federal and state income tax rate to pre-tax future net cash flows, net of the tax basis of the properties involved and utilization of available tax carryforwards related to oil and gas operations.

The principal sources of changes in the Standardized Measure of the future net cash flows for the three years ended December 31, 2002, are as follows (in thousands):

	Year Ended December 31,
	2002			2001			2000
Balance, beginning of year	$	384,467		$	789,438		$	727,286
Sales, net of production expenses		(125,463	)		(139,545	)		(159,035	)
Net change in sales and transfer prices, net of production expenses		979,042			(665,006	)		180,935
Changes in estimated future development costs		(62,801	)		(17,535	)		(16,097	)
Extensions, discoveries and improved recovery, net of costs		98,969			89,010			141,641
Previously estimated development costs incurred during the year		39,692			86,881			27,855
Purchase of reserves in-place		16,583			—			—
Sale of reserves in-place		(2,959	)		—			—
Revision of quantity estimates and timing of estimated production		(133,618	)		(156,362	)		(82,141	)
Accretion of discount		62,376			141,598			101,667
Net change in income taxes		(372,781	)		255,988			(132,673	)
Balance, end of year	$	883,507		$	384,467		$	789,438

F-47

PLAINS EXPLORATION & PRODUCTION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Note 11—Quarterly Financial Data (Unaudited)

The following table shows summary financial data for 2002 and 2001 (in thousands, except per share data):

	First Quarter			Second Quarter		Third Quarter		Fourth Quarter		Year
2002
Revenues	$	40,673		$	45,140	$	50,907	$	51,843	$	188,563
Operating profit		16,753			20,471		21,408		21,121		79,753
Net income		5,864			8,218		7,418		4,737		26,237
Basic and diluted earnings per share	$	0.24		$	0.34	$	0.30	$	0.20	$	1.08
2001
Revenues	$	53,773		$	56,924	$	50,598	$	42,844	$	204,139
Operating profit		35,039			34,202		27,060		19,938		116,239
Income before cumulative effect of accounting change		17,573			17,080		12,468		7,572		54,693
Cumulative effect of accounting change		(1,522	)		—		—		—		(1,522	)
Net income		16,051			17,080		12,468		7,572		53,171
Basic and diluted earnings per share
Income before cumulative effect of accounting change	$	0.73		$	0.71	$	0.51	$	0.31		2.26
Cumulative effect of accounting change		(0.06	)		—		—		—		(0.06	)
Net income		0.67			0.71		0.51		0.31		2.20

Note 12—Consolidating Financial Statements

We and Plains E&P Company are the co-issuers of the 8.75% notes discussed in Note 3. The 8.75% notes are jointly and severally guaranteed on a full and unconditional basis by Arguello Inc., Plains Illinois Inc. and certain immaterial subsidiaries (referred to as “Guarantor Subsidiaries”).

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

• PXP (the “Issuer”);

• the guarantor subsidiaries on a combined basis (“Guarantor Subsidiaries”);

• elimination entries necessary to consolidate the Issuer and Guarantor Subsidiaries; and

• the company on a consolidated basis.

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

F-48

PLAINS EXPLORATION & PRODUCTION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING BALANCE SHEET

DECEMBER 31, 2002

(in thousands)

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

F-49

PLAINS EXPLORATION & PRODUCTION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING BALANCE SHEET

DECEMBER 31, 2001

(in thousands)

	Issuer			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
ASSETS
Current Assets
Cash and cash equivalents	$	11		$	2		$	—		$	13
Accounts receivable and other current assets		10,703			5,679			—			16,382
Commodity hedging contracts		13,872			7,915			—			21,787
Inventories		3,252			1,377			—			4,629
		27,838			14,973			—			42,811
Property and Equipment, at cost
Oil and gas properties—full cost method
Subject to amortization		450,038			110,996			—			561,034
Not subject to amortization		19,676			13,695			—			33,371
Other property and equipment		1,322			194			—			1,516
		471,036			124,885			—			595,921
Less allowance for depreciation, depletion and amortization		(56,137	)		(84,667	)		—			(140,804	)
		414,899			40,218			—			455,117
Investment in and Advances to Subsidiaries		(21,496	)		—			21,496			—
Other Assets		16,275			2,552			—			18,827
	$	437,516		$	57,743		$	21,496		$	516,755
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts payable and other current liabilities	$	29,822		$	11,546		$	—		$	41,368
Current maturities on long-term debt		511			—			—			511
		30,333			11,546			—			41,879
Payable to Plains Resources Inc.		172,603			62,558			—			235,161
Long-Term Debt		1,022			—			—			1,022
Other Long-Term Liabilities		—			1,413			—			1,413
Deferred Income Taxes		53,471			3,722			—			57,193
Stockholders’ equity
Combined owner’s equity		164,203			(25,889	)		25,889			164,203
Accumulated other comprehensive income		15,884			4,393			(4,393	)		15,884
		180,087			(21,496	)		21,496			180,087
	$	437,516		$	57,743		$	21,496		$	516,755

F-50

PLAINS EXPLORATION & PRODUCTION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING STATEMENT OF INCOME

YEAR ENDED DECEMBER 31, 2002

(in thousands)

	Issuer			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
Revenues
Oil and liquids	$	123,795		$	54,243		$	—		$	178,038
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		(140	)		314			—			174
Income Before Income Taxes and Cumulative Effect of Accounting Change		39,084			9,873			(5,988	)		42,969
Income tax expense
Current		(1,232	)		(5,121	)		—			(6,353	)
Deferred		(11,615	)		1,236			—			(10,379	)
Net Income	$	26,237		$	5,988		$	(5,988	)	$	26,237

F-51

PLAINS EXPLORATION & PRODUCTION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING STATEMENT OF INCOME

YEAR ENDED DECEMBER 31, 2001

(in thousands)

	Issuer			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
Revenues
Oil and liquids	$	124,250		$	50,645		$	—		$	174,895
Gas		28,771			—			—			28,771
Other operating revenues		—			473			—			473
		153,021			51,118			—			204,139
Costs and Expenses
Production expenses		41,458			22,337			—			63,795
General and administrative		8,708			1,502			—			10,210
Depreciation, depletion and amortization		18,413			5,692			—			24,105
		68,579			29,531			—			98,110
Income from Operations		84,442			21,587			—			106,029
Other Income (Expense)
Equity in earnings of subsidiaries		11,528			—			(11,528	)		—
Interest expense		(10,679	)		(6,732	)		—			(17,411	)
Interest and other income		94			369			—			463
Income Before Income Taxes and Cumulative Effect of Accounting Change		85,385			15,224			(11,528	)		89,081
Income tax expense
Current		(2,832	)		(3,182	)		—			(6,014	)
Deferred		(27,620	)		(754	)		—			(28,374	)
Income Before Cumulative Effect of Accounting Change		54,933			11,288			(11,528	)		54,693
Cumulative effect of accounting change, net of tax benefit		(1,762	)		240			—			(1,522	)
Net Income	$	53,171		$	11,528		$	(11,528	)	$	53,171

F-52

PLAINS EXPLORATION & PRODUCTION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING STATEMENT OF INCOME

YEAR ENDED DECEMBER 31, 2000

(in thousands)

	Issuer			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
Revenues
Oil and liquids	$	85,921		$	40,513		$	—		$	126,434
Gas		16,017			—			—			16,017
		101,938			40,513			—			142,451
Costs and Expenses
Production expenses		35,278			20,950			—			56,228
General and administrative		5,168			1,140			—			6,308
Depreciation, depletion and amortization		15,450			3,409			—			18,859
		55,896			25,499			—			81,395
Income from Operations		46,042			15,014			—			61,056
Other Income (Expense)
Equity in earnings of subsidiaries		6,859			—			(6,859	)		—
Interest expense		(10,212	)		(5,673	)		—			(15,885	)
Interest and other income		213			130			—			343
Income Before Income Taxes		42,902			9,471			(6,859	)		45,514
Income tax expense
Current		(168	)		(2,263	)		—			(2,431	)
Deferred		(13,985	)		(349	)		—			(14,334	)
Net Income	$	28,749		$	6,859		$	(6,859	)	$	28,749

F-53

PLAINS EXPLORATION & PRODUCTION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

YEAR ENDED DECEMBER 31, 2002

(in thousands)

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

F-54

PLAINS EXPLORATION & PRODUCTION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

YEAR ENDED DECEMBER 31, 2001

(in thousands)

	Issuer			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	53,171		$	11,528		$	(11,528	)	$	53,171
Items not affecting cash flows from operating activities:
Depreciation, depletion and amortization		18,413			5,692			—			24,105
Equity in earnings of subsidiaries		(11,528	)		—			11,528			—
Deferred income taxes		27,620			754			—			28,374
Cumulative effect of adoption of accounting change		1,762			(240	)		—			1,522
Change in derivative fair value		(7	)		1,062			—			1,055
Other noncash items		263			733			—			996
Change in assets and liabilities from operating activities:
Accounts receivable and other assets		9,449			(252	)		—			9,197
Inventories		(586	)		(5	)		—			(591	)
Accounts payable and other liabilities		157			(1,178	)		—			(1,021	)
Net cash provided by operating activities		98,714			18,094			—			116,808
CASH FLOWS FROM INVESTING ACTIVITIES
Acquisition, exploration and developments costs		(108,577	)		(17,176	)		—			(125,753	)
Additions to other property and equipment		(127	)		—			—			(127	)
Net cash used in investing activities		(108,704	)		(17,176	)		—			(125,880	)
CASH FLOWS FROM FINANCING ACTIVITIES
Principal payments of long-term debt		(511	)		—			—			(511	)
Receipts from (payments to) Plains Resources Inc.		10,272			(1,212	)		—			9,060
Net cash provided by (used in) financing activities		9,761			(1,212	)		—			8,549
Net increase (decrease) in cash and cash equivalents		(229	)		(294	)		—			(523	)
Cash and cash equivalents, beginning of year		240			296			—			536
Cash and cash equivalents, end of year	$	11		$	2		$	—		$	13

F-55

PLAINS EXPLORATION & PRODUCTION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

YEAR ENDED DECEMBER 31, 2000

(in thousands)

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

F-56

PLAINS EXPLORATION & PRODUCTION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Note 13—Subsequent Event

On February 3, 2003 we announced that we entered into a definitive agreement pursuant to which we will acquire 3TEC Energy Corporation, or 3TEC, for approximately $333 million plus the assumption of debt, which totaled $99.0 million at December 31, 2002. Under the terms of the merger agreement, 3TEC common stockholders will receive $8.50 of cash and 0.85 of a share of our common stock for each share of 3TEC common stock they own, which equates to a total of $16.97 per 3TEC common share based on the January 31, 2003 closing price of $9.96 per share for our common stock. This exchange ratio is subject to an upward or downward adjustment should the market price of our common stock fall below $7.65 per share or rise above $12.35 per share, respectively. This mechanism is intended to provide that the total value of the consideration received by 3TEC common stockholders at the effective time of the merger will be between $15.00 and $19.00 per share of 3TEC common stock. For this purpose, the market price of our common stock will be the average closing price of our common stock for the 20 consecutive trading days immediately preceding the third trading day prior to closing. In addition, if the market price of our common stock is less than $6.25, we may either (i) terminate the merger agreement or (ii) in lieu of issuing more common stock increase the cash consideration paid per share of 3TEC common stock by the amount our common stock market price is less than $6.25 times the exchange ratio after adjustment.

The merger is expected to qualify as a tax free reorganization under Section 368(a) of the Internal Revenue Code. Accordingly, the merger is expected to be tax free to our stockholders and tax free for the stock portion of the consideration received by 3TEC stockholders. We anticipate funding the cash portion of the merger through a new credit facility.

The Boards of Directors of both companies have approved the merger agreement and each has recommended it to their respective stockholders for approval. The transaction is subject to stockholder approval from both companies and other customary conditions. Assuming the market price of our common stock is between $7.65 and $12.35, after the merger is completed, 3TEC common stockholders will own approximately 40% of the combined company and our stockholders will own approximately 60% of the combined company.

Note 14—Asset Retirement Obligations

Effective January 1, 2003 we adopted Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations” (“SFAS 143”). SFAS 143 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 should capitalize the retirement cost of the related long-lived asset. Each period the liability is accreted to its then present value, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized. In prior periods we included estimated future costs of abandonment and dismantlement in our full cost amortization base and these costs were amortized as a component of our depletion expense.

At January 1, 2003 the present value of our asset retirement obligation for oil and gas properties and equipment (“ARO”) was $26.5 million. The following table shows, on a pro forma basis, the amount of the ARO on January 1, 2000 and December 31, 2000, 2001, and 2002 had we adopted SFAS 143 on January 1, 2000 (thousands of dollars):

	ARO
January 1, 2000	$	20,563
December 31, 2000		20,332
December 31, 2001		21,629
December 31, 2002		26,540

F-57

PLAINS EXPLORATION & PRODUCTION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

The following table illustrates on a pro forma basis the effect on our net income and earnings per share as if SFAS 143 had been applied during the three years ended December 31, 2002, 2001, and 2000 (thousands of dollars, except per share data):

	Year ended December 31,
	2002		2001			2000
Income before cumulative effect of accounting change—as reported	$	26,237	$	54,693		$	28,749
Adjustment for effect of adoption of SFAS 143 that is retroactively applied, net of tax		1,194		1,210			1,291
Pro forma income before cumulative effect of SFAS 133 accounting change		27,431		55,903			30,040
Cumulative effect of adoption of SFAS 133		—		(1,522	)		—
Pro forma net income	$	27,431	$	54,381		$	30,040
Earnings per share, basic and diluted:
Income before cumulative effect of accounting change—as reported	$	1.08	$	2.26		$	1.19
Adjustment for effect of adoption of SFAS 143 that is retroactively applied, net of tax		0.05		0.05			0.05
Pro forma income before cumulative effect of SFAS 133 accounting change		1.13		2.31			1.24
Cumulative effect of adoption of SFAS 133		—		(0.06	)		—
Pro forma net income	$	1.13	$	2.25		$	1.24

F-58

3TEC ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands, except per share data)

	March 31, 2003			December 31, 2002
	(Unaudited)			(Audited)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	1,846		$	2,249
Accounts receivable		25,386			17,486
Other current assets		3,004			1,285
Total current assets		30,236			21,020
PROPERTY AND EQUIPMENT (AT COST)
Oil and gas-successful efforts method		455,393			435,591
Other property and equipment		3,918			3,931
		459,311			439,522
Accumulated depreciation, depletion and amortization		(125,167	)		(112,732	)
Net Properties and Equipment		334,144			326,790
OTHER ASSETS		1,280			1,375
TOTAL ASSETS	$	365,660		$	349,185
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts payable	$	14,411		$	13,440
Accrued liabilities		1,819			1,340
Series C Preferred stock redemption payable		1,255			1,272
Derivative fair value liability		2,968			3,551
Asset retirement obligation		261			—
Other current liabilities		2,244			3,055
Total current liabilities		22,958			22,658
Long-term debt		106,000			99,000
Asset retirement obligation		4,835			—
Deferred income taxes		46,259			44,563
TOTAL LIABILITIES		180,052			166,221
STOCKHOLDERS’ EQUITY
Preferred stock, $0.02 par, 20,000,000 shares authorized, 266,667 shares designated Series B, 2,300,000 shares designated Series C and 725,167 shares designated Series D, none other designated		—			—
Convertible preferred stock Series D, 5% $24.00 redemption value, 613,919 shares issued and outstanding at March 31, 2003 and December 31, 2002, $14,734 aggregate liquidation preference		7,475			7,475
Common stock, $.02 par value, 60,000,000 shares authorized, 16,850,572 shares issued at March 31, 2003 and December 31, 2002		337			337
Additional paid-in capital		157,557			157,557
Retained earnings		22,117			19,520
Treasury stock; 69,807 shares at March 31, 2003 and December 31, 2002.		(1,049	)		(1,049	)
Deferred compensation		(829	)		(876	)
TOTAL STOCKHOLDERS’ EQUITY		185,608			182,964
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	365,660		$	349,185

See accompanying notes to unaudited consolidated financial statements

F-59

3TEC ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except share and per share data)

	Three Months Ended March 31
	2003			2002
	(Unaudited)			(Unaudited)
REVENUES
Oil, natural gas and plant income	$	48,372		$	17,851
Gain on sale of properties		59			77
Gain (loss) on derivative fair value		583			(21,410	)
Gain (loss) on derivatives settlements		(14,993	)		6,883
Other		53			188
TOTAL REVENUES		34,074			3,589
EXPENSES
Production—
Lease operations		4,155			3,495
Production, severance and ad valorem taxes		2,735			1,248
Gathering, transportation and other		1,106			806
Geological and geophysical		3,608			180
Dry hole and impairments		2,161			54
General and administrative		2,528			2,207
Stock compensation (general and administrative)		47			—
Accretion		84			—
Interest		831			1,023
Depreciation, depletion and amortization		10,634			8,755
Merger costs		894			—
TOTAL EXPENSES		28,783			17,768
INCOME (LOSS) BEFORE INCOME TAX EXPENSE AND DIVIDENDS TO PREFERRED STOCKHOLDERS		5,291			(14,179	)
Income tax (benefit) expense		2,064			(5,531	)
INCOME (LOSS) BEFORE CUMULATIVE EFFECT OF AN ACCOUNTING CHANGE		3,227			(8,648	)
Cumulative effect of a change in accounting principle (net of tax)		446			—
NET INCOME (LOSS)		2,781			(8,648	)
Dividends to preferred stockholders		184			185
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCKHOLDERS	$	2,597		$	(8,833	)
NET INCOME (LOSS) PER COMMON SHARE (before cumulative effect of a change in accounting principle)
BASIC	$	0.18		$	(0.54	)
DILUTED	$	0.17		$	(0.54	)
NET INCOME (LOSS) PER COMMON SHARE (after cumulative effect of a change in accounting principle)
BASIC	$	0.16		$	(0.54	)
DILUTED	$	0.15		$	(0.54	)
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING
BASIC		16,695,581			16,488,579
DILUTED		19,066,387			16,488,579

See accompanying notes to unaudited consolidated financial statements

F-60

3TEC ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

	Three Months Ended March 31
	2003			2002
	(Unaudited)			(Unaudited)
OPERATING ACTIVITIES
Net income (loss)	$	2,781		$	(8,648	)
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		10,538			8,590
Amortization of debt issue costs		96			165
Dry hole and impairments		2,161			54
(Gain) loss on derivative fair value		(583	)		21,410
Gain on sale of properties		(59	)		(77	)
Deferred income taxes		2,064			(5,530	)
Stock compensation		47			—
Accretion		84			—
Cumulative effect of a change in accounting principle		446			—
Other		—			8
Changes in current assets and liabilities:
Accounts receivable and other current assets		(9,618	)		8,773
Accounts payable, accrued liabilities and other current liabilities		528			(17,975	)
NET CASH PROVIDED BY OPERATING ACTIVITIES		8,485			6,770
INVESTING ACTIVITIES
Proceeds from sales of properties		623			674
Development of oil and gas properties		(16,321	)		(12,878	)
Additions to other assets		(6	)		(176	)
NET CASH USED IN INVESTING ACTIVITIES		(15,704	)		(12,380	)
FINANCING ACTIVITIES
Proceeds from long term debt		39,000			17,000
Principal payments on long-term debt		(32,000	)		(26,000	)
Proceeds from exercise of stock options and warrants		—			251
Preferred stock dividends		(184	)		(185	)
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES		6,816			(8,934	)
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		(403	)		(14,544	)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		2,249			17,762
CASH AND CASH EQUIVALENTS AT ENDING OF PERIOD	$	1,846		$	3,218
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid during the year for:
Interest	$	786		$	957
Non-cash investing and financing activities:
Deferred taxes recorded in acquisition of Classic	$	—		$	325

See accompanying notes to unaudited consolidated financial statements

F-61

3TEC ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(1)    BASIS OF PRESENTATION

In management’s opinion, the accompanying unaudited consolidated financial statements contain all adjustments (consisting primarily of normal recurring adjustments) necessary to present fairly the consolidated financial position of the Company as of March 31, 2003 and December 31, 2002 and consolidated results of operations and consolidated cash flows for the periods ended March 31, 2003 and 2002.

These consolidated financial statements should be read in conjunction with the Company’s financial statements and notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2002. The results of operations for the three months ended March 31, 2003, are not necessarily indicative of the results which may be expected for any other interim period or for the entire fiscal year ending December 31, 2003.

Recent Developments

On February 2, 2003, the Company entered into a definitive merger agreement with Plains Exploration & Production Company (“Plains”) whereby Plains will acquire the Company for a combination of cash and stock. Under the terms of the agreement, the Company’s shareholders will receive $8.50 in cash and 0.85 of a share of Plains’s Common Stock for each share of the Company’s Common Stock, subject to certain adjustments if the average share price of Plains’s Common Stock (as determined during a twenty-day trading period prior to closing) is less than $7.65 per share or greater than $12.35 per share. The transaction is subject to a shareholder vote on June 3, 2003, and is expected to close during the second quarter of 2003.

Significant Accounting Policies

The Company’s accounting policies reflect industry standards and conform to generally accepted accounting principles. The more significant of such policies are described below.

Reclassifications

Certain prior-year amounts have been reclassified to conform with current year presentation.

Oil and Gas Properties

The Company follows the successful efforts method of accounting for oil and natural gas properties, and accordingly, capitalizes all direct costs incurred in connection with the acquisition, drilling and development of productive oil and natural gas properties. Costs associated with unsuccessful exploration are charged to expense currently. Geological and geophysical costs and costs of carrying and retaining unevaluated properties are charged to expense. Depreciation, depletion and amortization of capitalized costs are computed separately for each field based on the unit-of-production method using only proved oil and natural gas reserves. In arriving at such rates, commercially recoverable reserves have been estimated by an independent petroleum engineering firm. The Company reviews its undeveloped properties continually and charges them to expense on a property-by-property basis when it is determined that they have been condemned by dry holes, or have otherwise diminished in value.

Proved oil and natural gas reserves are the estimated quantities of oil, natural gas and natural gas liquids which are expected to be recoverable in future years from known reservoirs under existing economic and

F-62

3TEC ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

operating conditions. Reservoirs are considered proved if economic productability is supported by either actual production or conclusive formation tests.

The Company reviews long-lived assets for impairment when events or changes in circumstances indicate that the carrying value of such an asset may not be recoverable. This review consists of a comparison of the carrying value of the asset to the asset’s expected future undiscounted cash flows. Estimates of expected future cash flows represent management’s best estimate based on reasonable and supportable assumptions and projections. If the expected future cash flows, assuming escalated prices, are less than the carrying value of the asset, an impairment exists and is measured as the excess of the carrying value over the estimated fair value of the asset. The Company estimates the discounted future net cash flows of its oil and gas properties to determine their fair value. Any impairment provisions recognized are permanent and may not be restored in the future. For the three months ended March 31, 2003, the Company’s proved properties were assessed for impairment on an individual field basis and the Company recorded impairment provisions on certain producing properties of $2.9 million.

Revenue Recognition of Production Imbalances

Oil and natural gas revenues are recorded using the sales method, whereby the Company recognizes revenues based on the amount of oil and natural gas sold to purchasers on its behalf notwithstanding its ownership percentage. At March 31, 2003, the Company’s net imbalance position was immaterial.

Hedging

In June 1998, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities (“SFAS 133”). In June 2000, the FASB issued SFAS 138, Accounting for Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133. SFAS 133, as amended, establishes accounting and reporting standards requiring that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded in the balance sheet as either an asset or liability measured at its fair market value. The statement requires that changes in the derivative’s fair value be recognized currently in earnings unless specific hedge criteria are met. Special accounting for qualifying hedges allows a derivative’s gains and losses to offset related results on the hedged item in the statement of operations, and requires that a company must formally document, designate and assess the effectiveness of transactions that receive hedge accounting. The Company adopted SFAS 133 effective January 1, 2001.

SFAS 133, in part, allows hedge accounting. SFAS 133 provides that the effective portion of the gain or loss on a derivative instrument designated and qualifying as a cash flow hedging instrument be reported as a component of other comprehensive income and be reclassified into earnings in the same period during which the hedged forecasted transaction affects earnings. The remaining gain or loss on the derivative instrument, if any, must be recognized currently in earnings.

To qualify for cash flow hedge accounting, the cash flows from the hedging instrument must be highly effective in offsetting changes in cash flows due to changes in the underlying items being hedged. In addition, all hedging relationships must be designated, documented, and reassessed periodically. The Company’s natural gas derivative instruments entered into during the periods presented were not designated as hedges at the time the instruments were executed. In accordance with provisions of SFAS 133, these instruments were marked-to-market through earnings at March 31, 2003, resulting in an increase of $583,358.

F-63

3TEC ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

Earnings Per Share

Basic earnings and loss per common share are based on the weighted average shares outstanding without any dilutive effects considered. Diluted earnings and loss per share reflect dilution from all potential common shares, including options, warrants and convertible preferred stock and convertible notes. Diluted loss per share does not include the effect of any potential common shares if the effect would be to decrease the loss per share.

At March 31, 2003, the Company had a weighted average of 2,370,806 combined stock options, warrants and convertible preferred stock and notes outstanding included in the Company’s fully diluted per share calculation, respectively. At March 31, 2002, the Company had a weighted average of 2,557,775 stock options, warrants and convertible preferred stock outstanding which were not included in the computation of diluted earnings per share, because the effect of the assumed exercise of these stock options, warrants and convertible securities would have an antidilutive effect on the computation of diluted loss per share.

Basic and diluted earnings per share for the three-month period ended March 31, 2003 and March 31, 2002, was determined as follows (in thousands):

	Three Months Ended March 31, 2003		Three Months Ended March 31, 2002
Basic net income (loss) attributable to common shareholders	$	2,597	$	(8,833	)
Plus preferred stock dividends		184		—
Fully diluted net income (loss) attributable to common shareholders		2,781		(8,833	)
Basic shares outstanding (weighted average shares)		16,696		16,489
Plus potentially dilutive securities:
Ÿ  Dilutive options and warrants applying treasury stock method		1,734		—
Ÿ  Shares from conversion of Series D preferred stock		614		—
Ÿ  Non-vested restricted stock		22		—
Fully diluted shares outstanding (weighted average shares)		19,066		16,489

Accounting Pronouncements

In August, 2001, the FASB issued SFAS 143, “Accounting for Asset Retirement Obligations”, which addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. The Company adopted SFAS 143 as of January 1, 2003. The impact of adoption is discussed in more detail in Note 4.

During second quarter 2002 the FASB issued SFAS No. 145, Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections. This statement rescinds SFAS No. 4, Reporting Gains and Losses from Extinguishment of Debt, and requires that all gains and losses from extinguishment of debt should be classified as extraordinary items only if they meet the criteria in APB No. 30. Applying APB No. 30 will distinguish transactions that are part of an entity’s recurring operations from those that are unusual or infrequent or that meet the criteria for classification as an extraordinary item. Any gain or loss on extinguishment of debt that was classified as an extraordinary item in prior periods presented that does not meet the criteria in APB No. 30 for classification as an extraordinary item must be reclassified. The Company does not expect that there will be any current impact from SFAS No. 145.

F-64

3TEC ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

The FASB issued SFAS No. 146, Accounting for Costs Associated with Exit or Disposal Activities, in June 2002. This statement addresses financial accounting and reporting for costs associated with exit or disposal activities and nullifies Emerging Issues Task Force Issue No. 94-3, Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring). SFAS No. 146 applies to costs incurred in an “exit activity,” which includes, but is not limited to, a restructuring, or a “disposal activity” covered by SFAS No. 144. There is no current impact of SFAS 146 on the Company’s financial position or results of operations.

In December 2002, SFAS No. 148, Accounting for Stock-Based Compensation—Transition and Disclosure—an amendment of FASB Statement No. 123 was issued. SFAS 148 amends SFAS 123, Accounting for Stock-Based Compensation, to provide alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. In addition, this Statement amends the disclosure requirements of SFAS 123 to require prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on reported results. The provisions of SFAS 148 are effective for financial statements for fiscal years ending after December 15, 2002. SFAS 148 does not change the provisions of SFAS 123 that permit entities to continue to apply the intrinsic value method of Accounting Principles Bulletin No. 25, Accounting for Stock Issued to Employees. We have and will continue to account for stock-based compensation in accordance with the provisions of APB No. 25.

For the periods ending March 31, 2003 and 2002, the exercise price of the options granted is equal to the quoted market price of the Company’s stock at the grant date, and therefore, no compensation costs have been recognized for its stock option plans. Had compensation cost for the Company’s plans been determined based on the fair market value at the grant date for stock options granted for the periods ending March 31, 2003 and 2002, the Company’s net income and income per share would have been adjusted to the pro forma amounts listed below (in thousands, except per share amounts):

	March 31, 2003			March 31, 2002
Net Income (Loss) attributable to Common Stockholders
As reported	$	2,597		$	(8,833	)
Add: Stock-based employee compensation expense included and reported in net income, net of tax		29			—
Less: Total stock-based employee compensation expense determined under fair value based methods for all awards, net of related tax effects		(574	)		(632	)
Pro forma	$	2,052		$	(9,465	)
Net Income (Loss) per common share, basic
As reported	$	0.16		$	(0.54	)
Pro forma	$	0.12		$	(0.57	)
Net Income (Loss) per common share, diluted
As reported	$	0.15		$	(0.54	)
Pro forma	$	0.12		$	(0.57	)

During 2002, the FASB issued two interpretations: FIN 45, Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others and FIN 46, Consolidation of Variable Interest Entities. There is no current impact of FIN 45 or FIN 46 on the Company’s financial position or results of operations.

F-65

3TEC ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

(2)    STOCKHOLDERS’ EQUITY

Preferred Stock—Series B

In connection with the merger with Shore Oil Company, effective June 30, 1997, the Company issued 266,667 shares of Series B Preferred Stock (“Series B”). The Series B is nonvoting and pays no dividends. The Series B has a liquidation value of $7.50 per share. During the first quarter of 2002, 58,762 shares of Series B were converted into 34,065 shares of Company Common Stock (“Common”). On December 31, 2002, the remaining 207,905 Series B shares were converted into 152,165 shares of Common. The conversion calculation was calculated as 88,889 shares plus the result of multiplying (i) (the value of approximately 40,000 net mineral acres owned by the Company in South Louisiana (the “Mineral Acres”) minus $2,000,000) divided by $8,000,000 times (ii) 355,555.

Restricted Stock

During May 2002, the Company issued 95,000 shares of restricted stock to certain members of the Company’s management valued at $1.6 million. During the quarter ended March 31, 2003, the Company recognized approximately $47,000 as restricted stock compensation expense. Of the 95,000 shares that were issued, 10,832 shares had vested and were outstanding as of March 31, 2003. The remaining shares will vest either over a two-year period, when the Company’s stock price meets a certain price target or when there is a change of control, as defined by the plan documents.

(3)    DERIVATIVE ACTIVITIES

The following table details the Company’s derivative contract positions in place at March 31, 2003, which had a fair value liability of $3.0 million at that date.

Natural Gas Hedges (Mmbtu/d)
2003
Swaps - $5.02/Mmbtu (April - December)	50,000
2004
Swaps - $4.45/Mmbtu (January - December)	20,000
Collar - $4.00 x $5.15/Mmbtu (January - December)	20,000
Crude Oil Hedges (Bbls/d)
2003
Swaps - $29.62/Bbl (April - December)	1,000
2004
Swaps - $24.94/Bbl (January - December)	1,000

Through March 31, 2003, the Company has paid net cash settlements of approximately $15.0 million related to its derivative activities.

(4) ASSET RETIREMENT OBLIGATION

In August, 2001, the FASB issued SFAS 143, Accounting for Asset Retirement Obligations. SFAS 143 addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. The standard applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and (or) normal use of the asset. The Company currently has legal obligations to plug and abandon wells at the end of the assets’ useful lives.

F-66

3TEC ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

SFAS 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The fair value of the liability is added to the carrying amount of the associated asset and this additional carrying amount is depreciated over the life of the asset. Upon adoption of this statement on January 1, 2003, the Company recorded a cumulative effect accounting adjustment of $0.4 million, net of deferred tax expense of $0.3 million. Additionally, the Company established a liability for asset retirement obligations of $4.9 million, a corresponding increase in property, plant and equipment of $3.6 million and a decrease in accumulated DD&A of $0.6 million.

The following table describes the changes in the Company’s asset retirement obligations for the first quarter of 2003 (in thousands):

Asset retirement obligation at January 1, 2003	$	4,934
Liabilities incurred		78
Accretion expense		84
Asset retirement obligation at March 31, 2003	$	5,096

The following table summarizes the pro forma net income and earnings per share for the three months ended March 31, 2002 for the change in accounting principle had it been implemented on January 1, 2002:

	1st Quarter 2002 (in thousands, except per share data)
Net income
As Reported	$	(8,833	)
Pro Forma	$	(8,981	)
Net income per share—Reported
Basic	$	(0.54	)
Diluted	$	(0.54	)
Net income per share—Pro Forma
Basic	$	(0.54	)
Diluted	$	(0.54	)

In addition, on a pro forma basis as required by SFAS No. 143, had we adopted the provisions of SFAS No. 143 on January 1, 2002, the amount of the asset retirement obligations would have been as follows:

	Pro Forma Asset Retirement Obligation
	(In thousands)
January 1, 2002	$4,376
March 31, 2002	$4,483
December 31, 2002	$4,934

F-67

INDEPENDENT AUDITORS’ REPORT

The Board of Directors and Stockholders

3TEC Energy Corporation:

We have audited the accompanying consolidated balance sheets of 3TEC Energy Corporation and subsidiaries, as of December 31, 2002 and 2001, and the related consolidated statements of operations, changes in stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2002. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. 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 includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of 3TEC Energy Corporation and subsidiaries as of December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2002, in conformity with accounting principles generally accepted in the United States of America.

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

KPMG LLP

Houston, Texas

February 14, 2003

F-68

3TEC ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands, except share and per share data)

	As of December 31,
	2002			2001
ASSETS
Current Assets:
Cash and cash equivalents	$	2,249		$	17,762
Accounts receivable		17,486			16,835
Income tax receivable		—			4,464
Other		1,285			4,473
Total Current Assets		21,020			43,534
Properties and Equipment, at cost:
Oil and gas properties, successful efforts method		435,591			385,264
Other property and equipment		3,931			3,549
		439,522			388,813
Accumulated depletion, depreciation and amortization		(112,732	)		(71,039	)
Net Properties and Equipment		326,790			317,774
Other Assets, net		1,375			1,730
TOTAL ASSETS	$	349,185		$	363,038
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Accounts payable	$	13,440		$	25,052
Accrued liabilities		1,340			1,322
Series C Preferred stock redemption payable		1,272			1,349
Derivative fair value liability		3,551			—
Other current liabilities		3,055			1,468
Total Current Liabilities		22,658			29,191
Long-term debt		99,000			108,000
Deferred income taxes		44,563			45,135
TOTAL LIABILITIES		166,221			182,326
Commitments and Contingencies (Note 11)		—			—
STOCKHOLDERS’ EQUITY
Preferred stock, $.02 par value, 20,000,000 shares authorized, 266,667 shares designated Series B, 2,300,000 shares designated Series C and 725,167 shares designated Series D, none other designated		—			—
Convertible preferred stock Series B, $7.50 stated value, 266,667 shares issued and outstanding as of December 31, 2001. $2,000 aggregate liquidation preference		—			3,627
Convertible preferred stock Series D, 5% $24.00 redemption value, 613,919 shares and 614,776 issued and outstanding at December 31, 2002 and December 31, 2001, respectively, $14,734 aggregate liquidation preference at December 31, 2002		7,475			7,485
Common stock, $.02 par value, 60,000,000 shares authorized, 16,850,572 and 16,547,595 shares issued at December 31, 2002 and December 31, 2001, respectively.		337			331
Additional paid-in capital		157,557			151,412
Retained earnings		19,520			18,906
Treasury stock; 69,807 shares at December 31, 2002 and December 31, 2001		(1,049	)		(1,049	)
Deferred compensation		(876	)		—
TOTAL STOCKHOLDERS’ EQUITY		182,964			180,712
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	349,185		$	363,038

See accompanying notes to consolidated financial statements.

F-69

3TEC ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except share and per share data)

	Year Ended December 31,
	2002			2001		2000
REVENUES:
Oil, natural gas and plant income	$	103,064		$	116,080		102,148
Gain (loss) on sale of properties		(159	)		815		800
Gain (loss) on derivative fair value		(6,632	)		3,081		—
Gain (loss) on derivative settlements		(5,644	)		162		—
Other		473			836		813
TOTAL REVENUES	$	91,102		$	120,974	$	103,761
EXPENSES:
Production—
Lease operations	$	14,590		$	15,957	$	14,994
Production, severance and ad valorem tax		7,271			7,711		6,692
Gathering, transportation and other		3,465			3,002		1,493
Geological and geophysical		2,683			1,172		666
Dry hole and impairments		8,918			12,261		29
Surrendered and expired acreage		860			7,875		—
General and administrative		9,154			6,991		6,141
Stock compensation (general and administrative)		816			—		—
Interest		3,962			6,773		7,556
Depreciation, depletion and amortization		37,357			30,983		19,779
Other		629			250		—
TOTAL EXPENSES	$	89,705		$	92,975	$	57,350
NET INCOME BEFORE INCOME TAXES, MINORITY INTEREST AND DIVIDENDS TO PREFERRED STOCKHOLDERS		1,397			27,999		46,411
Minority Interest		—			511		305
Income Tax Expense		45			10,640		14,442
NET INCOME		1,352			16,848		31,664
Dividends to preferred stockholders		738			710		1,488
NET INCOME ATTRIBUTABLE TO COMMON STOCKHOLDERS	$	614		$	16,138	$	30,176
NET INCOME PER COMMON SHARE:
Basic	$	0.04		$	1.06	$	2.91
Diluted	$	0.03		$	0.91	$	2.28
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
Basic		16,533,405			15,170,116		10,382,836
Diluted		18,361,956			18,968,973		13,894,961

See accompanying notes to consolidated financial statements.

F-70

3TEC ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

	Year Ended
	December 31, 2002			December 31, 2001			December 31, 2000
OPERATING ACTIVITIES
Net income		1,352			16,848			31,664
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		36,758			30,265			18,713
Amortization of debt issue costs and other		599			967			1,066
Dry hole and impairments		8,918			12,261			29
Surrendered and expired leases		860			7,875			—
(Gain)/Loss on derivative fair value		6,632			(3,081	)		—
(Gain)/Loss on sale of properties		159			(815	)		(800	)
Deferred income taxes		(67	)		9,017			6,480
Minority interest		—			511			305
Restricted stock compensation (general and administrative)		816			—			—
Other changes		28			166			—
Changes in operating assets and liabilities:
Accounts receivable and other current assets		3,834			9,961			(21,706	)
Account payable and accrued liabilities		(10,087	)		5,805			8,717
CASH PROVIDED BY OPERATING ACTIVITIES		49,802			89,780			44,468
INVESTING ACTIVITIES
Proceeds from sales of oil and gas properties		1,181			36,818			5,840
Acquisition of Magellan Exploration LLC, net of cash acquired		—			—			418
Acquisition of Classic Resources, Inc., net of cash acquired		—			(58,670	)		—
Acquisition of Enex Resources Corporation		—			(3,803	)		—
Acquisition of oil and gas properties		(302	)		(22,380	)		(64,612	)
Development of oil and gas properties		(56,356	)		(72,554	)		(24,091	)
Additions of other assets		(391	)		(1,930	)		(1,326	)
CASH USED IN INVESTING ACTIVITIES		(55,868	)		(122,519	)		(83,771	)
FINANCING ACTIVITIES
Proceeds from long-term debt		51,000			130,000			66,100
Proceeds from issuance of common stock		—			—			68,103
Proceeds from exercise of stock options and warrants		616			1,590			705
Payments on long-term debt		(60,000	)		(85,000	)		(90,600	)
Preferred stock dividends		(738	)		(525	)		(1,369	)
Treasury stock purchase—Alabama dissenters		—			—			(981	)
Redemption of Preferred Series C stock		—			—			(1,433	)
Debt issuance costs		(325	)		—			(2,927	)
CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES		(9,447	)		46,065			37,598
(DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS		(15,513	)		13,326			(1,705	)
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD		17,762			4,436			6,141
CASH AND CASH EQUIVALENTS, END OF PERIOD	$	2,249		$	17,762		$	4,436
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid during the year for:
Interest	$	3,915		$	6,795		$	7,539
Income Taxes		—			10,571			3,500
Non-cash investing and financing activities:
Common stock and warrants issued in acquisition of Magellan Exploration LLC		—			—			10,573
Preferred Stock Series D issued in acquisition of Magellan Exploration LLC		—			—			7,453
Preferred Stock Series C conversions to common stock		—			—			362
Preferred dividends incurred but not paid		185			185			—
Common stock repurchase contingency accrual—Alabama dissenters		—			—			138
Conversion of Preferred Series C into Common Stock		—			—			910
Preferred dividends paid in-kind		—			—			118
Liability for redemption of Preferred Stock Series C		—			—			2,856
Deferred taxes recorded in acquisition of Classic Resources, Inc.		—			29,347			—
Preferred Stock Series B conversions to Common Stock		3,627			—			—
Preferred Stock Series D conversions to Common Stock		10			—			—

See accompanying notes to consolidated financial statements.

F-71

3TEC ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY

YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000

(in thousands, except shares)

	Preferred Stock
	Series B					Series C					Series D					Common Stock					Paid-in Capital			Accumulated Earnings (Deficit)			Deferred Compensation			Treasury Stock Par			Stockholders’ Equity
	Shares		Par			Shares		Par			Shares		Par			Shares		Par
Balance January 1, 2000	266,667		$	3,627		1,139,506		$	5,198		—			—		5,338,771		$	107		$	57,775		$	(27,408	)				$	(1,187	)	$	38,112
Common stock issued in merger with Magellan Exploration LLC																1,085,934			22			10,251												10,273
Warrants issued in merger with Magellan Exploration LLC																						300												300
Preferred Series D issued in merger with Magellan Exploration LLC											617,009			7,453																				7,453
Stockholder dissenters repurchase contingency adjustment																															138			138
Preferred Series C conversions						(72,496	)		(362	)						63,465			1			361												—
Common stock issued																8,050,000			161			67,943												68,104
Common stock offering and registration costs																						(1,497	)											(1,497	)
Preferred Series C redemption						(1,067,010	)		(4,836	)						36,527			1			547												(4,288	)
Reverse split fractional shares																(314	)																	—
Employee stock option exercises																95,190			2			648												650
Warrant exercises																18,333						55												55
Net Income																									31,664									31,664
Preferred stock dividends											4,921			119											(1,488	)								(1,369	)
Balance December 31, 2000	266,667		$	3,627		—			—		621,930		$	7,572		14,687,906		$	294		$	136,383		$	2,768		$	—		$	(1,049	)	$	149,595
Employee stock option exercises																81,682			2			739												741
Preferred Series D Conversions											(7,154	)		(87	)	7,154						85												(2	)
Warrant exercises																283,047			6			843												849
Senior subordinated debt conversions																1,487,806			29			13,362												13,391
Net Income																									16,848									16,848
Preferred stock dividends																									(710	)								(710	)
Balance December 31, 2001	266,667		$	3,627		—		$	—		614,776		$	7,485		16,547,595		$	331		$	151,412		$	18,906		$	—		$	(1,049	)	$	180,712
Employee Stock Option Exercises																58,817			1			615												616
Preferred Series B Conversions	(266,667	)		(3,627	)											186,230			4			3,623												—
Preferred Series D Conversions											(857	)		(10	)	857						10												—
Common Stock Issues																1,799						26												26
Restricted Stock Grants																95,000			2			1,690						(876	)					816
Net Income																									1,352									1,352
Preferred Stock Dividends																									(738	)								(738	)
Employee Stock Option Deferred Tax Adjustment																						181												181
Other																(39,726	)		(1	)														(1	)
Balance December 31, 2002	—		$	—		—		$	—		613,919		$	7,475		16,850,572		$	337		$	157,557		$	19,520		$	(876	)	$	(1,049	)	$	182,964

See accompanying notes to consolidated financial statements

F-72

3TEC ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2002, 2001 and 2000

(1)    ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Organization

3TEC Energy Corporation, (formerly Middle Bay Oil Company, Inc.), was incorporated under the laws of the state of Alabama on November 20, 1992. The Company was reincorporated in Delaware on December 7, 1999 and changed its name to 3TEC Energy Corporation. The reincorporation and name change were part of a series of transactions related to a securities purchase agreement that closed on August 27, 1999 between the Company and W/E Energy Company, LLC (“W/E LLC”), formerly known as 3TEC Energy Company, LLC, whereby the Company received $21.4 million in cash and oil and natural gas properties for the sale of common stock, warrants and debt securities (See Note 3).

3TEC Energy Corporation (the “Company”) is engaged in the acquisition, development, production and exploration of oil and natural gas in the contiguous United States. The Company considers its business to be a single operating segment. Effective November 23, 1999, the Company acquired oil and natural gas properties and interests managed by Floyd Oil Company from a group of private sellers. Effective February 3, 2000, the Company acquired oil and natural gas properties through a merger with Magellan Exploration, LLC. Effective May 31, 2000, the Company acquired oil and natural gas properties from C.W. Resources, Inc. Effective November 15, 2000, the Company acquired oil and natural gas properties from H.G. Westerman and a group of private sellers. Effective January 30, 2001, the Company acquired oil and natural gas properties through the purchase of the stock of Classic Resources, Inc.

On February 2, 2003, the Company entered into a definitive agreement with Plains Exploration & Production Company (“Plains”) whereby Plains will acquire the Company for a combination of cash and stock. Under the terms of the agreement, the Company’s shareholders will receive $8.50 in cash and 0.85 shares of Plains’s Common Stock for each share of the Company’s Common Stock, subject to certain adjustments if the average share price of Plains’s Common Stock (as determined during a twenty-day trading period prior to closing) is less than $7.65 per share or greater than $12.35 per share. Although subject to shareholder approval and other customary closing conditions, the aforementioned transaction is expected to close during the second quarter of 2003.

Significant Accounting Policies

The Company’s accounting policies reflect industry standards and conform to generally accepted accounting principles. The more significant of such policies are described below.

Principles of Consolidation

The consolidated financial statements include the accounts of the Company and Enex Resources Corporation (“Enex”) which prior to December 31, 2001 was an 80% owned subsidiary. The equity of the minority interests in Enex is reflected in the consolidated financial statements as “minority interest”. On December 31, 2001, the Company acquired the remaining 20% of Enex pursuant to the merger of Enex into a wholly-owned subsidiary of the Company for cash consideration of $3.8 million. All significant intercompany balances and transactions have been eliminated in consolidation.

Reclassifications

Certain prior-year amounts have been reclassified to conform with current year presentation.

F-73

3TEC ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

December 31, 2002, 2001 and 2000

Consolidated Statements of Cash Flows

For the purpose of cash flows, the Company considers all highly liquid investments with a maturity date of three months or less to be cash equivalents. Significant transactions may occur which do not directly affect cash balances and as such will not be disclosed in the Consolidated Statements of Cash Flows. Certain of such non-cash transactions are disclosed in the Consolidated Statements of Shareholders’ Equity relating to shares issued as compensation, and shares issued for stock and debt of an acquired company.

Oil and Gas Properties

The Company follows the successful efforts method of accounting for oil and natural gas properties, and accordingly, capitalizes all direct costs incurred in connection with the acquisition, drilling and development of productive oil and natural gas properties. Costs associated with unsuccessful exploration are charged to expense currently. Geological and geophysical costs and costs of carrying and retaining unevaluated properties are charged to expense. Depreciation, depletion and amortization of capitalized costs are computed separately for each field based on the unit-of-production method using only proved oil and natural gas reserves. In arriving at such rates, commercially recoverable reserves have been estimated by an independent petroleum engineering firm. The Company reviews its undeveloped properties continually and charges them to expense on a property-by-property basis when it is determined that they have been condemned by dry holes, or have otherwise diminished in value. For the years ended December 31, 2002, 2001 and 2000, the Company recorded surrendered and expired acreage expense on its undeveloped properties of $0.9 million, $7.9 million and $-0-, respectively. Gains and losses are recorded on sales of interests in proved properties and on sales of entire interests in unproved properties. The Company realized losses on sales of properties of $0.2 million for the year ended December 31, 2002 and gains of $0.8 million for both years ended December 31, 2001 and 2000.

Proved oil and natural gas reserves are the estimated quantities of oil, natural gas and natural gas liquids which are expected to be recoverable in future years from known reservoirs under existing economic and operating conditions. Reservoirs are considered proved if economic productability is supported by either actual production or conclusive formation tests.

The Company reviews long-lived assets for impairment when events or changes in circumstances indicate that the carrying value of such an asset may not be recoverable. This review consists of a comparison of the carrying value of the asset to the asset’s expected future undiscounted cash flows. Estimates of expected future cash flows represent management’s best estimate based on reasonable and supportable assumptions and projections. If the expected future cash flows, assuming escalated prices, are less than the carrying value of the asset, an impairment exists and is measured as the excess of the carrying value over the estimated fair value of the asset. The Company estimates discounted future net cash flows to determine fair value. Any impairment provisions recognized are permanent and may not be restored in the future. For the years ended December 31, 2002, 2001 and 2000, the Company’s proved properties were assessed for impairment on an individual field basis and the Company recorded impairment provisions on certain producing properties of $5.6 million, $3.4 million, and $-0- respectively.

Revenue Recognition of Production Imbalances

Oil and natural gas revenues are recorded using the sales method, whereby the Company recognizes revenues based on the amount of oil and natural gas sold to purchasers on its behalf not-withstanding its ownership percentage. At December 31, 2002 and 2001, the Company’s net imbalance position was immaterial.

F-74

3TEC ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

December 31, 2002, 2001 and 2000

Hedging

In June 1998, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities (“SFAS 133”). In June 2000, the FASB issued SFAS 138, Accounting for Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133. SFAS 133, as amended, establishes accounting and reporting standards requiring that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded in the balance sheet as either an asset or liability measured at its fair market value. The statement requires that changes in the derivative’s fair value be recognized currently in earnings unless specific hedge criteria are met. Special accounting for qualifying hedges allows a derivative’s gains and losses to offset related results on the hedged item in the statement of operations, and requires that a company must formally document, designate and assess the effectiveness of transactions that receive hedge accounting. The Company adopted SFAS 133 effective January 1, 2001. Based upon the historical volatility of oil and gas commodity prices, the Company expects that SFAS 133 will increase volatility in the Company’s earnings and other comprehensive income for periods where hedging activities are present.

SFAS 133, in part, allows hedge accounting. SFAS 133 provides that the effective portion of the gain or loss on a derivative instrument designated and qualifying as a cash flow hedging instrument be reported as a component of other comprehensive income and be reclassified into earnings in the same period during which the hedged forecasted transaction affects earnings. The remaining gain or loss on the derivative instrument, if any, must be recognized currently in earnings.

To qualify for cash flow hedge accounting, the cash flows from the hedging instrument must be highly effective in offsetting changes in cash flows due to changes in the underlying items being hedged. In addition, all hedging relationships must be designated, documented, and reassessed periodically. The Company’s natural gas derivative instruments entered into during the periods presented were not designated as hedges at the time the instruments were executed. In accordance with provisions of SFAS 133, these instruments were marked-to-market through earnings at December 31, 2002 and 2001, resulting in a decrease to revenues of $6.6 million and an increase to revenues of $3.1 million during those annual periods, respectively.

Earnings Per Share

Basic earnings and loss per common share are based on the weighted average shares outstanding without any dilutive effects considered. Diluted earnings and loss per share reflect dilution from all potential common shares, including options, warrants and convertible preferred stock and convertible notes. Diluted loss per share does not include the effect of any potential common shares if the effect would be to decrease the loss per share.

At December 31, 2002, 2001 and 2000, the Company had a weighted average of 2,442,929, 3,798,857 and 3,512,000 combined stock options, warrants and convertible preferred stock and notes outstanding included in the Company’s fully diluted per share calculation, respectively.

F-75

3TEC ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

December 31, 2002, 2001 and 2000

Basic and diluted earnings per share for the years ended December 31, 2002, 2001 and 2000 were determined as follows (in thousands):

	2002			2001		2000
Basic net income attributable to common shareholders	$	614		$	16,138	$	30,176
Plus preferred stock dividends		—	(1)		710		1,488
Plus interest expense (net of tax) on subordinated convertible notes		—			505		—
Fully diluted net income attributable to common shareholders	$	614		$	17,353	$	31,664
Basic shares outstanding (weighted average shares)		16,533			15,170		10,383
Plus potentially dilutive securities:
Ÿ Dilutive options and warrants applying treasury stock method		1,688			2,052		1,390
Ÿ  Shares from conversion of subordinated convertible notes					996		1,469
Ÿ  Shares from conversion of Series B preferred stock		127			132		91
Ÿ  Shares from conversion of Series D preferred stock		—			619		562
Ÿ  Non-vested restricted stock		14			—		—
Fully diluted shares outstanding (weighted average shares)		18,362			18,969		13,895

(1) Preferred stock dividends in the amount of $738,000 were not included in the 2002 calculation as they were antidilutive.

All share and per share amounts have been retroactively adjusted for a one-for-three reverse split that was approved by the Company’s shareholders on January 14, 2000.

Income Taxes

Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.

F-76

3TEC ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

December 31, 2002, 2001 and 2000

Stock Compensation

Stock-based employee compensation is accounted for under the intrinsic value method of Accounting Principles Bulletin No. 25 “Accounting for Stock Issued to Employees.” For the years ending December 31, 2002, 2001 and 2000, the exercise price of the options granted is equal to the quoted market price of the Company’s stock at the grant date, and therefore, no compensation costs have been recognized for its stock option plans. Had compensation cost for the Company’s Plans been determined based on the fair value at the grant date for stock options granted for the years ending December 31, 2002, 2001 and 2000, the Company’s net income and income per share would have been adjusted to the pro forma amounts listed below (in thousands, except per share amounts):

	December 31,
	2002			2001			2000
Net Income attributable to Common Stockholders
As Reported	$	614		$	16,138		$	30,176
Add: Stock-based employee compensation expense included and reported in net income, net of tax		530			—			—
Less: Total stock-based employee compensation expense determined under fair value based methods for all awards net of related tax effects		(3,098	)		(2,691	)		(8,287	)
Pro Forma	$	(1,954	)	$	13,447		$	21,889
Net Income per common share, basic
As Reported	$	0.04		$	1.06		$	2.91
Pro Forma	$	0.04		$	0.89		$	2.11
Net Income per common share, diluted
As Reported	$	0.03		$	0.91		$	2.28
Pro Forma	$	0.03		$	0.77		$	1.58

The fair value of grants was estimated on the date of grant using the Black Scholes option pricing model with the following weighted-average assumptions used in 2002, 2001 and 2000, respectively: risk free interest rates of 4.30%, 3.96% and 6.48%, expected volatility of 65%, 69% and 72%, no dividend yield, and an expected life of the option of 3 years in 2002, 2001 and 2000. The weighted average fair value of stock options granted in 2002, 2001 and 2000 was $6.33, $7.02 and $5.72 per share, respectively.

Concentrations of Market Risk

The future results of the Company will be affected by the market prices of oil and natural gas. The availability of a ready market for oil and natural gas in the future will depend on numerous factors beyond the control of the Company, including weather, production of other oil and natural gas, imports, marketing of competitive fuels, proximity and capacity of oil and natural gas pipelines and other transportation facilities, any oversupply or undersupply of oil and natural gas, the regulatory environment, and other regional and political events, none of which can be predicted with certainty.

Concentrations of Credit Risk

Financial instruments which subject the Company to concentrations of credit risk consist primarily of cash and accounts receivable. The Company places its cash investments with high credit qualified financial

F-77

3TEC ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

December 31, 2002, 2001 and 2000

institutions. Risk with respect to receivables is concentrated primarily in the current production revenue receivable from multiple oil and natural gas purchasers, and is typical in the industry. Concentrations within the industry have the potential to impact the Company’s overall exposure to credit risk, either positively or negatively, in that the customer base may be similarly affected by changes in economic, industry or other conditions. For 2002, Superior Natural Gas Corporation, Conoco Inc. and Wagner & Brown, Ltd. accounted for approximately 15%, 14% and 11% of total oil and gas sales, respectively. Calpine Producer Services, L.P. (formerly Highland Energy Company) and Wagner & Brown, Ltd. accounted for approximately 22% and 19% of total oil and natural gas sales, respectively, for the year ended December 31, 2001. No single customer accounted for greater than 10% of the Company’s total oil and natural gas sales for the year ended December 31, 2000.

Use of Estimates

Management of the Company has made a number of estimates and assumptions relating to the reporting of assets and liabilities to prepare the financial statements in conformity with generally accepted accounting principles. Actual results could differ from these estimates.

Accounting Pronouncements

In October, 2001, the FASB issued SFAS 144, Accounting for the Impairment or Disposal of Long-Lived Assets, which addresses financial accounting and reporting for the impairment or disposal of long-lived assets. While SFAS 144 supersedes SFAS 121, Accounting for the Impairment of Long-Lived Assets and for Long Lived Assets to Be Disposed Of, it retains many of the fundamental provisions of that Statement.

SFAS 144 also supersedes the accounting and reporting provisions of APB Opinion No. 30, Reporting the Results of Operations—Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions, for the disposal of a segment of business. However, it retains the requirement in Opinion 30 to report separately discontinued operations and extends that reporting to a component of an entity that either has been disposed of (by sale, abandonment, or in a distribution to owners) or is classified as held for sale. By broadening the presentation of discontinued operations to include more disposal transactions, the FASB has enhanced managements ability to provide information that helps financial statement users to assess the effects of a disposal transaction on the ongoing operations of an entity.

In August, 2001, the FASB issued SFAS 143, “Accounting for Asset Retirement Obligations”. SFAS 143 addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. The standard applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and (or) normal use of the asset. SFAS 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The fair value of the liability is added to the carrying amount of the associated asset and this additional carrying amount is depreciated over the life of the asset. The liability is accreted at the end of each period through charges to operating expense. If the obligation is settled for other than the carrying amount of the liability, the Company will recognize a gain or loss on settlement. The Company adopted SFAS No. 143 as of January 1, 2003. Upon adoption of this statement, the Company expects to record a cumulative effect accounting adjustment of between $0.1 million and $1.0 million, net of deferred tax expense of between $0.03 million and $0.5 million. Additionally, the Company expects to establish a liability for asset retirement obligations of between $4.0 million and $6.0 million, a corresponding increase in property, plant and equipment of between $3.0 million and $5.0 million and a decrease in accumulated DD&A of between $0.1 million and $1.0 million in the Company’s balance sheets.

F-78

3TEC ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

December 31, 2002, 2001 and 2000

During second quarter 2002 the FASB issued SFAS No. 145, Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections. This statement rescinds SFAS No. 4, Reporting Gains and Losses from Extinguishment of Debt, and requires that all gains and losses from extinguishment of debt should be classified as extraordinary items only if they meet the criteria in APB No. 30. Applying APB No. 30 will distinguish transactions that are part of an entity’s recurring operations from those that are unusual or infrequent or that meet the criteria for classification as an extraordinary item. Any gain or loss on extinguishment of debt that was classified as an extraordinary item in prior periods presented that does not meet the criteria in APB No. 30 for classification as an extraordinary item must be reclassified. The Company does not expect that there will be any current impact from SFAS No. 145.

The FASB issued SFAS No. 146, Accounting for Costs Associated with Exit or Disposal Activities, in June 2002. This statement addresses financial accounting and reporting for costs associated with exit or disposal activities and nullifies Emerging Issues Task Force Issue No. 94-3, Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring). SFAS No. 146 applies to costs incurred in an “exit activity,” which includes, but is not limited to, a restructuring, or a “disposal activity” covered by SFAS No. 144. SFAS No. 146 will be effective for the Company in January 2003.

In December 2002, SFAS No. 148, “Accounting for Stock-Based Compensation—Transition and Disclosure—an amendment of FASB Statement No. 123” was issued. SFAS 148 amends SFAS 123, “Accounting for Stock-Based Compensation”, to provide alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. In addition, this Statement amends the disclosure requirements of SFAS 123 to require prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on reported results. The provisions of SFAS 148 are effective for financial statements for fiscal years ending after December 15, 2002. SFAS 148 does not change the provisions of SFAS 123 that permit entities to continue to apply the intrinsic value method of Accounting Principles Bulletin No. 25, “Accounting for Stock Issued to Employees”. We have and will continue to account for stock-based compensation in accordance with the provisions of APB No. 25.

During 2002, the FASB issued two interpretations: FIN 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others” and FIN 46 “Consolidation of Variable Interest Entities”. There was no current impact of FIN 45 or FIN 46 on the Company’s financial position or results of operations.

(2)    ACQUISITIONS AND DIVESTITURES

On January 30, 2001, the Company acquired 100% of the issued and outstanding stock of Classic Resources Inc. (the “Classic Acquisition”) for cash consideration of approximately $53.5 million plus other acquisition costs. The operating results of the Classic Acquisition have been included in the consolidated financial statements since that date. Classic was a privately-held exploration and production company with properties located in East Texas. The Company’s estimate of total net proved reserves at the time of the acquisition for Classic’s oil and gas properties was 47 Bcfe and net daily production of approximately 11 Mmcfe. The Company financed the acquisition under its existing Credit Facility. The purchase price of the Classic Acquisition was allocated principally to proved properties, with additional amounts allocated to working capital related to amounts recorded for production related receivables and payables in existence and accrued for at January 30, 2001.

F-79

3TEC ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

December 31, 2002, 2001 and 2000

On May 31, 2000, we completed the acquisition of the CWR Properties (the “CWR Acquisition”) located in East Texas for cash consideration of approximately $51.7 million. Operating results from this acquisition are included in the Company’s consolidated financial statements beginning June 1, 2000. The CWR Acquisition was financed under our existing Credit Facility, which we amended prior to closing the acquisition. The total purchase price was allocated principally to oil and natural gas properties using the purchase method of accounting.

On February 3, 2000, we completed the acquisition of Magellan Exploration LLC (the “Magellan Acquisition”), from certain affiliates of EnCap Investments L.L.C. (“EnCap”), a Delaware limited liability company and an investor in W/E LLC, and other third parties for consideration consisting of (a) 1,085,934 shares of common stock, (b) four-year warrants to purchase up to 333,333 shares of common stock at $30.00 per share, (c) 617,009 shares of 5% Series D Convertible Preferred Stock with a redemption value of $24.00 per share and (d) the assignment of a performance based “back-in” working interest of 5% of Magellan’s interest in 12 exploration prospects. The total purchase price of approximately $19 million was allocated principally to proved undeveloped oil and natural gas properties using the purchase method of accounting.

The following pro forma data presents the results of the Company for the year ended December 31, 2000, as if the Classic Acquisition and the CWR Acquisition had occurred on January 1, 2000, and the results of the Company for the year ended December 31, 2001 as if the Classic Acquisition had occurred on January 1, 2001. The unaudited pro forma data assumes the acquisition of the respective properties and the debt financing transactions related to these acquisitions. The unaudited pro forma results are presented for comparative purposes only and are not necessarily indicative of the results which would have been obtained had the acquisitions been consummated as presented. (in thousands, except per share amounts):

	Pro Forma Year Ended December 31, 2001		Pro Forma Year Ended December 31, 2000
	(unaudited)		(unaudited)
Total revenues	$	120,008	$	120,662
Net income attributable to common stockholders		13,958		24,266
Net income per basic share attributable to common stockholders	$	0.92	$	2.34

During 2001, the Company completed the sale of certain non-strategic oil and gas properties for net cash proceeds of approximately $36.7 million. In order to defer the tax gain on the sales of the properties, the Company successfully replaced a portion of these properties in accordance with the Like-Kind Exchange regulations of the Internal Revenue Service. At December 31, 2001, the Company had $13.9 million of cash in like-kind escrow accounts. In January 2002, the like-kind replacement term expired in accordance with the Internal Revenue Service regulations and the balance of the escrow accounts were used to reduce borrowings under the Company’s Credit Facility.

(3) COMMON STOCK, WARRANT AND SENIOR SUBORDINATED CONVERTIBLE NOTE SALE TO W/E ENERGY COMPANY, L.L.C. (“W/E LLC”)

On August 27, 1999, the Company closed a Securities Purchase Agreement (the “Agreement”) for a total of $21.4 million with W/E LLC. The Securities Purchase Agreement and contemplated transactions were approved by the stockholders at the Company’s annual meeting on August 10, 1999.

The controlling person of W/E LLC was EnCap. The sole member of EnCap is El Paso Field Services Company, a Delaware corporation (“El Paso Field Services”). The controlling person of El Paso Field Services is

F-80

3TEC ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

December 31, 2002, 2001 and 2000

El Paso Corporation, a Delaware corporation. The Company received $9.8 million in cash and properties valued at $875,000 for 1,585,185 shares of common stock and 1,200,000 warrants (the “Warrants”) and $10.7 million for a 5-year senior subordinated convertible note with a face value of $10.7 million (See Note 6).

On November 28, 2001, W/E LLC was dissolved and all shares of common stock and warrants of the Company held by W/E LLC were distributed to its members.

(4)    RELATED PARTY TRANSACTIONS

David B. Miller and D. Martin Phillips, directors of the Company, are managing directors of EnCap, which was the controlling person of W/E LLC. Floyd C. Wilson, Chairman and Chief Executive Officer of the Company, was also a member of W/E LLC. Gary R. Christopher, a shareholder and director of the Company until December 31, 2001, is employed by Kaiser-Francis Oil Co., which owns approximately 7% of the common stock of the Company as of December 31, 2002.

In 2000, the Company paid EnCap a fee of $500,000 in connection with a private equity shelf facility related to the CWR Acquisition. As required by the Company’s Credit Facility, the private equity shelf facility would have allowed the Company to require EnCap Investments to purchase up to $20 million of a new class of exchangeable preferred stock from the Company. Upon completion of the Company’s public offering of common stock on June 30, 2000, the shelf facility expired.

The Company has a $250 million credit facility (the “Credit Facility”) with Bank One, NA, as administrative agent, Bank of Montreal, as syndication agent, and Union Bank of California, N.A., Wells Fargo Bank Texas, N.A., CIBC, Inc., Comerica Bank, Fleet National Bank and The Bank of Nova Scotia as participating lenders. The borrowing base is redetermined semi-annually and as of December 31, 2002, was $160 million. In addition, the Company is a party to certain derivative contracts that Bank One, NA is the counterparty to. These derivative contracts cover a portion of the Company’s anticipated natural gas and oil production for 2003 and 2004. Larry L. Helm, a director of the Company, is responsible for the nationwide Middle Market Banking Group of Bank One Corporation.

(5)    LONG-TERM DEBT

Long-term debt at December 31, 2002 and 2001, consisted of the following (in thousands):

	2002		2001
$250 million Credit Facility	$	99,000	$	108,000
Less current maturities		—		—
Long-term debt excluding current maturities	$	99,000	$	108,000

The Company’s Credit Facility is with Bank One, NA as agent and seven other banks. The Credit Facility as amended, matures August 31, 2004. As of December 31, 2002, the borrowing base was $160 million. The borrowing base is to be redetermined semi-annually on May 1 and November 1 and provides for interest as revised under the Credit Facility to accrue at a rate calculated at the Company’s option as either the bank’s prime

F-81

3TEC ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

December 31, 2002, 2001 and 2000

rate plus a low of zero to a high of 37.5 basis points or LIBOR plus basis points increasing from a low of 150 to a high of 200 as loans outstanding increase as a percentage of the borrowing base. As of December 31, 2002, the Company was paying an average of 2.99% per annum interest on the principal balance of $99 million under the Credit Facility. Prior to maturity, no payments of principal are required so long as the borrowing base exceeds the loan balance. The borrowings under the Credit Facility are secured by substantially all of the Company’s oil and natural gas properties. At December 31, 2002, the amount available to be borrowed under the Credit Facility was approximately $61 million.

The Credit Facility is governed by various financial and other covenants, including requirements to maintain a current ratio of one to one (1:1), and an interest rate coverage ratio of 2.5 to 1. Additionally, limitations on asset dispositions, declaration and payment of cash dividends and the entering into hedge transactions without the bank’s consent are included. Aggregate amounts of expected required repayments of long term debt at December 31, 2002 are as follows (in thousands):

2002	$	—
2003		—
2004		99,000
Thereafter		—
Total	$	99,000

(6)    SENIOR SUBORDINATED CONVERTIBLE NOTES

On August 27, 1999, senior subordinated convertible promissory notes (the “Senior Subordinated Notes”) were sold to W/E LLC and affiliates of Alvin V. Shoemaker (“Shoemaker”), a former director and significant shareholder, for $10.7 million and $0.2 million, respectively. On October 19, 1999, $2.4 million of Senior Subordinated Notes were sold to The Prudential Insurance Company of America (“Prudential”). The Senior Subordinated Notes bore interest at an annual rate of 9%. Interest was payable beginning on December 31, 1999, every March 31, June 30, September 30 and December 31, until maturity on August 27, 2004. The Company could defer payment of fifty percent (50%) of the first eight quarterly interest payments. The Senior Subordinated Notes could be prepaid, without premium or penalty, in whole or in part, at any time after August 27, 2001. The holders of the Senior Subordinated Notes could convert all or any portion of outstanding principal and accrued interest at any time into shares of Company common stock at a conversion price of $9.00 per common share, a total of 1,469,316 common shares. The conversion price could be adjusted from time to time based on the occurrence of certain events. In the event of a change in control, the entire outstanding principal balance and all accrued but unpaid interest would be immediately due and payable.

The Senior Subordinated Notes ranked senior in right of payment to all Company notes and indebtedness other than the Credit Facility.

During the second quarter of 2001, the Company received notice of an election by Shoemaker to convert approximately $0.2 million of Senior Subordinated Notes. The conversion resulted in the retirement of $0.2 million in senior subordinated debt and the issuance of an additional 16,666 shares of common stock of the Company.

During the third quarter of 2001, the Company sent notice of an election to W/E LLC to prepay the $10.7 million of Senior Subordinated Notes. Pursuant to the terms of the convertible note agreement, W/E LLC elected

F-82

3TEC ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

December 31, 2002, 2001 and 2000

instead to exercise its right to convert the principal and accrued interest outstanding into common shares of the Company. Under the terms of the convertible note agreement, the balance of the note plus any accrued interest was to be converted at $9.00 per share. The conversion by W/E LLC resulted in the retirement of approximately $10.7 million in senior subordinated debt and the issuance of an additional 1,206,127 shares of common stock of the Company.

During the fourth quarter of 2001, the Company received notice of an election by Prudential to convert approximately $2.4 million of Senior Subordinated Notes. The conversion resulted in the retirement of $2.4 million in senior subordinated debt and the issuance of an additional 265,013 shares of common stock of the Company.

(7)    INCOME TAXES

The components of income tax expense for the years ended December 31, 2002, 2001 and 2000 consisted of the following (in thousands):

	2002									2001						2000
	Federal			State			Total			Federal		State		Total		Federal		State		Total
Current	$	438		$	179		$	617		$	1,143	$	479	$	1,622	$	6,120	$	1,842	$	7,962
Deferred		(427	)		(146	)		(573	)		7,582		1,436		9,018		6,224		256		6,480
Total	$	11		$	33		$	44		$	8,725	$	1,915	$	10,640	$	12,344	$	2,098	$	14,442

The reconciliation of income tax computed at the U.S. federal statutory tax rates to the provision for income taxes is as follows (in thousands):

	December 31,
	2002			2001			2000
Income tax provision at statutory rate	$	489		$	9,800		$	16,137
State income taxes, net of federal benefit		70			1,224			1,364
Decrease in valuation allowance		—			—			(2,523	)
Utilization of Sec. 29 tax credits		(500	)		(500	)		(400	)
Other		(15	)		116			(136	)
Total	$	44		$	10,640		$	14,442

F-83

3TEC ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

December 31, 2002, 2001 and 2000

The Company’s net deferred tax liability at December 31, 2002 and 2001 is as follows (in thousands):

	2002			2001			2000
Deferred tax liability
Basis difference in oil and natural gas properties	$	45,709		$	47,563		$	9,547
Deferred tax asset
NOL carryforward		(3,868	)		(5,237	)		(5,812	)
AMT tax credit carryforward		(4,367	)		(327	)		(36	)
Other		(408	)		(430	)		(495	)
		(4,712	)		(5,994	)		(6,343	)
Valuation allowance		3,566			3,566			3,566
Net deferred tax liability	$	44,563		$	45,135		$	6,770

In connection with the Classic Acquisition, the Company recorded $29.3 million in deferred taxes for the future tax impact of the difference between the allocated book basis and the historical tax basis of the Classic Properties.

In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax asset will not be realized. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income, and tax planning strategies in making this assessment. Based upon projections for future taxable income over the periods in which the deferred tax assets are deductible and the Section 382 limitation discussed below, management believes it is more likely than not that the Company will realize the benefits of these deductible differences, net of the existing valuation allowances at December 31, 2002, 2001 and 2000. The net change in the total valuation allowance for the years ended December 31, 2002, 2001 and 2000 was $-0-, $-0- and $2.5 million and the amount remaining at December 31, 2002 is $3.6 million.

The Enex acquisition caused an ownership change pursuant to Section 382 in March 1998. As a result of this ownership change, the Company’s use of its net operating loss carryforwards subsequent to that date will be limited. The Floyd Oil Acquisition in November 1999 also caused an ownership change pursuant to Section 382. As a result of these changes, the Company’s use of its net operating loss carryforwards subsequent to that date will be limited. In February 2000, Enex had an ownership change pursuant to Section 382 with respect to its net operating losses.

As of December 31, 2002, the Company had net operating loss carryforwards of approximately $11.1 million, expiring beginning in 2009 through 2019.

(8)    RETIREMENT PLAN AND EMPLOYEE INCENTIVE PLAN

All of the employees of the Company are eligible to participate in a defined contribution plan that provides for the maximum employee contributions permissible under the Internal Revenue Code and discretionary Company contributions. Company contributions made to the plan for the years ending December 31, 2002, 2001 and 2000 were $365,172, $462,763 and $135,225, respectively.

F-84

3TEC ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

December 31, 2002, 2001 and 2000

(9)    STOCK OPTION PLANS

The Company’s stock option plans authorize the granting of options to key employees and non-employee directors at prices equivalent to the market value at the date of grant. Options generally become exercisable in the following manner: 50% upon the date of grant with the remaining 50% exercisable in three annual installments commencing one year after the date of grant and, if not exercised, expire 10 years from the date of grant.

A summary of the status of the Company’s plans as of December 31, 2002, 2001 and 2000, and changes during the years ended on those dates is presented below:

	Shares		Average Exercise Price Per Share
Options outstanding at January 1, 2000	335,922		$	15.00
Granted in 2000	2,898,500		$	11.07
Exercised in 2000	(95,190	)	$	6.83
Forfeited in 2000	(248,160	)	$	16.39
Options outstanding at January 1, 2001	2,891,072		$	11.15
Granted in 2001	502,835		$	14.67
Exercised in 2001	(81,682	)	$	9.12
Forfeited in 2001	(36,729	)	$	18.53
Options outstanding at January 1, 2002	3,275,496		$	11.66
Granted in 2002	269,500		$	13.71
Exercised in 2002	(58,817	)	$	10.54
Forfeited in 2002	(14,833	)	$	16.50
Options outstanding at December 31, 2002	3,471,346		$	11.82
Options outstanding at December 31, 2001	3,275,496		$	11.66
Options outstanding at December 31, 2000	2,891,072		$	11.15
Options exercisable at December 31, 2002	2,605,528		$	11.49
Options exercisable at December 31, 2001	2,058,765		$	11.45
Options exercisable at December 31, 2000	1,442,995		$	11.16
Options available for grant at December 31, 2002	757,360
Options available for grant at December 31, 2001	1,012,527
Options available for grant at December 31, 2000	275,298

At December 31, 2002, the range of exercise prices and weighted average remaining contractual life of options outstanding was $4.50 to $18.56 and 7.9 years, respectively.

Warrants to purchase 1,216,822 shares and 266,226 shares of common stock at $3.00 per share, which were issued on August 27, 1999 and October 19, 1999, respectively, and warrants to purchase 333,333 shares of common stock at $30.00 per share, which were issued on February 3, 2000, are excluded from the table above because the warrants were issued in conjunction with the sales of stock and are not stock-based compensation. During 2002, no warrants were exercised.

F-85

3TEC ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

December 31, 2002, 2001 and 2000

(10)    STOCKHOLDERS’ EQUITY

Preferred Stock—Series B

In connection with the merger with Shore Oil Company, effective June 30, 1997, the Company issued 266,667 shares of Series B Preferred Stock (“Series B”). The Series B is nonvoting and pays no dividends. The Series B has a liquidation value of $7.50 per share. During the first quarter of 2002, 58,762 shares of Series B were converted into 34,065 shares of Company Common Stock (“Common”). On December 31, 2002, the remaining 207,905 Series B shares were converted into 152,165 shares of Common. The conversion calculation was calculated as 88,889 shares plus the result of multiplying (i) (the value of approximately 40,000 net mineral acres owned by the Company in South Louisiana (the “Mineral Acres”) minus $2,000,000) divided by $8,000,000 times (ii) 355,555.

Preferred Stock—Series C

On August 31, 2000, the Company sent notices to the holders of its Series C Preferred Stock (the “Series C”) advising that the Series C would be redeemed on September 30, 2000. The Series C had a redemption price of $5.00 per share and the holders had the right to convert their Series C shares into Company common stock at a ratio of one share of common for three shares of Series C prior to September 30, 2000. A total of 2,101,827 shares of the Series C were outstanding on September 30, 2000 with 1,293,521 (62%) held by the Company’s then 80% owned subsidiary, Enex. 109,580 Series C shares were converted to 36,527 shares of common stock and approximately 1,992,247 Series C shares were redeemed. On a consolidated basis, the Company’s initial liability for the Series C redemption was approximately $4.8 million. As a result of the Series C redemption, the Company recognized a charge to dividend expense in 2000 of $498,706. At December 31, 2002, the remaining liability was $1.3 million.

Preferred Stock—Series D

On February 3, 2000, we completed the Magellan Acquisition, from certain affiliates of EnCap and an investor in W/E LLC, and other third parties for consideration consisting of (a) 1,085,934 shares of common stock, (b) four-year warrants to purchase up to 333,333 shares of common stock at $30.00 per share, (c) 617,009 shares of 5% Series D Convertible Preferred Stock with a redemption value of $24.00 per share and (d) the assignment of a performance based “back-in” working interest of 5% of Magellan’s interest in 12 exploration prospects. The total purchase price of approximately $19 million was allocated principally to proved undeveloped oil and natural gas properties. During 2002, 857 shares of the Series D were converted to common stock.

Common Stock

On June 30, 2000, the Company completed its public offering of 8.05 million shares of the Company’s common stock (priced at $9.00 per share). The net proceeds, approximately $66.6 million, were used primarily to repay a portion of the outstanding debt under the then existing Credit Facility.

On January 14, 2000, the Company’s stockholders voted to affect a one-for-three reverse split of the Company’s common stock for the stockholders of record on December 9, 1999. The par value of these shares was transferred to additional paid-in capital. All common share and earnings per common share amounts have been retroactively restated in the accompanying consolidated financial statements to reflect the reverse stock split.

F-86

3TEC ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

December 31, 2002, 2001 and 2000

On August 27, 1999, the Company sold to W/E LLC 1,585,185 shares of common stock and five-year warrants to purchase 1,200,000 shares of common stock for $9.8 million in cash and oil and natural gas properties valued at $0.9 million. On the same date, the Company sold 22,222 shares of common stock and five-year warrants to purchase 16,822 shares of common stock to Shoemaker for $0.2 million (See Notes 3 and 6).

On October 19, 1999, the Company closed a private placement of securities to Prudential. The economic terms and conditions of the private placement are similar to those of the securities purchase agreement with W/E LLC and Shoemaker entered into on July 1, 1999. The private placement consisted of the sale of 351,681 shares of common stock and five-year warrants to purchase 266,226 shares at $3.00 per share of common stock for $2.4 million and a five-year senior subordinated convertible note for $2.4 million (See Note 6).

The warrants issued to W/E LLC, Shoemaker and Prudential are exercisable for $3.00 per share and expire five years from the issue date. Sixty percent of the warrants were immediately exercisable, in whole or in part at any time until the expiration date. An additional 10% of the warrants may be exercised at each anniversary of the grant date until expiration. At December 31, 2001, 1,200,000 warrants were exercisable. As a result of the conversion of the entire principal balance of the Senior Subordinated Notes during 2001, all of the warrants became immediately exercisable. During 2002, no warrants were exercised.

On February 3, 2000, the Company completed the acquisition of Magellan Exploration, LLC (“Magellan”), from certain affiliates of EnCap and other third parties for consideration consisting of (a) 1,085,934 shares of Company common stock, (b) four year warrants to purchase up to 333,333 shares of common stock at $30.00 per share, (c) 617,008 shares of 5% Series D Convertible Preferred Stock with a redemption value of $24.00 per share and (d) the assignment of performance based “back-in” working interest of 5% of Magellan’s interest in 12 exploration prospects. During 2002, no warrants were exercised. At December 31, 2002, 333,333 warrants were exercisable.

Restricted Stock

During May 2002, the Company issued 95,000 shares of restricted stock to certain members of the Company’s management valued at $1.6 million. During the year ended December 31, 2002, the Company recognized approximately $0.8 million as restricted stock compensation expense and will recognize the remaining $0.8 million over the remaining service and vesting periods of two years. Of the 95,000 shares that were issued, 10,832 shares had vested and were outstanding as of December 31, 2002. The remaining shares will vest either over a two-year period, when the Company’s stock price meets a certain price target or when there is a change of control, as defined by the plan documents.

(11)    COMMITMENTS AND CONTINGENCIES

On November 18, 1999, the Company’s shareholders approved a reincorporation of the Company from Alabama to Delaware (See Note 1). The Alabama Code has a shareholder dissent provision that allows a shareholder to dissent from the reincorporation and demand cash payment equal to the fair value of the common stock owned at the date of the reincorporation. Before the November 18, 1999 meeting, the Company received shareholder dissents representing ownership of 99,438 shares of common stock. Over the period December 15, 1999 to January 25, 2000, the Company received formal demands for payment from the dissenting shareholders (the “dissenters”). At December 31, 1999 the Company had accrued the estimated cash payment to the dissenters of approximately $1.1 million. The Company made an offer to the dissenters on March 14, 2000 and the dissenters made a counteroffer in late March. On May 26, 2000, the Company agreed to a settlement with the dissenters for them to surrender 62,549 shares of common stock for a total of $980,800, including interest. The

F-87

3TEC ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

December 31, 2002, 2001 and 2000

settlement closed on June 30, 2000 and the shares are held by the Company as treasury stock. A shareholder holding 36,889 shares of common stock agreed to withdraw his dissent.

On October 7, 1994, J.B. Hanks Co., Inc. (“Hanks”) filed litigation in the 21st Judicial District, Parish of Livingston, State of Louisiana against Shore Oil Company (“Shore”), which merged with Middle Bay on June 30, 1997, seeking specific performance of a July, 1994 Agreement of Purchase and Sale (the “Agreement”). On the same date, Shore filed suit against Hanks in the 129th Judicial District, County of Harris, State of Texas also seeking specific performance of the Agreement. Hanks alleges that Shore failed to comply with the Agreement inasmuch as Hanks contended that royalties on certain of the oil and gas leases had not been properly paid. The petition alleges that at the time of the contemplated transaction, Shore was in an overproduced position with respect to the taking of gas on the allegedly affected oil and gas leases and that instead of Shore paying royalties based on actual production, royalties were paid based on entitlements. Despite having received no demand from the particular lessors, Hanks claimed that Shore was in violation of the oil and gas leases; an assertion that Shore denies. On November 15, 1994, the parties entered into a standstill agreement which dismissed both actions. Nearly two (2) years after the dismissal Hanks informed Shore that the royalty problems alleged by Hanks had been cured by the passage of time and that Hanks was therefore prepared to purchase the property in accordance with the Agreement. Shore refused to comply. Both parties again filed suit. The Louisiana litigation was removed to Federal District Court where the matter will be decided. In October 2002, the parties attempted to mediate their dispute. A settlement was not reached. The Company intends to vigorously pursue the defense of this matter. In the opinion of management, the ultimate resolution of this lawsuit will not have a material adverse effect on the Company’s financial position or results of operations.

The Company has commitments for operating leases (primarily for office space in Houston, Texas). Rental expense for office space was $1,135,485 in 2002 and $670,842 in 2001. Future minimum lease commitments at December 31, 2002 are $1,255,546 in 2003; $1,285,412 in 2004; $884,171 in 2005; $847,822 in 2006; and $1,769,192 in years thereafter.

(12)    FINANCIAL INSTRUMENTS

Oil and Natural Gas Derivatives

During February 2002, the Company unwound the floor portion of the April through October 2002 collar for net proceeds of approximately $5.8 million ($0.48/Mmbtu), and then re-swapped the 56,000 Mmbtu of daily natural gas production for the same period at $2.56/Mmbtu. Also during February 2002, the Company put in place a collar on 20,000 Mmbtu of daily gas production from November 2002 to March 2003 with a floor of $3.20/Mmbtu and a weighted average ceiling of $3.53/Mmbtu.

The following table details the Company’s derivative contract positions which were in place at December 31, 2002, which had a fair value liability of $3.5 million at that date.

Natural Gas Derivatives
Period	Mmbtu Per Day	Total Mmbtu	Type	NYMEX Price
January 2003–March 2003	20,000	3,020,000	Put	$	3.20
January 2003–March 2003	10,000	1,510,000	Call	$	3.40
January 2003–March 2003	20,000	3,020,000	Call	$	3.60

Through December 31, 2002, the Company has paid net cash settlements of approximately $11.4 million related to its derivative activities. The $5.8 million gain from the sale of the put floor and the $11.4 million of net

F-88

3TEC ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

December 31, 2002, 2001 and 2000

cash paid for settlements on the derivative activities have been included in the statement of operations as loss on derivative settlements.

Counterparty Risk

The Company’s counterparties to the derivative contracts open at December 31, 2002 are Bank One, NA and Bank of Montreal, both commercial banks who are also participants in the Company’s Credit Facility. We feel the credit worthiness of our current counterparties is sound and do not anticipate any non-performance of contractual obligations.

(13)    QUARTERLY FINANCIAL DATA (Unaudited)

The following unaudited summarized quarterly financial data is presented in thousands, except per share data.

	2002
	1st Qtr.			2nd Qtr.		3rd Qtr.			4th Qtr.
Total Revenues	$	3,589		$	31,820	$	23,887		$	31,806
Operating Income (loss)		(14,179	)		8,651		3,732			3,193
Net Income (loss)		(8,648	)		5,277		2,277			2,447
Net Income (loss) per share (fully diluted)	$	(0.54	)	$	0.27	$	0.12		$	0.12
	2001
	1st Qtr.			2nd Qtr.		3rd Qtr.			4th Qtr.
Total Revenues	$	44,296		$	39,879	$	17,530		$	19,269
Operating Income (loss)		26,294			21,495		(766	)		(19,024	)
Net Income (loss)		16,177			13,209		(915	)		(11,623	)
Net Income (loss) per share (fully diluted)	$	0.86		$	0.70	$	(0.07	)	$	(0.72	)
	2000
	1st Qtr.			2nd Qtr.		3rd Qtr.			4th Qtr.
Total Revenues	$	17,609		$	21,986	$	26,893		$	37,273
Operating Income		4,764			7,505		13,852			20,290
Net Income		3,116			4,914		9,085			14,549
Net Income per share (fully diluted)	$	0.35		$	0.50	$	0.50		$	0.93

The financial results of the Company have been restated for the first and second quarters of 2001. The changes reflect adjustments to oil and natural gas production and revenues as a result of the Company’s overaccrual of revenue related to these quarters. The impact of the adjustments decreased the previously reported amounts as follows (in thousands):

	2001
	1st Qtr.		2nd Qtr.
Total Revenues	$	4,345	$	3,494
Cost and operating expenses		693		961
Operating Income		3,652		2,533
Net Income		2,272		1,571
Net Income per share, (fully-diluted)		0.12		0.08

F-89

3TEC ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

December 31, 2002, 2001 and 2000

(14)    SUPPLEMENTAL OIL AND NATURAL GAS INFORMATION (UNAUDITED)

Capitalized Costs and Costs Incurred

The following tables present the capitalized costs related to oil and natural gas producing activities and the related depreciation, depletion, amortization and impairment as of December 31, 2002 and 2001 and costs incurred in oil and natural gas property acquisition, exploration and development activities (in thousands) for the years ended December 31, 2002, 2001 and 2000.

	2002			2001			2000
Capitalized Costs
Proved properties	$	421,512		$	374,449		$	263,801
Nonproducing leasehold		14,079			10,974			6,477
Accumulated depreciation, depletion, amortization and impairment		(111,238	)		(70,299	)		(54,260	)
Net capitalized costs	$	324,353		$	315,124		$	216,018
Costs Incurred
Proved properties	$	302		$	75,766		$	79,770
Unproved properties		—			8,560			95
Exploration costs		21,531			11,059			695
Development costs		37,510			62,668			25,346
Total	$	59,343		$	158,053		$	105,906
Depletion, depreciation, amortization and impairment	$	42,943		$	32,982		$	18,459

Estimated Quantities of Reserves

The Company has interests in oil and natural gas properties that are located principally in Texas, Louisiana, Oklahoma and New Mexico. The Company does not own or lease any oil and natural gas properties outside the United States. There are no quantities of oil and natural gas subject to long-term supply or similar agreements with any governmental agencies.

The Company retains independent engineering firms to provide year-end estimates of the Company’s future net recoverable oil, natural gas and natural gas liquids reserves. In 2002, 2001 and 2000, such estimates were prepared by Ryder Scott Company. The reserve information was prepared in accordance with guidelines established by the Securities and Exchange Commission.

Estimated proved net recoverable reserves as shown below include only those quantities that can be expected to be commercially recoverable at prices and costs in effect at the balance sheet dates under existing regulatory practices and with conventional equipment and operating methods. Proved developed reserves represent only those reserves expected to be recovered through existing wells. Proved undeveloped reserves include those reserves expected to be recovered from new wells or on undrilled acreage or from existing wells on which a relatively major expenditure is required for recompletion.

F-90

3TEC ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

December 31, 2002, 2001 and 2000

Net quantities of proved developed and undeveloped reserves of oil, including condensate and natural gas liquids, for the years ended December 31, 2002 and 2001 are summarized as follows:

	2002				2001				2000
	Oil (MBbls)(1)		Gas (MMcf)		Oil (MBbls)(1)		Gas (MMcf)		Oil (MBbls)(1)		Gas (MMcf)
Proved Reserves
Beginning of year	5,337		231,266		10,672		237,693		9,835		159,699
Purchases of reserves in place	6		2,282		211		33,712		1,981		85,437
Extensions and discoveries	738		21,066		308		11,547		51		2,699
Revisions of previous estimates	1,056		30,189		(1,520	)	(18,822	)	659		8,698
Sales of reserves in place	(101	)	(130	)	(3,382	)	(10,512	)	(715	)	(1,076	)
Production for the year	(828	)	(25,647	)	(952	)	(22,352	)	(1,139	)	(17,764	)
End of year	6,208		259,026		5,337		231,266		10,672		237,693
Proved Developed Reserves
Beginning of year	4,705		175,659		9,895		177,252		9,358		122,914
End of year	5,546		205,301		4,705		175,659		9,895		177,252

(1) Includes oil, condensate and plant product barrels.

Standardized Measure of Discounted Future Net Cash Flows From Proved Reserves

The following is a summary of the standardized measure of discounted future net cash flows related to the Company’s proved oil and natural gas reserves. For these calculations, estimated future cash flows from estimated future production of proved reserves are computed using oil and natural gas prices as of the end of each period presented. Future development and production costs attributable to the proved reserves were estimated assuming that existing conditions would continue over the economic lives of the individual leases and costs were not escalated for the future. Estimated future income taxes were calculated by applying statutory tax rates (based on current law adjusted for permanent differences and tax credits) to the estimated future pre-tax net cash flows related to proved oil and natural gas reserves, less the tax basis of the properties involved.

The Company cautions against using this data to determine the value of its oil and natural gas properties. To obtain the best estimate of the fair value of the oil and natural gas properties, forecasts of future economic conditions, varying discount rates, and consideration of other than proved reserves would have to be incorporated into the calculation. In addition, there are significant uncertainties inherent in estimating quantities of proved reserves and in projecting rates of production that impair the usefulness of the data.

F-91

3TEC ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

December 31, 2002, 2001 and 2000

The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves for the years ended December 31, 2002, 2001 and 2000 are summarized as follows (in thousands):

	2002			2001			2000
Future cash inflows	$	1,285,657		$	628,537		$	2,349,534
Future production costs		(284,860	)		(188,783	)		(301,344	)
Future development costs		(53,127	)		(54,418	)		(51,359	)
Future income tax expenses		(277,372	)		(58,051	)		(676,227	)
Future net cash flows		670,298			327,285			1,320,604
10% discount to reflect timing of cash flows		(320,858	)		(145,686	)		(627,930	)
Standardized measure of discounted future net cash flows	$	349,440		$	181,599		$	692,674

3TEC anticipates spending $30.3 million in 2003, $12.2 million in 2004 and $5.5 million in 2005 to develop its proved undeveloped reserves.

The following are the principal sources of changes in the standardized measure of discounted future net cash flows for the years ended December 31, 2002, 2001 and 2000 (in thousands):

	2002			2001			2000
Sales of oil and natural gas, net of production cost	$	(76,794	)	$	(89,410	)	$	(78,969	)
Net changes in prices and production cost		244,957			(765,134	)		467,920
Changes in estimated future development costs		810			(2,699	)		(25,849	)
Previously estimated development costs incurred during the year		15,364			15,591			5,102
Extensions and discoveries		77,849			11,388			15,393
Purchases of reserves		2,514			26,461			397,280
Sales of reserves		(1,503	)		(22,682	)		(8,789	)
Revisions of previous quantity estimates		62,484			(24,809	)		39,442
Net change in income taxes		(130,153	)		322,700			(304,816	)
Accretion of discount		21,235			104,736			19,843
Changes in production rates (timing) and other		(48,922	)		(87,217	)		17,376
Change for year	$	167,841		$	(511,075	)	$	543,933

The period end prices of oil and natural gas at December 31, 2002, 2001 and 2000, used in the above table were $31.20, $19.84 and $25.31 per barrel of oil and $4.79, $2.57 and $9.40 per thousand cubic feet of natural gas, respectively.

F-92

ANNEX A

LETTER OF TRANSMITTAL

LETTER OF TRANSMITTAL

To Tender For Exchange

8¾% Series A Senior Subordinated Notes Due 2012

of

PLAINS EXPLORATION & PRODUCTION COMPANY

PLAINS E&P COMPANY

Pursuant to the Prospectus Dated September 12, 2003

THIS OFFER WILL EXPIRE AT 5:00 P.M., NEW YORK CITY TIME, ON OCTOBER 17, 2003 UNLESS EXTENDED BY PLAINS EXPLORATION & PRODUCTION COMPANY AND PLAINS E&P COMPANY IN THEIR SOLE DISCRETION (THE “EXPIRATION DATE”). TENDERS OF NOTES MAY BE WITHDRAWN AT ANY TIME PRIOR TO THE EXPIRATION DATE.

The Exchange Agent for the Exchange Offer is:

JPMORGAN CHASE BANK

By Mail:	By Facsimile:	By Hand:
JPMorgan Chase Bank 600 Travis, Suite 1150 Houston, Texas 77002 Attention: Rebecca Newman	(713) 577-5200 Attention: Rebecca Newman Confirm by Telephone: (713) 216-4931 Attention: Rebecca Newman	JPMorgan Chase Bank 600 Travis, Suite 1150 Houston, Texas 77002 Attention: Rebecca Newman

DELIVERY OF THIS LETTER OF TRANSMITTAL TO AN ADDRESS OTHER THAN AS SET FORTH ABOVE OR TRANSMISSION OF INSTRUCTIONS VIA FACSIMILE TO A NUMBER OTHER THAN AS LISTED ABOVE WILL NOT CONSTITUTE A VALID DELIVERY.

HOLDERS WHO WISH TO BE ELIGIBLE TO RECEIVE SERIES B NOTES IN TO THE EXCHANGE OFFER MUST VALIDLY TENDER (AND NOT WITHDRAW) THEIR SERIES A NOTES TO THE EXCHANGE AGENT ON OR PRIOR TO THE EXPIRATION DATE.

This Letter of Transmittal is to be used by holders (“Holders”) of 8¾% Series A Senior Subordinated Notes due 2012 (the “Series A notes”) of Plains Exploration & Production Company and Plains E&P Company (together, the “Issuers”) to receive 8¾% Series B Senior Subordinated Notes due 2012 (the “Series B notes”) if: (i) certificates representing Series A notes are to be physically delivered to the Exchange Agent herewith by such Holders; (ii) tender of Series A notes is to be made by book-entry transfer to the Exchange Agent’s account at The Depository Trust Company (“DTC”) pursuant to the procedures set forth under the caption “The Exchange Offer—Procedures for Tendering Series A Notes Book-Entry Delivery Procedures” in the Prospectus dated September 12, 2003 (the “Prospectus”); or (iii) tender of Series A notes is to be made according to the guaranteed delivery procedures set forth under the caption “The Exchange Offer—Procedures for Tendering Series A Notes—Guaranteed Delivery” in the Prospectus, and, in each case, instructions are not being transmitted through the DTC Automated Tender Offer Program (“ATOP”). The undersigned hereby acknowledges receipt of the Prospectus. All capitalized terms used herein and not defined shall have the meanings ascribed to them in the Prospectus.

A-1

Holders of Series A notes that are tendering by book-entry transfer to the Exchange Agent’s account at DTC can execute the tender through ATOP, for which the transaction will be eligible. DTC participants that are accepting the exchange offer as set forth in the Prospectus and this Letter of Transmittal (together, the “Exchange Offer”) must transmit their acceptance to DTC which will edit and verify the acceptance and execute a book-entry delivery to the Exchange Agent’s account at DTC. DTC will then send an Agent’s Message to the Exchange Agent for its acceptance. Delivery of the Agent’s Message by DTC will satisfy the terms of the Offer as to execution and delivery of a Letter of Transmittal by the participant identified in the Agent’s Message. DTC participants may also accept the Exchange Offer by submitting a notice of guaranteed delivery through ATOP.

Delivery of documents to DTC does not constitute delivery to the exchange agent.

If a Holder desires to tender Series A notes pursuant to the Exchange Offer and time will not permit this Letter of Transmittal, certificates representing such Series A notes and all other required documents to reach the Exchange Agent, or the procedures for book-entry transfer cannot be completed, on or prior to the Expiration Date, then such Holder must tender such Series A notes according to the guaranteed delivery procedures set forth under the caption “The Exchange Offer— Procedures for Tendering Series A Notes—Guaranteed Delivery” in the Prospectus. See Instruction 2.

The undersigned should complete, execute and deliver this Letter of Transmittal to indicate the action the undersigned desires to take with respect to the Exchange Offer.

TENDER OF SERIES A NOTES

¨	CHECK HERE IF TENDERED SERIES A NOTES ARE ENCLOSED HEREWITH.
¨	CHECK HERE IF TENDERED SERIES A NOTES ARE BEING DELIVERED BY BOOK-ENTRY TRANSFER MADE TO THE ACCOUNT MAINTAINED BY THE EXCHANGE AGENT WITH DTC AND COMPLETE THE FOLLOWING:
	Name of Tendering Institution:
	Account Number:
	Transaction Code Number:
¨	CHECK HERE IF TENDERED SERIES A NOTES ARE BEING DELIVERED PURSUANT TO A NOTICE OF GUARANTEED DELIVERY PREVIOUSLY SENT TO THE EXCHANGE AGENT AND COMPLETE THE FOLLOWING:
	Name(s) of Registered Holder(s):
	Window Ticker Number (if any):
	Date of Execution of Notice of Guaranteed Delivery:
	Name of Eligible Institution that Guaranteed Delivery:

A-2

List below the Series A notes to which this Letter of Transmittal relates. The name(s) and address(es) of the registered Holder(s) should be printed, if not already printed below, exactly as they appear on the Series A notes tendered hereby. The Series A notes and the principal amount of Series A notes that the undersigned wishes to tender would be indicated in the appropriate boxes. If the space provided is inadequate, list the certificate number(s) and principal amount(s) on a separately executed schedule and affix the schedule to this Letter of Transmittal.

DESCRIPTION OF SERIES A NOTES
Name(s) and Address(es) of Registered Holder(s) (Please fill in, if blank) See Instruction 3.	Certificate Number(s)*	Aggregate Principal Amount Represented**	Principal Amount Tendered**	Total Principal Amount of Series A Notes
*          Need not be completed by Holders tendering by book-entry transfer. **        Unless otherwise specified, the entire aggregate principal amount represented by the Series A notes described above will be deemed to be tendered. See Instruction 4.

NOTE: SIGNATURES MUST BE PROVIDED BELOW.

PLEASE READ THE ACCOMPANYING INSTRUCTIONS CAREFULLY.

Ladies and Gentlemen:

The undersigned hereby tenders to Plains Exploration & Production Company and Plains E&P Company (together, the “Issuers”), upon the terms and subject to the conditions set forth in their Prospectus dated September 12, 2003 (the “Prospectus”), receipt of which is hereby acknowledged, and in accordance with this Letter of Transmittal (which together constitute the “Exchange Offer”), the principal amount of Series A notes indicated in the foregoing table entitled “Description of Series A Notes” under the column heading “Principal Amount Tendered.” The undersigned represents that it is duly authorized to tender all of the Series A notes tendered hereby which it holds for the account of beneficial owners of such Series A notes (“Beneficial Owner(s)”) and to make the representations and statements set forth herein on behalf of such Beneficial Owner(s).

Subject to, and effective upon, the acceptance for purchase of the principal amount of Series A notes tendered herewith in accordance with the terms and subject to the conditions of the Exchange Offer, the undersigned hereby sells, assigns and transfers to, or upon the order of, the Issuers, all right, title and interest in and to all of the Series A notes tendered hereby. The undersigned hereby irrevocably constitutes and appoints the Exchange Agent the true and lawful agent and attorney-in-fact of the undersigned (with full knowledge that the Exchange Agent also acts as the agent of the Issuers) with respect to such Series A notes, with full powers of substitution and revocation (such power of attorney being deemed to be an irrevocable power coupled with an interest) to (i) present such Series A notes and all evidences of transfer and authenticity to, or transfer ownership of, such Series A notes on the account books maintained by DTC to, or upon the order of, the Issuers, (ii) present such Series A notes for transfer of ownership on the books of the Issuers, and (iii) receive all benefits and otherwise exercise all rights of beneficial ownership of such Series A notes, all in accordance with the terms and conditions of the Exchange Offer as described in the Prospectus.

A-3

By accepting the Exchange Offer, the undersigned hereby represents and warrants that:

(i)  the Series B notes to be acquired by the undersigned and any Beneficial Owner(s) in connection with the Exchange Offer are being acquired by the undersigned and any Beneficial Owner(s) in the ordinary course of business of the undersigned and any Beneficial Owner(s),

(ii)  the undersigned and each Beneficial Owner are not participating, do not intend to participate, and have no arrangement or understanding with any person to participate, in the distribution of the Series B notes,

(iii)  except as indicated below, neither the undersigned nor any Beneficial Owner is an “affiliate,” as defined in Rule 405 under the Securities Act of 1933, as amended (together with the rules and regulations promulgated thereunder, the “Securities Act”), of the Issuers, and

(iv)  the undersigned and each Beneficial Owner acknowledge and agree that (x) any person participating in the Exchange Offer with the intention or for the purpose of distributing the Series B notes must comply with the registration and prospectus delivery requirements of the Securities Act in connection with a secondary resale of the Series B notes acquired by such person with a registration statement containing the selling securityholder information required by Item 507 of Regulation S-K of the Securities and Exchange Commission (the “SEC”) and cannot rely on the interpretation of the Staff of the SEC set forth in the no-action letters that are noted in the section of the Prospectus entitled “The Exchange Offer—Registration Rights” and (y) any broker-dealer that pursuant to the Exchange Offer receives Series B notes for its own account in exchange for Series A notes which it acquired for its own account as a result of market-making activities or other trading activities must deliver a prospectus meeting the requirements of the Securities Act in connection with any resale of such Series B notes.

If the undersigned is a broker-dealer that will receive Series B notes for its own account in exchange for Series A notes that were acquired as the result of market-making activities or other trading activities, it acknowledges that it will deliver a prospectus in connection with any resale of such Series B notes. By so acknowledging and by delivering a prospectus, a broker-dealer shall not be deemed to admit that it is an “underwriter” within the meaning of the Securities Act.

The undersigned understands that tenders of Series A notes may be withdrawn by written notice of withdrawal received by the Exchange Agent at any time prior to the Expiration Date in accordance with the Prospectus. In the event of a termination of the Exchange Offer, the Series A notes tendered pursuant to the Exchange Offer will be returned to the tendering Holders promptly (or, in the case of Series A notes tendered by book-entry transfer, such Series A notes will be credited to the account maintained at DTC from which such Series A notes were delivered). If the Issuers make a material change in the terms of the Exchange Offer or the information concerning the Exchange Offer or waives a material condition of such Exchange Offer, the Issuers will disseminate additional Exchange Offer materials and extend such Exchange Offer, if and to the extent required by law.

The undersigned understands that the tender of Series A notes pursuant to any of the procedures set forth in the Prospectus and in the instructions hereto will constitute the undersigned’s acceptance of the terms and conditions of the Exchange Offer. The Issuers’ acceptance for exchange of Series A notes tendered pursuant to any of the procedures described in the Prospectus will constitute a binding agreement between the undersigned and the Issuers in accordance with the terms and subject to the conditions of the Exchange Offer. For purposes of the Exchange Offer, the undersigned understands that validly tendered Series A notes (or defectively tendered Series A notes with respect to which the Issuers have, or have caused to be, waived such defect) will be deemed to have been accepted by the Issuers if, as and when the Issuers give oral or written notice thereof to the Exchange Agent.

A-4

The undersigned hereby represents and warrants that the undersigned has full power and authority to tender, sell, assign and transfer the Series A notes tendered hereby, and that when such tendered Series A notes are accepted for purchase by the Issuers, the Issuers will acquire good title thereto, free and clear of all liens, restrictions, charges and encumbrances and not subject to any adverse claim or right. The undersigned and each Beneficial Owner will, upon request, execute and deliver any additional documents deemed by the Exchange Agent or by the Issuers to be necessary or desirable to complete the sale, assignment and transfer of the Series A notes tendered hereby.

All authority conferred or agreed to be conferred by this Letter of Transmittal shall not be affected by, and shall survive the death or incapacity of the undersigned and any Beneficial Owner(s), and any obligation of the undersigned or any Beneficial Owner(s) hereunder shall be binding upon the heirs, executors, administrators, trustees in bankruptcy, personal and legal representatives, successors and assigns of the undersigned and such Beneficial Owner(s).

The undersigned understands that the delivery and surrender of any Series A notes is not effective, and the risk of loss of the Series A notes does not pass to the Exchange Agent or the Issuers, until receipt by the Exchange Agent of this Letter of Transmittal, or a manually signed facsimile hereof, properly completed and duly executed, together with all accompanying evidences of authority and any other required documents in form satisfactory to the Issuers. All questions as to form of all documents and the validity (including time of receipt) and acceptance of tenders and withdrawals of Series A notes will be determined by the Issuers, in their discretion, which determination shall be final and binding.

Unless otherwise indicated herein under “Special Issuance Instructions,” the undersigned hereby requests that any Series A notes representing principal amounts not tendered or not accepted for exchange be issued in the name(s) of the undersigned (and in the case of Series A notes tendered by book-entry transfer, by credit to the account of DTC), and Series B notes issued in exchange for Series A notes pursuant to the Exchange Offer be issued to the undersigned. Similarly, unless otherwise indicated herein under “Special Delivery Instructions,” the undersigned hereby requests that any Series A notes representing principal amounts not tendered or not accepted for exchange and Series B notes issued in exchange for Series A notes pursuant to the Exchange Offer be delivered to the undersigned at the address shown below the undersigned’s signature(s). In the event that the “Special Issuance Instructions” box or the “Special Delivery Instructions” box is, or both are, completed, the undersigned hereby requests that any Series A notes representing principal amounts not tendered or not accepted for purchase be issued in the name(s) of, certificates for such Series A notes be delivered to, and Series B notes issued in exchange for Series A notes pursuant to the Exchange Offer be issued in the name(s) of, and be delivered to, the person(s) at the address(es) so indicated, as applicable. The undersigned recognizes that the Issuers have no obligation pursuant to the “Special Issuance Instructions” box or “Special Delivery Instructions” box to transfer any Series A notes from the name of the registered Holder(s) thereof if the Issuers do not accept for exchange any of the principal amount of such Series A notes so tendered.

A-5

¨ CHECK HERE IF YOU OR ANY BENEFICIAL OWNER FOR WHOM YOU HOLD SERIES A NOTES IS AN AFFILIATE OF THE ISSUERS.

¨ CHECK HERE IF YOU OR ANY BENEFICIAL OWNER FOR WHOM YOU HOLD SERIES A NOTES TENDERED HEREBY IS A BROKER-DEALER WHO ACQUIRED SUCH NOTES DIRECTLY FROM THE ISSUERS OR AN AFFILIATE OF THE ISSUERS.

¨ CHECK HERE AND COMPLETE THE LINES BELOW IF YOU OR ANY BENEFICIAL OWNER FOR WHOM YOU HOLD SERIES A NOTES TENDERED HEREBY IS A BROKER-DEALER WHO ACQUIRED SUCH NOTES IN MARKET-MAKING OR OTHER TRADING ACTIVITIES. IF THIS BOX IS CHECKED, THE ISSUERS WILL SEND 10 ADDITIONAL COPIES OF THE PROSPECTUS AND 10 COPIES OF ANY AMENDMENTS OR SUPPLEMENTS THERETO TO YOU OR SUCH BENEFICIAL OWNER AT THE ADDRESS SPECIFIED IN THE FOLLOWING LINES.

Name:                                                                                           

Address:

A-6

SPECIAL ISSUANCE INSTRUCTIONS
(See Instructions 1, 5, 6 and 7) To be completed ONLY if Series A notes in a principal amount not tendered or not accepted for exchange are to be issued in the name of, or Series B notes are to be issued in the name of, someone other than the person(s) whose signature(s) appear(s) within this Letter of Transmittal or issued to an address different from that shown in the box entitled “Description of Series A Notes” within this Letter of Transmittal. Issue:  ¨  Series A notes¨  Series B notes (check as applicable) Name                                                                                         (Please Print) Address                                                                                    (Please Print) (Zip Code) (Tax Identification or Social Security Number) (See Substitute Form W-9 Herein) SPECIAL DELIVERY INSTRUCTIONS
(See Instructions 1, 5, 6 and 7) To be completed ONLY if Series A notes in a principal amount not tendered or not accepted for exchange or Series B notes are to be sent to someone other than the person(s) whose signature(s) appear(s) within this Letter of Transmittal or to an address different from that shown in the box entitled “Description of Series A Notes” within this Letter of Transmittal. Issue:  ¨  Series A notes¨  Series B notes (check as applicable) Name                                                                                         (Please Print) Address                                                                                    (Please Print) (Zip Code) (Tax Identification or Social Security Number) (See Substitute Form W-9 Herein)

A-7

PLEASE SIGN HERE

(To be completed by all tendering Holders of Series A notes

regardless of whether Series A notes are being physically delivered herewith)

This Letter of Transmittal must be signed by the registered Holder(s) exactly as name(s) appear(s) on certificate(s) for Series A notes or, if tendered by a participant in DTC exactly as such participant’s name appears on a security position listing as owner of Series A notes, or by the person(s) authorized to become registered Holder(s) by endorsements and documents transmitted herewith. If signature is by trustees, executors, administrators, guardians, attorneys-in-fact, officers of corporations or others acting in a fiduciary or representative capacity, please set forth full title and see Instruction 5.

Signature(s) of Registered Holder(s) or Authorized Signatory

(See guarantee requirement below)

Dated:                                                                                                                                                                                                          

Name(s):                                                                                                                                                                                                    

(Please Print)

Capacity (Full Title):                                                                                                                                                                             

Address:                                                                                                                                                                                                    

(Including Zip Code)

Area Code and Telephone No.:                                                                                                                                                    

Tax Identification or Social Security Number:                                                                                                                       

COMPLETE ACCOMPANYING SUBSTITUTE FORM W-9

SIGNATURE GUARANTEE

(If Required—See Instructions 1 and 5)

(Authorized Signature)

(Name of Firm)

[place seal here]

A-8

INSTRUCTIONS

Forming Part of The Terms and Conditions of The Exchange Offer

1.    Signature Guarantees.    Signatures of this Letter of Transmittal must be guaranteed by a recognized member of the Medallion Signature Guarantee Program or by any other “eligible guarantor institution,” as such term is defined in Rule 17Ad-15 promulgated under the Exchange Act (each of the foregoing, an “Eligible Institution”), unless the Series A notes tendered hereby are tendered (i) by a registered Holder of Series A notes (or by a participant in DTC whose name appears on a security position listing as the owner of such Series A notes) that has not completed either the box entitled “Special Issuance Instructions” or the box entitled “Special Delivery Instructions” on this Letter of Transmittal, or (ii) for the account of an Eligible Institution. If the Series A notes are registered in the name of a person other than the signer of this Letter of Transmittal, if Series A notes not accepted for exchange or not tendered are to be returned to a person other than the registered Holder or if Series B notes are to be issued in the name of or sent to a person other than the registered Holder, then the signatures on this Letter of Transmittal accompanying the tendered Series A notes must be guaranteed by an Eligible Institution as described above. See Instruction 5.

2.    Delivery of Letter of Transmittal and Series A Notes.    This Letter of Transmittal is to be completed by Holders if (i) certificates representing Series A notes are to be physically delivered to the Exchange Agent herewith by such Holders; (ii) tender of Series A notes is to be made by book-entry transfer to the Exchange Agent’s account at DTC pursuant to the procedures set forth under the caption “The Exchange offer—Procedures for Tendering Series A Notes—Book-Entry Delivery Procedures” in the Prospectus; or (iii) tender of Series A notes is to be made according to the guaranteed delivery procedures set forth under the caption “The Exchange Offer—Procedures for Tendering Series A Notes—Guaranteed Delivery” in the Prospectus. All physically delivered Series A notes, or a confirmation of a book-entry transfer into the Exchange Agent’s account at DTC of all Series A notes delivered electronically, as well as a properly completed and duly executed Letter of Transmittal (or manually signed facsimile thereof), any required signature guarantees and any other documents required by this Letter of Transmittal, must be received by the Exchange Agent at one of its addresses set forth on the cover page hereto on or prior to the Expiration Date, or the tendering Holder must comply with the guaranteed delivery procedures set forth below. Delivery of documents to DTC does not constitute delivery to the Exchange Agent.

If a Holder desires to tender Series A notes pursuant to the Exchange Offer and time will not permit this Letter of Transmittal, certificates representing such Series A notes and all other required documents to reach the Exchange Agent, or the procedures for book-entry transfer cannot be completed, on or prior to the Expiration Date, such Holder must tender such Series A notes pursuant to the guaranteed delivery procedures set forth under the caption “The Exchange Offer—Procedures for Tendering Series A Notes—Guaranteed Delivery” in the Prospectus. Pursuant to such procedures, (i) such tender must be made by or through an Eligible Institution; (ii) a properly completed and duly executed Notice of Guaranteed Delivery, substantially in the form provided by the Issuers, or an Agent’s Message with respect to guaranteed delivery that is accepted by the Issuers, must be received by the Exchange Agent, either by hand delivery, mail, telegram, or facsimile transmission, on or prior to the Expiration Date; and (iii) the certificates for all tendered Series A notes, in proper form for transfer (or confirmation of a book-entry transfer or all Series A notes delivered electronically into the Exchange Agent’s account at DTC pursuant to the procedures for such transfer set forth in the Prospectus), together with a properly completed and duly executed Letter of Transmittal (or manually signed facsimile thereof) and any other documents required by this Letter of Transmittal, or in the case of a book-entry transfer, a properly transmitted Agent’s Message, must be received by the Exchange Agent within two business days after the date of the execution of the Notice of Guaranteed Delivery.

A-9

The method of delivery of this Letter of Transmittal, the Series A notes and all other required documents, including delivery through DTC and any acceptance or agent’s message delivered through ATOP, is at the election and risk of the tendering Holder and, except as otherwise provided in this Instruction 2, delivery will be deemed made only when actually received by the Exchange Agent. If delivery is by mail, it is suggested that the Holder use properly insured, registered mail with return receipt requested, and that the mailing be made sufficiently in advance of the Expiration Date to permit delivery to the Exchange Agent prior to such date.

No alternative, conditional or contingent tenders will be accepted. All tendering Holders, by execution of this Letter of Transmittal (or a facsimile thereof), waive any right to receive any notice of the acceptance of their Series A notes for exchange.

3.    Inadequate Space.    If the space provided herein is inadequate, the certificate numbers and/or the principal amount represented by Series A notes should be listed on separate signed schedule attached hereto.

4.    Partial Tenders.    (Not applicable to Holders who tender by book-entry transfer). If Holders wish to tender less than the entire principal amount evidenced by a Series A note submitted, such Holders must fill in the principal amount that is to be tendered in the column entitled “Principal Amount Tendered.” The minimum permitted tender is $1,000 in principal amount of Series A notes. All other tenders must be in integral multiples of $1,000 in principal amount. In the case of a partial tender of Series A notes, as soon as practicable after the Expiration Date, new certificates for the remainder of the Series A notes that were evidenced by such Holder’s old certificates will be sent to such Holder, unless otherwise provided in the appropriate box on this Letter of Transmittal. The entire principal amount that is represented by Series A notes delivered to the Exchange Agent will be deemed to have been tendered, unless otherwise indicated.

5.    Signatures on Letter of Transmittal, Instruments of Transfer and Endorsements.    If this Letter of Transmittal is signed by the registered Holder(s) of the Series A notes tendered hereby, the signatures must correspond with the name(s) as written on the face of the certificate(s) without alteration, enlargement or any change whatsoever. If this Letter of Transmittal is signed by a participant in DTC whose name is shown as the owner of the Series A notes tendered hereby, the signature must correspond with the name shown on the security position listing as the owner of the Series A notes.

If any of the Series A notes tendered hereby are registered in the name of two or more Holders, all such Holders must sign this Letter of Transmittal. If any of the Series A notes tendered hereby are registered in different names on several certificates, it will be necessary to complete, sign and submit as many separate Letters of Transmittal as there are different registrations of certificates.

If this Letter of Transmittal or any Series A note or instrument of transfer is signed by a trustee, executor, administrator, guardian, attorney-in-fact, agent, officer of a corporation or other person acting in a fiduciary or representative capacity, such person should so indicate when signing, and proper evidence satisfactory to the Issuers of such person’s authority to so act must be submitted.

When this Letter of Transmittal is signed by the registered Holder(s) of the Series A notes listed herein and transmitted hereby, no endorsements of Series A notes or separate instruments of transfer are required unless Series B notes are to be issued, or Series A notes not tendered or exchanged are to be issued, to a person other than the registered Holder(s), in which case signatures on such Series A notes or instruments of transfer must be guaranteed by an Eligible Institution.

A-10

If this Letter of Transmittal is signed other than by the registered Holder(s) of the Series A notes listed herein, the Series A notes must be endorsed or accompanied by appropriate instruments of transfer, in either case signed exactly as the name(s) of the registered Holder(s) appear on the Series A notes and signatures on such Series A notes or instruments of transfer are required and must be guaranteed by an Eligible Institution, unless the signature is that of an Eligible Institution.

6.    Special Issuance and Delivery Instructions.    If certificates for Series B notes or unexchanged or untendered Series A notes are to be issued in the name of a person other than the signer of this Letter of Transmittal, or if Series B notes or such Series A notes are to be sent to someone other than the signer of this Letter of Transmittal or to an address other than that shown herein, the appropriate boxes on this Letter of Transmittal should be completed. All Series A notes tendered by book-entry transfer and not accepted for payment will be returned by crediting the account at DTC designated herein as the account for which such Series A notes were delivered.

7.    Transfer Taxes.    Except as set forth in this Instruction 7, the Issuers will pay or cause to be paid any transfer taxes with respect to the transfer and sale of Series A notes to it, or to its order, pursuant to the Exchange Offer. If Series B notes, or Series A notes not tendered or exchanged are to be registered in the name of any persons other than the registered owners, or if tendered Series A notes are registered in the name of any persons other than the persons signing this Letter of Transmittal, the amount of any transfer taxes (whether imposed on the registered Holder or such other person) payable on account of the transfer to such other person must be paid to the Issuers or the Exchange Agent (unless satisfactory evidence of the payment of such taxes or exemption therefrom is submitted) before the Series B notes will be issued.

8.    Waiver of Conditions.    The conditions of the Exchange Offer may be amended or waived by the Issuers, in whole or in part, at any time and from time to time in the Issuers’ discretion, in the case of any Series A notes tendered.

9.    Substitute Form W-9.    Each tendering owner of a note (or other payee) is required to provide the Exchange Agent with a correct taxpayer identification number (“TIN”), generally the owner’s social security or federal employer identification number, and with certain other information, on Substitute Form W-9, which is provided hereafter under “Important Tax Information,” and to certify that the owner (or other payee) is not subject to backup withholding. Failure to provide the information on the Substitute Form W-9 may subject the tendering owner (or other payee) to a $50 penalty imposed by the Internal Revenue Service and 31% federal income tax withholding. The box in Part 3 of the Substitute Form W-9 may be checked if the tendering owner (or other payee) has not been issued a TIN and has applied for a TIN or intends to apply for a TIN in the near future. If the box in Part 3 is checked and the Exchange Agent is not provided with a TIN within 60 days of the date on the Substitute Form W-9, the Exchange Agent will withhold 30% until a TIN is provided to the Exchange Agent.

10.    Broker-dealers Participating in the Exchange Offer.    If no broker-dealer checks the last box on page A-6 of this Letter of Transmittal, the Issuers have no obligation under the Registration Rights Agreement to allow the use of the Prospectus for resales of the Series B notes by broker-dealers or to maintain the effectiveness of the Registration Statement of which the Prospectus is a part after the consummation of the Exchange Offer.

11.    Requests for Assistance or Additional Copies.    Any questions or requests for assistance or additional copies of the Prospectus, this Letter of Transmittal or the Notice of Guaranteed Delivery may be directed to the Exchange Agent at the telephone numbers and location listed above. A Holder or owner may also contact such Holder’s or owner’s broker, dealer, commercial bank or trust company or nominee for assistance concerning the Exchange Offer.

A-11

IMPORTANT: This Letter of Transmittal (or a facsimile hereof), together with certificates representing the Series A notes and all other required documents or the Notice of Guaranteed Delivery, must be received by the Exchange Agent on or prior to the Expiration Date.

IMPORTANT TAX INFORMATION

Under federal income tax law, an owner of Series A notes whose tendered Series A notes are accepted for exchange is required to provide the Exchange Agent with such owner’s current TIN on Substitute Form W-9 below. If such owner is an individual, the TIN is his or her social security number. If the Exchange Agent is not provided with the correct TIN, the owner or other recipient of Series B notes may be subject to a $50 penalty imposed by the Internal Revenue Service. In addition, any interest on Series B notes paid to such owner or other recipient may be subject to 31% backup withholding tax.

Certain owners of notes (including, among others, all corporations and certain foreign individuals) are not subject to these backup withholding and reporting requirements. In order for a foreign individual to qualify as an exempt recipient, that owner must submit to the Exchange Agent a properly completed Internal Revenue Service Forms W-8ECI, W-8BEN, W-8EXP or W-8IMY (collectively, a “Form W-8”), signed under penalties of perjury, attesting to that individual’s exempt status. A Form W-8 can be obtained from the Exchange Agent. See the enclosed “Guidelines for Certification of Taxpayer Identification Number on Substitute Form W-9” for additional instructions.

Backup withholding is not an additional tax. Rather, the federal income tax liability of persons subject to backup withholding will be reduced by the amount of tax withheld. If withholding results in an overpayment of taxes, a refund may be obtained from the Internal Revenue Service.

Purpose of Substitute Form W-9

To prevent backup withholding the owner is required to notify the Exchange Agent of the owner’s current TIN (or the TIN of any other payee) by completing the following form, certifying that the TIN provided on Substitute Form W-9 is correct (or that such owner is awaiting a TIN), and that (i) the owner is exempt from withholding, (ii) the owner has not been notified by the Internal Revenue Service that the owner is subject to backup withholding as a result of failure to report all interest or dividends or (iii) the Internal Revenue Service has notified the owner that the owner is no longer subject to backup withholding.

What Number to Give The Exchange Agent

The Holder is required to give the Exchange Agent the TIN (e.g., social security number or employer identification number) of the owner of the Series A notes. If the Series A notes are registered in more than one name or are not registered in the name of the actual owner, consult the enclosed “Guidelines for Certification of Taxpayer Identification Number on Substitute Form W-9,” for additional guidance on which number to report.

A-12

SUBSTITUTE Form W-9 Department of The Treasury Internal Revenue Service Payer’s Request for Taxpayer Identification No. (“TIN”)	PART 1—PLEASE PROVIDE YOUR TIN IN THE BOX AT RIGHT AND CERTIFY BY SIGNING AND DATING BELOW.	Social Security Number(s) or Employer Identification Number
	PART 2—CERTIFICATION
	UNDER PENALTIES OF PERJURY, I CERTIFY THAT: (1)   The number shown on this form is my correct taxpayer identification number (or I am waiting for a number to be issued to me), and (2)   I am not subject to backup withholding because: (a) I am exempt from backup withholding, or (b) I have not been notified by the Internal Revenue Service (“IRS”) that I am subject to backup withholding as a result of a failure to report all interest or dividends, or (c) the IRS has notified me that I am no longer subject to backup withholding Signature                                                                      Date
CERTIFICATION INSTRUCTIONS—You must cross out item (2) above if you have been notified by the IRS that you are subject to backup withholding because of underreporting interest or dividends on your tax return.
PART 3—Awaiting TIN [            ]

NOTE: FAILURE TO COMPLETE AND RETURN THIS FORM MAY RESULT IN A $50 PENALTY IMPOSED BY THE INTERNAL REVENUE SERVICE AND BACKUP WITHHOLDING OF 30%. PLEASE REVIEW THE ENCLOSED GUIDELINES FOR CERTIFICATION OF TAXPAYER IDENTIFICATION NUMBER ON SUBSTITUTE FORM W-9 FOR ADDITIONAL DETAILS.

YOU MUST COMPLETE THE FOLLOWING CERTIFICATE IF YOU CHECKED THE BOX IN

PART 3 OF SUBSTITUTE FORM W-9.

CERTIFICATE OF AWAITING TAXPAYER IDENTIFICATION NUMBER

I certify under penalties of perjury that a taxpayer identification number has not been issued to me, and either
(1) I have mailed or delivered an application to receive a taxpayer identification number to the appropriate
Internal Revenue Service Center or Social Security Administration Office, or (2) I intend to mail or deliver an
application in the near future. I understand that if I do not provide a taxpayer identification number within 60
days of the date in this form, 31% of all reportable cash payments made to me will be withheld until I provide
a taxpayer identification number.

Signature                                                                                               Date                                                      

A-13

GUIDELINES FOR CERTIFICATION OF TAXPAYER IDENTIFICATION

NUMBER ON SUBSTITUTION FORM W-9

Guidelines for Determining the Proper Identification Number to Give the Payer—Social Security numbers have nine digits separated by two hyphens: i.e. 000-00-0000. Employer identification numbers have nine digits separated by only one hyphen: i.e. 00-0000000. The table below will help determine the number to give the payer.

(1) List first and circle the name of the person whose number you furnish. If only one person on a joint account has an SSN, that person’s number must be furnished.

(2) Circle the minor’s name and furnish the minor’s SSN.

(3) Circle the ward’s, minor’s or incompetent person’s name and furnish such person’s SSN.

(4) You must show your individual name, but you may also enter your business or “DBA” name. You may use either your SSN or EIN (if you have one).

(5) List first and circle the name of the legal trust, estate, or pension trust. (Do not furnish the TIN of the personal representative or trustee unless the legal entity itself is not distinguished in the account title).

Note: If no name is circled when there is more than one name, the number will be considered to be that of the first name listed.

A-14

For this type of account:	Give the SOCIAL SECURITY number of—
1.   Individual	The individual
2.   Two or more individuals (joint account)	The actual owner of the account or, if combined funds, the first individual on the account(1)
3.   Custodian account of a minor (Uniform Gift to Minors Act)	The minor(2)
4.   Account in the name of guardian or committee for a designated ward, minor, or incompetent person	The ward, minor or incompetent person(3)
5.   a The usual revocable savings trust (grantor is also trustee)	The grantor-trustee(1)
b  So-called “trust” account that is not a legal or valid trust under State law	The actual owner(1)
6.   Sole proprietorship account or single-owner LLC	The owner(4)

For this type of account:	Give the EMPLOYER IDENTIFICATION number of—
7.   Sole proprietorship or single-owner LLC	The owner(4)
8.   Corporate account	The legal entity(5)
9.   Corporate or LLC electing corporation status	The corporation
10.   Association, club, religious, charitable, educational or other tax-exempt organization	The organization
11.   Partnership or multi-member LLC	The partnership
12.   A broker or registered nominee	The broker or nominee
13.   Account with the Department of Agriculture in the name of a public entity (such as a State or local government, school district or prison) that receives agricultural program payments	The public entity

GUIDELINES FOR CERTIFICATION OF TAXPAYER IDENTIFICATION

NUMBER ON SUBSTITUTE FORM W-9

Obtaining a Number

If you do not have a taxpayer identification number (TIN), apply for one immediately. To apply for a Social Security Number, get Form SS-5, Application for a Social Security Card, from your local Security Administration office or get this form on-line at www.ssa.gov/online/ss5.html. You may also get this form by calling 1-800-772-1213. Use Form W-7, Application for IRS Individual Taxpayer Identification Number, to apply for an Individual Taxpayer Identification Number, or Form SS-4, Application for Employer Identification Number, to apply for an Employer Identification Number. You can get Forms W-7 and SS-4 from the IRS by calling 1-800-829-3676 or from the IRS Web Site at www.irs.gov.

If you are asked to complete Form W-9 but do not have a TIN, write “Applied For” in the space for the TIN, sign and date the form, and give it to the requester. For interest and dividend payments, and certain payments made with respect to readily tradable instruments, generally you will then have 60 days to get a TIN and give it to the requester before you are subject to backup withholding on payments. The 60-day rule does not apply to other types of payments. You will be subject to backup withholding on all such payments until you provide your TIN to the requester.

Note: Writing “Applied For” means that you have already applied for a TIN or that you intend to apply for one soon.

Caution: A disregarded domestic entity that has a foreign owner must use the appropriate Form W-8.

Payees Exempt from Backup Withholding

Backup withholding is not required on any payments made to the following payees:

· An organization exempt from tax under section 501(a) of the Internal Revenue Code (IRC), any IRA, or a custodial account under IRC section 403(b)(7) if the account satisfies the requirements of IRC section 401(f)(2);

· The United States or any of its agencies or instrumentalities;

· A state, the District of Columbia, a possession of the United States, or any of their political subdivisions or instrumentalities;

· A foreign government or any of its political subdivisions, agencies or instrumentalities; or

· An international organization or any of its agencies or instrumentalities.

Other payees that may be exempt from backup withholding include:

· A corporation;

· A foreign central bank of issue;

· A dealer in securities or commodities required to register in the United States, the District of Columbia, or a possession of the United States;

· A futures commission merchant registered with the Commodity Futures Trading Commission;

· A real estate investment trust;

· An entity registered at all times during the tax year under the Investment Company Act of 1940;

· A common trust fund operated by a bank under IRC section 584(a);

· A financial institution;

· A middleman known in the investment community as a nominee or custodian; or

· A trust exempt form tax under IRC section 664 or described in IRC section 4947.

Payments of dividends and patronage dividends not generally subject to backup withholding include the following:

· Payments to nonresident aliens subject to withholding under IRC section 1441.

· Payments to partnerships not engaged in a trade or business in the United States and which have at least one nonresident partner

· Payments of patronage dividends not paid in money.

· Payments made by certain foreign organizations.

· Section 404(k) distributions made by an ESOP.

Payments of interest not generally subject to backup withholding include the following:

· Payments of interest on obligations issued by individuals. However, if you pay $600 or more of interest in the course of your trade or business to a payee, you must report the payment. Backup withholding applies to the reportable payment if the payee has not provided a TIN or has provided an incorrect TIN.

· Payments of tax-exempt interest (including exempt-interest dividends under IRC section 852).

· Payments described in IRC section 6049(b)(5) to non-resident aliens.

· Payments on tax-free covenant bonds under IRC section 1451.

· Payments made by certain foreign organizations.

· Mortgage or student loan interest paid to you.

Exempt payees described above should file Form W-9 to avoid possible erroneous backup withholding. FILE THIS FORM WITH THE PAYER, FURNISH YOUR TAXPAYER IDENTIFICATION NUMBER, WRITE “EXEMPT” ON THE FACE OF THE FORM, AND RETURN IT TO THE PAYER.

Certain payments other than interest, dividends, and patronage dividends that are not subject to information reporting are also not subject to backup withholding. For details, see IRC sections 6041, 6041A, 6042, 6044, 6045, 6049, 6050A and 6050N, and their regulations.

Privacy Act Notices. IRC section 6109 requires most recipients of dividends, interest or other payments to give TINs to payers who must report the payments to the IRS. The IRS uses the numbers for identification purposes and to help verify the accuracy of your tax return. Payers must be given the numbers whether or not recipients are required to file tax returns. Payers must generally withhold 28% of taxable interest, dividend and certain other payments to a payee who does not furnish a TIN to a payer. Certain penalties may also apply.

Penalties

(1)    Penalty for Failure to Furnish TIN. If you fail to furnish your correct TIN to a payer, you are subject to a penalty of $50 for each such failure unless your failure is due to reasonable cause and not to willful neglect.

(2)    Failure to Report Certain Dividend and Interest Payments. If you fail to include any portion of an includible payment for interest, dividends or patronage dividends in gross income, such failure will be treated as being due to negligence and will be subject to a penalty on any portion of an under-payment attributable to that failure unless there is clear and convincing evidence to the contrary.

(3)    Civil Penalty for False Statements With Respect to Withholding. If you make a false statement with no reasonable basis that results in backup withholding, you are subject to a $500 penalty.

(4)    Criminal Penalty for Falsifying Information. If you falsify certifications or affirmations, you are subject to criminal penalties including fines and/or imprisonment.

(5)    Misuse of TINs. If the requester discloses or uses TINs in violation of Federal law, the requester may be subject to civil and criminal penalties.

FOR ADDITIONAL INFORMATION CONTACT YOUR TAX CONSULTANT OR THE INTERNAL REVENUE SERVICE.

A-15

ANNEX B

NOTICE OF GUARANTEED DELIVERY

NOTICE OF GUARANTEED DELIVERY

Plains Exploration & Production Company

Plains E&P Company

Offer to Exchange

8 ³/4% Series B Senior Subordinated Notes due 2012 for any and all

outstanding 8 ³/4% Series A Senior Subordinated Notes due 2012

As set forth in the Prospectus dated September 12, 2003 (as the same may be amended from time to time, the “Prospectus”), of Plains Exploration & Production Company and Plains E&P Company (together, the “Issuers”) under the caption of “The Exchange Offer—Procedures for Tendering Series A Notes—Guaranteed Delivery,” this form or one substantially equivalent hereto must be used to accept the Issuers’ offer (the “Exchange Offer”) to exchange their 8¾% Series B Senior Subordinated Notes due 2012 (the “Series B notes”), which have been registered under the Securities Act of 1933, as amended (the “Securities Act”), for an equal principal amount of their 8 ³/4% Series A Senior Subordinated Notes due 2012 (the “Series A notes”), if (i) certificates representing the Series A notes to be exchanged are not lost but are not immediately available, or (ii) time will not permit all required documents to reach the Exchange Agent prior to the Expiration Date. This form may be delivered by an eligible institution by mail or hand delivery or transmittal, via facsimile, to the Exchange Agent at its address set forth below not later than 5:00 p.m., New York City time, on October 17, 2003. All capitalized terms used herein but not defined herein shall have the meanings ascribed to them in the Prospectus.

The Exchange Agent for the Exchange Offer is:

JPMorgan Chase Bank

By Mail: JPMorgan Chase Bank 600 Travis, Suite 1150 Houston, Texas 77002 Attention: Rebecca Newman By Facsimile: (713) 577-5200 Attention: Rebecca Newman Confirm by Telephone: (713) 216-4931 Attention: Rebecca Newman

Delivery or transmission via facsimile of this notice of guaranteed delivery to an address other than as set forth above will not constitute a valid delivery.

B-1

Ladies and Gentlemen:

The undersigned hereby tender(s) for exchange to the Issuers, upon the terms and subject to the conditions set forth in the Prospectus and the Letter of Transmittal, receipt of which is hereby acknowledged, the principal amount of the Series A notes as set forth below pursuant to the guaranteed delivery procedures set forth in the Prospectus under the caption of “The Exchange Offer—Procedures for Tendering Series A Notes—Guaranteed Delivery.”

The undersigned understands and acknowledges that the Exchange Offer will expire at 5:00 p.m., New York City time, on October 17, 2003, unless extended by the Issuers. With respect to the Exchange Offer, “Expiration Date” means such time and date, or if the Exchange Offer is extended, the latest time and date to which the Exchange Offer is so extended by the Issuers.

All authority herein conferred or agreed to be conferred by the Notice of Guaranteed Delivery shall survive the death or incapacity of the undersigned and every obligation of the undersigned under this Notice of Guaranteed Delivery shall be binding upon the heirs, personal representatives, executors, administrators, successors and assigns, trustees in bankruptcy and other legal representatives of the undersigned.

Name of Firm:
Address:	Name:
	Title:
Area Code and Telephone No.:	Date:

DO NOT SEND SERIES A NOTES WITH THIS FORM. ACTUAL SURRENDER OF SERIES A NOTES MUST BE MADE PURSUANT TO, AND BE ACCOMPANIED BY, THE LETTER OF TRANSMITTAL.

B-2

SIGNATURES	Principal Amount of Series A Notes Exchanged: $
Signature of Owner
	Certificate Nos. of Series A Notes (if available)
Signature of Owner (if more than one)
Dated:                                                                           , 2003
Name(s):
(Please Print)
Address:                                                                                     (Include Zip Code)
Area Code and Telephone No.:
Capacity (full title), if signing in a representative capacity:
Taxpayer Identification or Social Security No.:

B-3

GUARANTEE

(NOT TO BE USED FOR SIGNATURE GUARANTEE)

The undersigned, a member firm of a registered national securities exchange or of the National Association of Securities Dealers, Inc. or a commercial bank or trust company having an office or a correspondent in the United States, or is otherwise an “eligible guaranteed institution” within the meaning of Rule 17Ad-15 under the Securities Exchange Act of 1934, as amended, hereby guarantees that, within three New York Stock Exchange trading days from the date of this Notice of Guaranteed Delivery, a properly completed and duly executed Letter of Transmittal (or a facsimile thereof), together with certificates representing the Series A notes tendered hereby in proper form for transfer (or confirmation of the book-entry transfer of such Series A notes into the account of JPMorgan Chase Bank (the “Trust Company”) at a book-entry transfer facility, pursuant to the Trust Company’s account at a book-entry transfer facility, pursuant to the procedure for book-entry transfer set forth in the Prospectus under the caption “The Exchange Offer—Procedures for Tendering Series A Notes—Book-Entry Delivery Procedures”), and any other required documents will be deposited by the undersigned with the Trust Company.

Name of Firm:
Address:	Name:
	Title:
Area Code and Telephone No.:	Date:

DO NOT SEND SERIES A NOTES WITH THIS FORM. ACTUAL SURRENDER OF SERIES A NOTES MUST BE MADE PURSUANT TO, AND BE ACCOMPANIED BY, THE LETTER OF TRANSMITTAL.

B-4