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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-Q

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

SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2005

OR

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

SECURITIES EXCHANGE ACT OF 1934

Commission file number: 001-31470

PLAINS EXPLORATION & PRODUCTION COMPANY

(Exact name of registrant as specified in its charter)

700 Milam Street, Suite 3100

Houston, Texas 77002

(Address of principal executive offices)

(Zip Code)

(713) 579-6000

(Registrant’s telephone number, including area code)

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

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

77.4 million shares of Common Stock, $0.01 par value, issued and outstanding at April 29, 2005.

PLAINS EXPLORATION & PRODUCTION COMPANY

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

(i)

PLAINS EXPLORATION & PRODUCTION COMPANY

CONSOLIDATED BALANCE SHEETS (Unaudited)

(in thousands of dollars)

See notes to consolidated financial statements.

1

PLAINS EXPLORATION & PRODUCTION COMPANY

CONSOLIDATED STATEMENTS OF INCOME (Unaudited)

(in thousands, except per share data)

See notes to consolidated financial statements.

2

PLAINS EXPLORATION & PRODUCTION COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(in thousands of dollars)

See notes to consolidated financial statements.

3

PLAINS EXPLORATION & PRODUCTION COMPANY

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited)

(in thousands of dollars)

See notes to consolidated financial statements.

4

PLAINS EXPLORATION & PRODUCTION COMPANY

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY (Unaudited)

(share and dollar amounts in thousands)

See notes to consolidated financial statements.

5

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 (“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.

These consolidated financial statements and related notes present our consolidated financial position as of March 31, 2005 and December 31, 2004, the results of our operations, our comprehensive income and our cash flows for the three months ended March 31, 2005 and 2004 and the changes in our stockholders’ equity for the three months ended March 31, 2005. 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 three months March 31, 2005, 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, 2004.

Accounting Policies

Asset Retirement Obligations.    The following table reflects the changes in our asset retirement obligation (ARO) during the three months ended March 31, 2005 (in thousands):

(1) $3.6 million included in current liabilities.

Earnings Per Share.    For the three months ended March 31, 2005 and 2004 the weighted average shares outstanding for computing basic and diluted earnings per share were (in thousands):

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Due to our net loss in 2005 our unvested restricted stock, restricted stock units and stock options (846,000 equivalent shares) were not included in computing earnings per share because the effect was antidilutive. In computing earnings per share, no adjustments were made to reported net income.

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):

General and Administrative Expense.    Our general and administrative (“G&A”) expense consists of (in thousands):

Use of Estimates.    The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Significant estimates made by management include (1) oil and natural gas reserves; (2) depreciation, depletion and amortization, including future abandonment costs; (3) assigning fair value and allocating purchase price in connection with business combinations, including goodwill; (4) income taxes; (5) accrued liabilities; and (6) valuation of derivative instruments. Although management believes these estimates are reasonable, actual results could differ from these estimates.

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

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

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material, the amounts associated with buy/sell contracts and to discuss in a footnote to the financial statements the basis for the underlying accounting.

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

For the three months ended March 31, 2005, Gas Sales includes $7.8 million and Steam Gas Costs includes $8.1 million related to buy/sell contracts. If the EITF were to determine these transactions should be accounted for as non-monetary, such amounts would be netted in our Consolidated Statements of Income. We did not enter into buy/sell contracts in periods prior to our acquisition of Nuevo Energy Company in May 2004.

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

Recent Accounting Pronouncements. In December 2004 the FASB issued SFAS No.123R (revised 2004), “Share-Based Payment” (“SFAS 123R”). SFAS 123R requires that the compensation cost relating to share-based payment transactions be recognized in financial statements. That cost will be measured based on the fair value of the equity or liability instruments issued. SFAS No. 123R covers a wide range of share-based compensation arrangements including stock options, restricted stock plans, performance-based awards, stock appreciation rights, and employee stock purchase plans. SFAS 123R replaces FASB Statement No. 123, “Accounting for Stock-Based Compensation,” and supersedes APB Opinion No. 25, “Accounting for Stock Issued to Employees.” Public entities (other than those filing as small business issuers) were originally required to apply SFAS 123R as of the first interim or annual reporting period that begins after June 15, 2005. On April 14, 2005 the SEC announced the adoption of a new rule that amends the compliance dates for SFAS 123R. The Commission’s new rule allows registrants to implement SFAS 123R at the beginning of their next fiscal year, instead of the next reporting period, that begins after June 15, 2005. Accordingly, we will adopt SFAS 123R effective January 1, 2006. We are in the process of determining how the new method of valuing stock-based compensation as prescribed in SFAS 123R will be applied to valuing stock-based awards and the impact the recognition of compensation expense related to such awards will have on our financial statements.

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

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

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

In March 2005, the FASB issued FASB Interpretation (FIN) No. 47, “Accounting for Conditional Asset Retirement Obligations.” This Interpretation clarifies the definition and treatment of conditional asset retirement obligations as discussed in FASB Statement No. 143, “Accounting for Asset Retirement Obligations.” A conditional asset retirement obligation is defined as an asset retirement activity in which the timing and/or method of settlement are dependent on future events that may be outside the control of the company. FIN 47 states that a company must record a liability when incurred for conditional asset retirement obligations if the fair value of the obligation is reasonably estimable. This Interpretation is intended to provide more information about long-lived assets, more information about future cash outflows for these obligations and more consistent recognition of these liabilities. FIN 47 is effective for fiscal years ending after December 15, 2005. We do not believe that our financial position, results of operations or cash flows will be impacted by this Interpretation.

Note 2—Acquisitions

Nuevo Energy Company

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

Pro Forma Information

The following unaudited pro forma information shows the pro forma effect of the Nuevo acquisition, the issuance by PXP on June 30, 2004 of $250 million of 7.125% Senior Notes due 2014, the retirement of Nuevo’s 9 ³/8% Senior Subordinated Notes and TECONS on June 30, 2004 and the sale of Nuevo’s Congo operations. This unaudited pro forma information assumes such transactions occurred on January 1, 2004.

This unaudited pro forma information has been prepared based on our historical consolidated statements of income and the historical consolidated statement of income of Nuevo. 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 January 1, 2004.

Pro forma net income has been reduced by debt extinguishment costs of $3.0 million ($1.9 million after tax) in the three months ended March 31, 2004.

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Note 3—Derivative Instruments and Hedging Activities

General

We use various derivative instruments to manage our exposure to commodity price risk on sales of oil and gas production. All derivative instruments are recorded on the balance sheet at fair value. If a derivative does not qualify as a hedge or is not designated as a hedge, the changes in fair value, both realized and unrealized, are recognized currently in our income statement as gain (loss) on mark-to-market derivative contracts. If a derivative is designated as a cash flow hedge and qualifies for hedge accounting, any unrealized gain or loss is deferred in accumulated Other Comprehensive Income (“OCI”), a component of Stockholders’ Equity, until the hedged oil and gas production is sold. Realized gains and losses on derivative instruments that are designated as a hedge and qualify for hedge accounting are generally included in oil and gas revenues in the period the hedged volumes are sold. Gains and losses deferred in OCI related to cash flow hedges for which hedge accounting has been discontinued remain in OCI until the related product has been delivered.

We do not use hedge accounting for certain of our derivative instruments, either because the derivatives do not qualify for hedge accounting or we have elected not to use hedge accounting. Consequently, these derivative contracts are marked-to-market each quarter with fair value gains and losses, both realized and unrealized, recognized currently as a gain or loss on mark-to-market derivative contracts on the income statement. Cash flow is only impacted to the extent the actual settlements under the contracts result in making or receiving a payment from the counterparty.

Elimination of 2006 swap & collar positions

In March 2005, we executed a series of contracts that will eliminate all of our 2006 oil price swaps and collars at a pre-tax cost of approximately $292 million ($175 million after tax). Approximately $146 million of this amount is attributable to 2006 collars for 22,000 barrels of oil per day with a floor price of $25.00 and an average ceiling price of $34.76. Approximately $146 million of the cost is attributable to 2006 swaps for 15,000 barrels of oil per day at an average price of $25.28. The collars were not accounted for as hedges, therefore, the $146 million loss in the fair value of these instruments was currently recognized in our income statement and there will be no income statement effect subsequent to the amounts reported as of March 31, 2005. We used hedge accounting for the swaps and as a result the $146 million loss in fair value attributable to the swaps has been deferred in OCI and will be recognized as a noncash reduction to oil revenues in 2006 when the hedged production is sold.

The $146 million cash payment for the collars will be reflected as a financing cash outflow in our statement of cash flows when the cash is paid. Under SFAS 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities, the collars are deemed to contain a significant financing element because they included off-market terms. The $146 million cash payment for the swaps will be reflected as an operating cash outflow when the cash is paid. We expect to pay the cost to eliminate the 2006 swaps and collars in the second or third quarter of 2005 with proceeds received from the property sale discussed in Note 7. These payments will reduce derivative liabilities on our balance sheet

Acquisition of floors for 2006 oil production

In March 2005 we acquired $45.00 NYMEX put options on 40,000 barrels of oil per day in 2006. These put options cost an average of $2.96 per barrel which will be paid during 2006. We have elected not to use hedge accounting for the puts, consequently, the puts will be marked-to-market with fair value gains and losses recognized as a gain or loss on mark-to-market derivative contracts on the income statement.

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Derivative Instruments Designated as Cash Flow Hedges

At March 31, 2005, we had the following open commodity derivative positions designated as cash flow hedges:

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

Derivative Instruments Not Designated as Hedging Instruments

At March 31, 2005, we had the following open commodity derivative positions that were not designated as hedging instruments:

During the three months ended March 31, 2005 and 2004 we recognized pre-tax losses of $374 million and $2 million, respectively, from derivatives that do not qualify or have not been designated for hedge accounting. Cash settlements for the three months ended March 31, 2005 and 2004 were $37 million and $1 million, respectively.

Physical Purchase Contracts

Although not a derivative, at March 31, 2005 we also had the following contracts for the purchase of natural gas utilized in our steam flood operations:

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Other Comprehensive Income

OCI consists of the following gains (losses):

During the three months ended March 31, 2005 and 2004 deferred losses for cash flow hedges of $45.3 million and $17.8 million, respectively, were reclassified from OCI and charged to income as a reduction of oil and gas revenues and steam gas costs. During each of such periods we recognized $0.1 million for ineffectiveness of derivatives that qualify for hedge accounting. During the twelve months ended March 31, 2006, based on quoted market prices for future delivery as of March 31, 2005, we expect to reclassify $18.4 million of net deferred losses associated with open derivative contracts and $113.6 million of net deferred losses on terminated and de-designated derivative contracts from OCI to oil and gas revenue. Also during such period, we expect to reclassify approximately $53.2 million of deferred income tax benefits from OCI to income tax expense. The amounts ultimately reclassified to earnings will vary due the actual realized value upon settlement.

Net deferred losses associated with terminated or de-designated derivative contracts that have been or will be reclassified from OCI and recognized as a non-cash reduction in our 2005 and 2006 oil revenues are as follows (in thousands):

Note 4—Long-Term Debt

At March 31, 2005 and December 31, 2004 long-term debt consisted of (in thousands):

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Senior Revolving Credit Facility. At March 31, 2005, we had $143 million in borrowings and $7 million in letters of credit outstanding under the credit facility. At that date we were in compliance with the covenants contained in the credit facility and could have borrowed the full amount available under the credit facility. The effective interest rate on our borrowings under this revolving credit facility was 4.1% at March 31, 2005.

Note 5—Related Party Transactions

Our Chief Executive Officer is a director of Vulcan Energy Corporation (“Vulcan Energy” formerly known as Plains Resources). In connection with the reorganization and our 2002 spin-off from Plains Resources we entered into certain agreements with Plains Resources, including a master separation agreement; the Plains Exploration & Production transition services agreement that expired June 16, 2004; the Plains Resources transition services agreement that expired June 8, 2004; and a technical services agreement that expired June 30, 2004. For the three months ended March 31, 2004 we billed Plains Resources $0.3 million for services provided by us under these agreements.

Our Chief Executive Officer is a member of Cypress Aviation LLC (“Cypress”). During 2004, we chartered private aircraft from Gulf Coast Aviation Inc. (“Gulf Coast”), a corporation that from time-to-time leased aircraft owned by Cypress. In the three months ended March 31, 2004, we paid Gulf Coast $0.2 million in connection with such services. The charter services were arranged with market-based rates.

Plains All American Pipeline, L.P. (“PAA”), a publicly traded master limited partnership, is an affiliate of Vulcan Energy. PAA is the marketer/purchaser for a significant portion of our oil production, including the royalty share of production. The marketing agreement provides that PAA will purchase for resale at market prices certain of our oil production for which PAA charges a marketing fee of either $0.20 or $0.15 per barrel based upon the contract the barrels are resold under. During the three months ended March 31, 2005 and 2004, the following amounts were recorded with respect to such transactions (in thousands):

Note 6—Commitments and Contingencies

Environmental matters. As an owner or lessee and operator of oil and gas properties, we are subject to various federal, state, and local laws and regulations relating to discharge of materials into, and protection of, the environment. Often these regulations are more burdensome on older properties that were operated before the regulations came into effect such as some of our properties in California that have operated for over 90 years. We have established policies for continuing compliance with environmental laws and regulations. We also maintain insurance coverage for environmental matters, which we believe is customary in the industry, but we are not fully insured against all environmental risks. There can be no assurance that current or future local, state or federal rules and regulations will not require us to spend material amounts to comply with such rules and regulations.

In January 2005 we discovered and self-reported a violation related to flared gas emissions in excess of permitted levels on properties acquired in the Nuevo acquisition. Estimated excess emissions from

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the San Joaquin Valley casing vent recovery system located on the Gamble Lease are approximately 881 tons over a 745 day period. We brought the facility into compliance within 10 days of discovering the violation. We do not believe that the outcome of this matter will have a material adverse effect on our financial condition, results of operations or cash flows.

Plugging, Abandonment and Remediation Obligations. Consistent with normal industry practices, substantially all of our oil and gas leases require that, upon termination of economic production, the working interest owners plug and abandon non-producing wellbores, remove tanks, production equipment and flow lines and restore the wellsite. Typically, when producing oil and gas assets are purchased the purchaser assumes the obligation to plug and abandon wells that are part of such assets. However, in some instances, we receive an indemnity with respect to those costs. There can be no assurance that we will be able to collect on these indemnities.

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

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

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

CMS sold its interest in the Congolese properties to a subsidiary of Perenco, S.A. (Perenco) in 2002. Both CMS and Perenco filed a request with the Internal Revenue Service (IRS), in accordance with the U.S consolidated return regulations, for a closing agreement confirming that the transaction will not trigger recapture. The closing agreement is expected to be finalized in the near future. We and Perenco have finalized a closing agreement with the IRS confirming that neither our merger with Nuevo, nor the sale of our interest in the Congolese properties to Perenco will trigger recapture. The estimated remaining contingent liabilities are $19.2 million relative to Nuevo’s former interest, and

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$23.5 million relative to CMS’ former interest, for which we would be jointly liable. We believe the occurrence of a triggering event in the future is remote and we do not believe the agreements will have a material adverse effect upon us.

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

We are a defendant in various lawsuits arising in the ordinary course of our business. While the outcome of these lawsuits cannot be predicted with certainty and could have a material adverse effect on our financial position, we do not believe that the outcome of these legal proceedings, individually or in the aggregate, will have a material adverse effect on our financial condition, results of operations or cash flows.

Note 7 - Property Acquisitions and Dispositions

On March 11, 2005 we entered into an agreement to acquire certain California producing oil and gas properties from a private company for $119 million. The properties are primarily located in the Los Angeles Basin of onshore California with some smaller properties located in adjacent Ventura County. The transaction, which was financed under our existing credit facility, closed on April 1, 2005.

On March 31, 2005, we entered into a purchase and sale agreement with XTO Energy, Inc. to sell 275 net active wells for $350 million. As of December 31, 2004, our independent reserve engineers estimated that these producing properties had proven reserves of approximately 27 million equivalent barrels of which 81% was proved developed. The properties produced approximately 5,800 net equivalent barrels per day at March 31, 2005. This transaction, which has an effective date of January 1, 2005, is expected to close in the second quarter of 2005, subject to customary closing adjustments and we expect the net proceeds we receive will be reduced by approximately $15 to $20 million.

Note 8 - Consolidating Financial Statements

We are the issuer of $275 million of 8.75% Notes due 2012 and $250 million of 7.125% Notes due 2014. The 8.75% Notes and 7.125% Notes are jointly and severally guaranteed on a full and unconditional basis by our wholly-owned subsidiaries (referred to as “Guarantor Subsidiaries”).

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

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PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING BALANCE SHEET (Unaudited)

MARCH 31, 2005

(in thousands)