Plains Exploration & Production 10-Q/A 2003 Q3 Quarterly report (amended)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q / A

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

SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2003

OR

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

SECURITIES EXCHANGE ACT OF 1934

Commission file number: 001-31470

PLAINS EXPLORATION & PRODUCTION COMPANY

(Exact name of registrant as specified in its charter)

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

700 Milam Street, Suite 3100

Houston, Texas 77002

(Address of principal executive offices)

(Zip Code)

(832) 239-6000

(Registrant’s telephone number, including area code)

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

Indicate by check mark whether the registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2). Yes¨    Nox

40.3 million shares of Common Stock, $0.01 par value, issued and outstanding at October 31, 2003.

EXPLANATORY NOTE

This quarterly report on Form 10-Q/A (“Form 10-Q/A”) is being filed to amend in its entirety the Company’s quarterly report on Form 10-Q for the quarter ended September 30, 2003, which was filed with the SEC on November 7, 2003 (“Original Form 10-Q”). Accordingly, pursuant to rule 12b-15 under the Securities Exchange Act of 1934, as amended, the Form 10-Q/A contains the complete text of items 1, 2 and 3 of Part I and item 6 of Part II, as amended, as well as certain currently dated certifications.

The Company is adjusting its financial statements to correctly reflect the impact of purchase accounting on the derivative contracts assumed in its merger with 3TEC Energy Corporation, or 3TEC. Upon closing the merger, the Company considered the derivative contracts in determining the fair value of oil and gas properties subject to amortization. The Company followed hedge accounting for all of the derivative contracts and recorded a liability for the fair value on the closing date of the merger with offsetting debits to Other Comprehensive Income, or OCI, and deferred taxes. As the oil and gas production was sold, the Company reduced the liability for the settlements, reclassed the amount applicable to the settled contracts in OCI and reflected the cash settlements for these hedges as an increase or decrease to oil and gas revenues. Upon further review, it was recently determined that the treatment of the hedges in the initial purchase accounting was incorrect, resulting in adjustments to earnings subsequent to the acquisition, as well as adjustments to oil and gas properties and goodwill at the date of acquisition. The initial purchase accounting should have reflected the fair value of the derivatives as a liability with an increase to oil and gas properties and goodwill. Since the cash settlements on these derivatives for the period from acquisition through September 30, 2003 were less than the liability recorded at the merger date, the difference should have been reflected as an increase to earnings. In addition, the Company is adjusting the statement of cash flows to reclassify the payment of $14.7 million for the redemption of the 3TEC preferred stock, which occurred soon after the acquisition and contemplated at the date of the acquisition, as investing activities instead of as previously reported in operating activities.

In addition, it was determined that one gas collar that had been accounted for as a hedge did not qualify for hedge accounting because such contract had a value of a net liability which would be considered a net written option as of the date of acquisition.

Accordingly, the Company’s consolidated financial statements as of and for the three and nine months ended September 30, 2003 have been restated to reflect the correct accounting for the derivative contracts. The net effect of these adjustments was an increase of $24.0 million to total assets, which primarily relates to the increase to oil and gas properties subject to amortization, as of September 30, 2003, an increase to net income of $4.2 million and $5.9 million, respectively, for the three months and nine months ended September 30, 2003 and a decrease to other comprehensive income of $0.2 million for the three months ended September 30, 2003 and an increase to other comprehensive income of $15.2 million for the nine months ended September 30, 2003. These adjustments also increased net cash provided by operating activities and net cash used in investing activities by $14.8 million for the nine months ended September 30, 2003.

2

This amendment does not reflect events occurring after the filing of the Original 10-Q, and does not modify or update the disclosures therein in any way other than as required to reflect the amendments as described above and set forth below.

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

PART I. FINANCIAL INFORMATION

ITEM 1. Financial Statements:

Consolidated Balance Sheets (Unaudited) September 30, 2003 and December 31, 2002	4
Consolidated Statements of Income (Unaudited) For the three and nine months ended September 30, 2003 and 2002	5
Consolidated Statements of Cash Flows (Unaudited) For the nine months ended September 30, 2003 and 2002	6
Consolidated Statements of Comprehensive Income (Unaudited) For the three and nine months ended September 30, 2003 and 2002	7
Consolidated Statement of Changes in Stockholders' Equity (Unaudited) For the nine months ended September 30, 2003	8
Notes to Consolidated Financial Statements (Unaudited)	9
ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	32
ITEM 3. Quantitative and Qualitative Disclosures About Market Risk	42
PART II. OTHER INFORMATION	45

3

PLAINS EXPLORATION & PRODUCTION COMPANY

CONSOLIDATED BALANCE SHEETS (Unaudited)

(in thousands of dollars)

	September 30, 2003(1)			December 31, 2002
ASSETS
Current Assets
Cash and cash equivalents	$	4		$	1,028
Accounts receivable—Plains All American Pipeline, L.P.		20,951			22,943
Other accounts receivable		25,689			5,925
Commodity hedging contracts		2,615			2,594
Inventories		5,438			5,198
Other current assets		6,680			1,051
		61,377			38,739
Property and Equipment, at cost
Oil and gas properties—full cost method
Subject to amortization		1,025,670			629,454
Not subject to amortization		85,630			30,045
Other property and equipment		4,184			2,207
		1,115,484			661,706
Less allowance for depreciation, depletion and amortization		(170,065	)		(168,494	)
		945,419			493,212
Goodwill		149,722			—
Other Assets		17,877			18,929
	$	1,174,395		$	550,880
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts payable and other current liabilities	$	67,129		$	40,012
Commodity hedging contracts		29,722			24,572
Royalties payable		18,780			11,873
Interest payable		6,455			9,207
Current maturities of long-term debt		511			511
		122,597			86,175
Long-Term Debt
8.75% senior subordinated notes		276,949			196,855
Revolving credit facility		226,200			35,800
Other		—			511
		503,149			233,166
Asset Retirement Obligation		32,457			—
Other Long-Term Liabilities		16,713			6,303
Deferred Income Taxes		129,472			51,416
Commitments and Contingencies (Note 7)
Stockholders’ Equity
Common stock		405			244
Additional paid-in capital		321,996			174,279
Retained earnings		59,526			12,155
Accumulated other comprehensive income		(11,870	)		(12,858	)
Treasury stock		(50	)		—
		370,007			173,820
	$	1,174,395		$	550,880

(1) As restated, see Note 2

See notes to consolidated financial statements.

4

PLAINS EXPLORATION & PRODUCTION COMPANY

CONSOLIDATED STATEMENTS OF INCOME (Unaudited)

(in thousands, except per share data)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2003(1)			2002			2003(1)			2002
Revenues
Oil sales to Plains All American Pipeline, L.P.	$	58,903		$	55,957		$	178,496		$	137,633
Other oil sales		5,366			—			7,002			—
Oil hedging		(11,595	)		(7,616	)		(37,863	)		(8,070	)
Gas sales		37,011			2,552			57,240			7,130
Gas hedging		5,437			—			5,436			—
Other operating revenues		260			14			667			27
		95,382			50,907			210,978			136,720
Costs and Expenses
Production expenses		24,599			20,601			66,950			53,355
Production and ad valorem taxes		3,893			1,143			6,749			3,471
Gathering and transportation expenses		969			—			1,296			—
General and administrative
G&A excluding items below		5,517			2,636			14,274			7,362
Stock appreciation rights		4,670			—			7,317			—
Merger related costs		2,007			—			3,104			—
Depreciation, depletion and amortization		15,471			7,755			33,421			21,262
Accretion of asset retirement obligation		730			—			1,906			—
		57,856			32,135			135,017			85,450
Income from Operations		37,526			18,772			75,961			51,270
Other Income (Expense)
Interest expense		(6,936	)		(5,009	)		(17,130	)		(14,427	)
Extinguishment of debt		(224	)		—			(224	)		—
Expenses of terminated public equity offering		—			(1,700	)		—			(1,700	)
Gain on derivatives		1,741			—			3,207			—
Interest and other income (expense)		234			78			67			114
Income Before Income Taxes and Cumulative Effect of Accounting Change		32,341			12,141			61,881			35,257
Income tax expense
Current		(271	)		(1,642	)		(2,700	)		(5,660	)
Deferred		(14,526	)		(3,081	)		(24,134	)		(8,097	)
Income Before Cumulative Effect of Accounting Change		17,544			7,418			35,047			21,500
Cumulative effect of accounting change, net of tax		—			—			12,324			—
Net Income	$	17,544		$	7,418		$	47,371		$	21,500
Earnings Per Share (in dollars)
Basic
Income before cumulative effect of accounting change	$	0.44		$	0.31		$	1.13		$	0.89
Cumulative effect of accounting change		—			—			0.40			—
	$	0.44		$	0.31		$	1.53		$	0.89
Diluted
Income before cumulative effect of accounting change	$	0.43		$	0.31		$	1.12		$	0.89
Cumulative effect of accounting change		—			—			0.39			—
	$	0.43		$	0.31		$	1.51		$	0.89
Weighted Average Shares Outstanding
Basic		40,106			24,200			31,029			24,200
Diluted		40,726			24,200			31,415			24,200

(1) As restated, see Note 2

See notes to consolidated financial statements.

5

PLAINS EXPLORATION & PRODUCTION COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(in thousands of dollars)

	Nine Months Ended September 30,
	2003(1)			2002
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	47,371		$	21,500
Items not affecting cash flows from operating activities
Depreciation, depletion and amortization		33,421			21,262
Accretion of asset retirement obligation		1,906			—
Gain on derivatives		(3,207	)		—
Deferred income taxes		24,134			8,097
Cumulative effect of adoption of accounting change		(12,324	)		—
Noncash compensation		9,386			—
Other noncash items		352			372
Change in assets and liabilities from operating activities, net of effect of acquisition
Accounts receivable and other assets		2,399			(11,010	)
Accounts payable and other liabilities		(15,491	)		18,132
Net cash provided by operating activities		87,947			58,353
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to oil and gas properties		(95,024	)		(53,589	)
Acquisition of 3TEC Energy Corporation, net of cash acquired		(267,197	)		—
Proceeds from sale of oil and gas properties		8,517			—
Other		(1,759	)		(55	)
Net cash used in investing activities		(355,463	)		(53,644	)
CASH FLOWS FROM FINANCING ACTIVITIES
Change in revolving credit facility		190,400			90,700
Principal payments of long-term debt		(511	)		(511	)
Proceeds from debt issuance		80,061			196,752
Debt issuance costs		(4,143	)		(5,469	)
Distribution to Plains Resources Inc.		—			(311,964	)
Contribution from Plains Resources Inc.		—			5,000
Receipts from Plains Resources Inc.		510			21,536
Other		175			—
Net cash provided by financing activities		266,492			(3,956	)
Net increase (decrease) in cash and cash equivalents		(1,024	)		753
Cash and cash equivalents, beginning of period		1,028			13
Cash and cash equivalents, end of period	$	4		$	766

(1) As restated, see Note 2

See notes to consolidated financial statements.

6

PLAINS EXPLORATION & PRODUCTION COMPANY

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited)

(in thousands of dollars)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2003(1)			2002			2003(1)			2002
Net Income	$	17,544		$	7,418		$	47,371		$	21,500
Other Comprehensive Income (Loss)
Commodity hedging contracts, net of tax
Change in fair value		(795	)		(9,902	)		(18,332	)		(34,882	)
Reclassification adjustment for settled contracts		3,648			4,621			19,213			4,562
Other, net of tax		31			(167	)		107			(167	)
		2,884			(5,448	)		988			(30,487	)
Comprehensive Income (Loss)	$	20,428		$	1,970		$	48,359		$	(8,987	)

(1) As restated, see Note 2

See notes to consolidated financial statements.

7

PLAINS EXPLORATION AND PRODUCTION COMPANY

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY (Unaudited)

(share and dollar amounts in thousands)

	Common Stock			Additional Paid-in Capital			Retained Earnings(1)		Accumulated Other Comprehensive Income(1)			Treasury Stock						Total(1)
	Shares	Amount										Shares			Amount
Balance at December 31, 2002	24,224	$	244	$	174,279		$	12,155	$	(12,858	)	$	—		$	—		$	173,820
Net income	—		—		—			47,371		—			—			—			47,371
Contributions by Plains Resources Inc.	—		—		510			—		—			—			—			510
Issuance of common stock
Acquisition of 3TEC Energy Corporation	16,070		161		152,025			—		—			—			—			152,186
Other	20		—		206			—		—			—			—			206
Restricted stock awards
Deferred compensation	—		—		1,885			—		—			—			—			1,885
Spin-off by Plains Resources Inc.	—		—		(6,909	)		—		—			—			—			(6,909	)
Other comprehensive income	—		—		—			—		988			—			—			988
Repurchase of common stock	—		—		—			—		—			(4	)		(50	)		(50	)
Balance at June 30, 2003	40,314	$	405	$	321,996		$	59,526	$	(11,870	)		(4	)	$	(50	)	$	370,007

(1) As restated, see Note 2

See notes to consolidated financial statements.

8

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.

Prior to December 18, 2002, we were a wholly owned subsidiary of Plains Resources Inc., or 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”). On December 18, 2002, Plains Resources distributed 100% of the issued and outstanding shares of our common stock to its stockholders. Plains Resources received a favorable private letter ruling from the Internal Revenue Service stating that, for United States federal income tax purposes, the distribution by Plains Resources of our common stock qualified as a tax-free distribution under Section 355 of the Internal Revenue Code.

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 3.

These financial statements include allocations of direct and indirect corporate and administrative costs of Plains Resources made prior to the reorganization. The methods by which such costs were estimated and allocated to us were deemed reasonable by Plains Resources’ management; however, such allocations and estimates are not necessarily indicative of the costs and expenses that would have been incurred had we operated as a separate entity. Allocations of such costs are considered to be related party transactions and are discussed in Note 6.

These consolidated financial statements and related notes present our consolidated financial position as of September 30, 2003 and December 31, 2002, the results of our operations and our comprehensive income for the three and nine months ended September 30, 2003 and 2002, our cash flows for the nine months ended September 30, 2003 and 2002 and the changes in our stockholders’ equity for the nine months ended September 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 three and nine months ended September 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,

9

PLAINS EXPLORATION & PRODUCTION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)—(Continued)

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):

	Nine Months Ended September 30,
	2003			2002
				Pro forma
Asset retirement obligation—beginning of period	$	26,540		$	21,278
Liabilities incurred		5,156			—
Accretion expense		1,906			1,141
Asset retirement costs incurred		(654	)		—
Asset retirement obligation—end of period	$	32,948	(1)	$	22,419

(1) $491 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 three and nine months ended September 30, 2002 (thousands of dollars, except per share data):

	Pro forma
	Three Months Ended September 30, 2002		Nine Months Ended September 30, 2002
Net income—as reported	$	7,418	$	21,500
Adjustment for effect of change in accounting that is retroactively applied, net of tax		463		961
Pro forma net income	$	7,881	$	22,461
Earnings per share:
Basic—as reported	$	0.31	$	0.89
Adjustment for effect of change in accounting that is retroactively applied, net of tax		0.02		0.04
Basic—pro forma	$	0.33	$	0.93
Diluted—as reported	$	0.31	$	0.89
Adjustment for effect of change in accounting that is retroactively applied, net of tax		0.02		0.04
Diluted—pro forma	$	0.33	$	0.93

10

PLAINS EXPLORATION & PRODUCTION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)—(Continued)

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 24.2 million 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 three months and nine months ended September 30, 2002. The weighted average shares outstanding for computing both basic and diluted earnings per share was 24.2 million shares for such periods in 2002.

For the three months and nine months ended September 30, 2003 the weighted average shares outstanding for computing basic earning per share were 40.1 million and 31.0 million, respectively, and the weighted average shares outstanding for computing diluted earning per share were 40.7 million and 31.4 million, 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. 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):

	September 30, 2003		December 31, 2002
Oil	$	777	$	730
Materials and supplies		4,661		4,468
	$	5,438	$	5,198

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

	September 30, 2003		December 31, 2002
Land	$	8,853	$	8,853
Commodity hedging contracts		547		1,432
Debt issue costs, net		8,350		5,485
Other		127		3,159
	$	17,877	$	18,929

11

PLAINS EXPLORATION & PRODUCTION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)—(Continued)

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

Under the terms of a tax allocation agreement, our taxable income or loss prior to the spin-off was included in the consolidated income tax returns filed by Plains Resources. To the extent Plains Resources’ net operating losses were used in the consolidated return to offset our taxable income from operations during the period January 1, 2002 through the spin-off, we will reimburse Plains Resources for the reduction in our federal income tax liability resulting from the utilization of such net operating losses, but such reimbursement shall not exceed $3.0 million exclusive of any interest accruing under the agreement. At September 30, 2003 other long-term liabilities includes $3.0 million payable to Plains Resources with respect to the utilization of net operating losses. Such amount will be paid to Plains Resources in periods in which they are in a currently taxable position.

Income tax obligations reflected in our financial statements in periods prior to the spin-off are calculated assuming we filed a separate consolidated income tax return. To reflect differences between the amounts included in our financial statements at December 31, 2002 and the final 2002 tax returns filed by us and Plains Resources, income tax expense for the three months and nine months ended September 30, 2003 includes a $1.6 million charge (a $3.7 million deferred tax expense that includes a $1.7 million adjustment to reflect an increase in our effective state income tax rate, partially offset by a $2.1 million current tax benefit) and our deferred tax liability at December 31,2002 has been adjusted by $4.8 million. Such adjustments resulted in a $6.9 million decrease in our Additional Paid-in Capital.

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 had no effect on our financial statements.

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 had no 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.

12

PLAINS EXPLORATION & PRODUCTION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)—(Continued)

Under SFAS 142, goodwill and certain other intangible assets are not amortized, but rather are reviewed annually for impairment. One interpretation in applying these standards is that 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 September 30, 2003, we had undeveloped leaseholds of approximately $74.0 million that would be classified on our balance sheet as “intangible undeveloped leasehold” and developed leaseholds of an estimated $278.0 million that would be classified as “intangible developed leasehold” if we applied the interpretations described above. 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—Restatement of Financial Statements

These financial statements have been adjusted to correctly reflect the impact of purchase accounting on the derivative contracts assumed in its merger with 3TEC Energy Corporation, or 3TEC. Upon closing the merger, the Company considered the derivative contracts in determining the fair value of oil and gas properties subject to amortization. The Company followed hedge accounting for all of the derivative contracts and recorded a liability for the fair value on the closing date of the merger with offsetting debits to Other Comprehensive Income, or OCI, and deferred taxes. As the oil and gas production was sold, the Company reduced the liability for the settlements, reclassed the amount applicable to the settled contracts in OCI and reflected the cash settlements for these hedges as an increase or decrease to oil and gas revenues. Upon further review, it was recently determined that the treatment of the hedges in the initial purchase accounting was incorrect, resulting in adjustments to earnings subsequent to the acquisition, as well as adjustments to oil and gas properties and goodwill at the date of acquisition. The initial purchase accounting should have reflected the fair value of the derivatives as a liability with an increase to oil and gas properties and goodwill. Since the cash settlements on these derivatives for the period from acquisition through September 30, 2003 were less than the liability recorded at the merger date, the difference should have been reflected as an increase to earnings. In addition, it was determined that one gas collar that had been accounted for as a hedge did not qualify for hedge accounting because such contract had a value of a net liability which would be considered a net written option as of the date of acquisition. In addition, the Company is adjusting the statement of cash flows to reclassify the payment of $14.7 million for the redemption of the 3TEC preferred stock, which occurred soon after the acquisition and contemplated at the date of the acquisition, as investing activities instead of as previously reported in operating activities.

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PLAINS EXPLORATION & PRODUCTION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)—(Continued)

The significant effects of the restatement on the financial statements from the amounts previously reported are summarized in the following table (in thousands of dollars, except per share data):

	Three Months Ended September 30, 2003						Nine Months Ended September 30, 2003
	Previously Reported			As Restated			Previously Reported			As Restated
Consolidated Statements of Income
Oil hedging	$	(11,416	)	$	(11,595	)	$	(37,671	)	$	(37,863	)
Gas hedging		(357	)		5,437			(1,805	)		5,436
Total revenues		89,767			95,382			203,929			210,978
Depletion, depreciation and amortization		15,215			15,471			33,083			33,421
Total costs and expenses		57,600			57,856			134,679			135,017
Income from operations		32,167			37,526			69,250			75,961
Gain on derivatives		—			1,741			—			3,207
Income tax expense—deferred		(11,632	)		(14,526	)		(20,092	)		(24,134	)
Income before cumulative effect of accounting change		13,338			17,544			29,171			35,047
Net income		13,338			17,544			41,495			47,371
Earnings per share
Basic
Income before cumulative effect of accounting change	$	0.33		$	0.44		$	0.94		$	1.13
Net income		0.33			0.44			1.34			1.53
Diluted
Income before cumulative effect of accounting change		0.33			0.43			0.93			1.12
Net income		0.33			0.43			1.32			1.51
Consolidated Statements of Cash Flows
Cash flows from operating activities
Net income							$	41,495		$	47,371
Items not affecting cash flows from operating activities
Depreciation, depletion and amortization								33,083			33,421
Gain on derivatives								—			(3,207	)
Deferred income taxes								20,092			24,134
Change in assets and liabilities from operating activities, net of effect of acquisition
Accounts payable and other liabilities								(23,291	)		(15,491	)
Net cash provided by operating activities							$	73,098		$	87,947
Cash flows from investing activities
Acquisition of 3TEC Energy Corporation, net of cash acquired								(252,348	)		(267,197	)
Net cash used in investing activities								(340,614	)		(355,463	)
Consolidated Statements of Other Comprehensive Income
Net income	$	13,338		$	17,544		$	41,495		$	47,371
Commodity hedging contracts
Change in fair value		236			(795	)		(31,785	)		(18,332	)
Reclassification adjustment for settled contracts		6,975			3,648			23,389			19,213
Comprehensive income (loss)		20,580			20,428			33,206			48,359

(table continued on following page)

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PLAINS EXPLORATION & PRODUCTION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)—(Continued)

	September 30, 2003
	Previously Reported		As Restated
Consolidated Balance Sheet
Oil and gas properties—subject to amortization	1,003,656		1,025,670
Total property and equipment	1,093,470		1,115,484
Allowance for depreciation, depletion and amortization	(169,727	)	(170,065	)
Net property and equipment	923,743		945,419
Goodwill	147,383		149,722
Total assets	1,150,380		1,174,395
Deferred income taxes	120,610		129,472
Stockholders’ equity
Retained earnings	53,650		59,526
Accumulated other comprehensive income	(21,147	)	(11,870	)
Total stockholders’ equity	354,854		370,007
Total liabilities and stockholders’ equity	1,150,380		1,174,395

Note 3—Acquisition of 3TEC Energy Corporation

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

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PLAINS EXPLORATION & PRODUCTION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)—(Continued)

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)(1)
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		5,041
Total purchase price	$	408,012
Fair value of assets acquired and liabilities assumed:
Current assets	$	23,349
Oil and gas properties and equipment
Subject to amortization		294,356
Not subject to amortization		61,116
Other properties and equipment		218
Goodwill		149,722
Current liabilities		(75,468	)
Deferred tax liability related to the merger		(40,887	)
Other long-term liabilities		(4,394	)
Total purchase price	$	408,012

(1) As restated, see Note 2.

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.

16

PLAINS EXPLORATION & PRODUCTION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)—(Continued)

Pro Forma Information

The following unaudited pro forma information for the three months ended September 30, 2002 and the nine months ended September 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, 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.

	Three Months Ended September 30, 2002(1)		Nine Months Ended September 30,
			2003(1)		2002(1)
	(in thousands, except per share data)
Revenues	$	75,234	$	284,573	$	207,446
Income from operations		22,275		119,039		69,576
Income before the cumulative effect of accounting change		8,711		37,796		30,423
Net income		8,711		50,120		30,423
Earnings per share
Basic
Before cumulative effect of accounting change	$	0.22	$	0.94	$	0.76
Cumulative effect of accounting change		—		0.31		—
Net income	$	0.22	$	1.25	$	0.76
Diluted
Before cumulative effect of accounting change	$	0.22	$	0.94	$	0.76
Cumulative effect of accounting change		—		0.30		—
Net income	$	0.22	$	1.24	$	0.76
Weighted average shares outstanding
Basic		40,270		40,103		40,101
Diluted		40,270		40,489		40,101

(1) As restated, see Note 2

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 pro forma information presented above. Unrealized gains (losses) included in 3TEC’s results of operations totaled ($15.5) million for the nine months ended September 30, 2003 and $3.1 million and ($9.3) million for the three months and nine months ended September 30, 2002, respectively. At the time of the merger all of such derivative instruments, were assigned to us and in accordance with the provisions of SFAS 133, except for one gas collar, all were qualified for hedge accounting.

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PLAINS EXPLORATION & PRODUCTION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)—(Continued)

Note 4—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 Stockholders Equity.

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.

At September 30, 2003, OCI consisted of $19.7 million ($11.7 million net of tax) of unrealized losses on our oil and gas hedging instruments, a $0.2 million ($0.1 million, net of tax) loss related to our interest rate swap and $0.1 million ($0.1 million, net of tax) related to pension liabilities. The assets and liabilities related to all of our open commodity derivative instruments were included in current assets ($2.6 million), other assets ($0.5 million), current liabilities ($29.7 million), other long-term liabilities ($9.0 million) and deferred income taxes (a tax benefit of $10.0 million).

During the three and nine months ended September 30, 2003, $6.2 million ($3.7 million net of tax) and $32.4 million ($19.2 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 September 30, 2003, $14.3 million ($8.5 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 as the hedged volumes are produced and sold. In addition, during the three months and nine months ended September 30, 2003, $1.7 million and $3.2 million, respectively, of fair value changes for certain commodity derivatives acquired in the merger that do not qualify for hedge accounting is reflected in gain on derivatives.

At September 30, 2003, we had the following open commodity derivative 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 $23.85 per Bbl	—	—	7,500
Natural Gas Swaps
Average price $5.02 per MMBtu	50,000	—	—
Average price $4.45 per MMBtu	—	20,000	—
Natural Gas Costless Collar (1)
Floor price of $4.00 per MMBtu	—	20,000	—
Cap price of $5.15 per MMBtu

(1) Does not qualify for hedge accounting.

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PLAINS EXPLORATION & PRODUCTION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)—(Continued)

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.

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 September 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 2,500 barrels per day at $0.31 per barrel for the fourth quarter of 2003.

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 (1.6% at September 30, 2003).

Note 5—Long-Term Debt

At September 30, 2003 long-term debt consisted of:

	Current		Long-Term
Revolving credit facility	$	—	$	226,200
8.75% senior subordinated notes, including unamortized premium of $2.0 million		—
Other		511		—
	$	511	$	503,149

Revolving credit facility

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

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 our long-term debt rating. Commitment fees range from 0.375% to 0.5% of the unused portion of the borrowing base. Letter of credit fees range from 1.375% to 2.0%. The issuer of any letter of credit receives an issuing fee of 0.125% of the undrawn amount.

The credit facility contains negative covenants that limit our ability, as well as the ability of our subsidiaries, among other things, to incur additional debt, pay dividends on stock, make distributions of cash or property, change the nature of our business or operations, redeem stock or redeem subordinated debt, make investments,

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PLAINS EXPLORATION & PRODUCTION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)—(Continued)

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 September 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 September 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.

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 6—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 nine months ended September 30, 2003 we billed Plains Resources $0.4 million for services provided by us under these agreements and Plains Resources billed us $0.1 million for services they provided to us under these agreements.

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 nine months of 2003, we paid Gulf Coast $0.7 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

20

PLAINS EXPLORATION & PRODUCTION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)—(Continued)

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 nine months of 2002 we were charged $10.7 million of interest on amounts payable to Plains Resources.

To compensate Plains Resources for services rendered, we were allocated direct and indirect corporate and administrative costs of Plains Resources. For the first nine months of 2002 such costs totaled $4.4 million.

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 three months and nine months ended September 30, 2003 and 2002, the following amounts were recorded with respect to such transactions (in thousands of dollars).

	Three Months Ended September 30,				Nine Months Ended September 30,
	2003		2002		2003		2002
Sales of oil to PAA
PXP’s share	$	58,903	$	55,957	$	178,496	$	137,633
Royalty owners’ share		11,011		10,440		33,796		25,375
	$	69,914	$	66,397	$	212,292	$	163,008
Charges for PAA marketing fees	$	437	$	407	$	1,294	$	1,204

Note 7—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 in interest, 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. 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 8—Supplemental Cash Flow Information

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2003		2002		2003		2002
Cash payments for interest	$	11,561	$	567	$	21,770	$	567
Cash payments for taxes	$	779	$	143	$	3,581	$	469

21

PLAINS EXPLORATION & PRODUCTION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)—(Continued)

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

Fair value of common stock issued	$	152,186
Current liabilities assumed		75,468
Other long-term liabilities assumed		4,394
Deferred income tax liability		40,887
	$	272,935

As restated, see Note 2.

Note 9—Property Divestments

In September 2003, we sold our interest in 27 predominantly non-operated and noncore fields in the Permian Basin, the Texas Panhandle, the Mid-continent Area, Arkansas, Mississippi, and North Dakota for aggregate proceeds of approximately $14.3 million. Production from these fields was approximately 450 net equivalent barrels per day.

Note 10—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.

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PLAINS EXPLORATION & PRODUCTION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)—(Continued)

PLAINS EXPLORATION & PRODUCTION COMPANY

CONSOLIDATING BALANCE SHEET (Unaudited)

SEPTEMBER 30, 2003

(in thousands)

	Issuer(1)			Guarantor Subsidiaries(1)			Intercompany Eliminations(1)			Consolidated(1)
ASSETS
Current Assets
Cash and cash equivalents	$	3		$	1		$	—		$	4
Accounts receivable and other current assets		22,944			30,376			—			53,320
Commodity hedging contracts		485			2,130			—			2,615
Inventories		3,987			1,451			—			5,438
		27,419			33,958			—			61,377
Property and Equipment, at cost
Oil and natural gas properties—full cost method
Subject to amortization		562,448			463,222			—			1,025,670
Not subject to amortization		22,231			63,399			—			85,630
Other property and equipment		3,641			543			—			4,184
		588,320			527,164			—			1,115,484
Less allowance for depreciation, depletion and amortization		(60,548	)		(109,517	)		—			(170,065	)
		527,772			417,647			—			945,419
Goodwill		—			149,722			—			149,722
Investment in and Advances to Subsidiaries		452,287			—			(452,287	)		—
Other Assets		19,177			(1,300	)		—			17,877
	$	1,026,655		$	600,027		$	(452,287	)	$	1,174,395
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts payable and other current liabilities	$	45,422		$	46,942		$	—		$	92,364
Commodity hedging contracts		13,700			16,022			—			29,722
Current maturities on long-term debt		511			—			—			511
		59,633			62,964			—			122,597
Long-Term Debt		503,149			—			—			503,149
Asset Retirement Obligation		17,422			15,035			—			32,457
Other Long-Term Liabilities		11,262			5,451			—			16,713
Payable to Parent		454			465,546			(466,000	)		—
Deferred Income Taxes		80,150			49,322			—			129,472
Stockholders’ Equity
Stockholders’ equity		375,887			2,348			3,642			381,877
Accumulated other comprehensive income		(21,302	)		(639	)		10,071			(11,870	)
		354,585			1,709			13,713			370,007
	$	1,026,655		$	600,027		$	(452,287	)	$	1,174,395

(1) As restated, see Note 2.

Table continued on following page

23

PLAINS EXPLORATION & PRODUCTION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)—(Continued)

	Issuer			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
As previously reported:
Oil and natural gas properties—full cost method
Subject to amortization	$	562,448		$	441,208		$	—		$	1,003,656
Less allowance for depreciation, depletion and amortization		(60,548	)		(109,179	)		—			(169,727	)
Property and Equipment, at cost, net		527,772			395,971			—			923,743
Goodwill		—			147,383			—			147,383
Total assets		1,026,655			576,012			(452,287	)		1,150,380
Payable to Parent		—			466,000			(466,000	)		—
Deferred Income Taxes		80,335			40,275			—			120,610
Stockholders’ equity		376,001			(3,642	)		3,642			376,001
Accumulated other comprehensive income		(21,147	)		(10,071	)		10,071			(21,147	)
Total stockholders’ equity		354,854			(13,713	)		13,713			354,854
Total liabilities and stockholders’ equity		1,026,655			576,012			(452,287	)		1,150,380

24

PLAINS EXPLORATION & PRODUCTION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)—(Continued)

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

25

PLAINS EXPLORATION & PRODUCTION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)—(Continued)

PLAINS EXPLORATION & PRODUCTION COMPANY

CONSOLIDATING STATEMENTS OF INCOME (Unaudited)

THREE MONTHS ENDED SEPTEMBER 30, 2003

(in thousands)

	Issuer(1)			Guarantor Subsidiaries(1)			Intercompany Eliminations(1)			Consolidated(1)
Revenues
Oil sales to Plains All American Pipeline, L.P.	$	41,242		$	17,661		$	—		$	58,903
Other oil sales		—			5,366			—			5,366
Gas sales		3,921			33,090			—			37,011
Hedging		(7,157	)		999			—			(6,158	)
Other operating revenues		—			260			—			260
		38,006			57,376			—			95,382
Costs and Expenses
Production expenses		12,010			12,589			—			24,599
Production and ad valorem taxes		1,131			2,762			—			3,893
Transportation expenses		—			969			—			969
General and administrative
G&A, excluding items below		3,587			1,930			—			5,517
Stock appreciation rights		4,670			—			—			4,670
Merger related costs		2,007			—			—			2,007
Depreciation, depletion and amortization		3,166			12,305			—			15,471
Accretion of asset retirement obligation		368			362			—			730
		26,939			30,917			—			57,856
Income from Operations		11,067			26,459			—			37,526
Other Income (Expense)
Equity in earnings of subsidiaries		15,971			—			(15,971	)		—
Gain on derivatives		—			1,741			—			1,741
Extinguishment of debt		(224	)		—			—			(224	)
Interest expense		(5,641	)		(1,295	)		—			(6,936	)
Interest and other income		234			—			—			234
Income Before Income Taxes and Cumulative Effect of Accounting Change		21,407			26,905			(15,971	)		32,341
Income tax expense
Current		3,864			(4,135	)		—			(271	)
Deferred		(7,727	)		(6,799	)		—			(14,526	)
Net Income	$	17,544		$	15,971		$	(15,971	)	$	17,544
As previously reported:
Revenues
Hedging	$	(6,978	)	$	(4,795	)	$	—		$	(11,773	)
Total revenues		38,185			51,582			—			89,767
Costs and Expenses
Depreciation, depletion and amortization		3,166			12,049			—			15,215
Total expenses		26,939			30,661			—			57,600
Income from Operations		11,246			20,921			—			32,167
Other Income (Expense)
Equity in earnings of subsidiaries		11,659			—			(11,659	)		—
Gain on derivatives		—			—			—			—
Income Before Income Taxes and Cumulative Effect of Accounting Change		17,274			19,626			(11,659	)		25,241
Income tax expense
Deferred		(7,800	)		(3,832	)		—			(11,632	)
Net Income		13,338			11,659			(11,659	)		13,338

(1) As restated, see Note 2.

26

PLAINS EXPLORATION & PRODUCTION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)—(Continued)

PLAINS EXPLORATION & PRODUCTION COMPANY

CONSOLIDATING STATEMENTS OF INCOME (Unaudited)

THREE MONTHS ENDED SEPTEMBER 30, 2002

(in thousands)

	Issuer			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
Revenues
Oil sales to Plains All American Pipeline, L.P.	$	38,166		$	17,791		$	—		$	55,957
Gas sales		2,552			—			—			2,552
Hedging		(5,494	)		(2,122	)		—			(7,616	)
Other operating revenues		—			14			—			14
		35,224			15,683			—			50,907
Costs and Expenses
Production expenses		12,919			7,682			—			20,601
Production and ad valorem taxes		1,074			69			—			1,143
General and administrative		2,336			300			—			2,636
Depreciation, depletion and amortization		5,141			2,614			—			7,755
		21,470			10,665			—			32,135
Income from Operations		13,754			5,018			—			18,772
Other Income (Expense)
Equity in earnings of subsidiaries		2,449			—			(2,449	)		—
Interest expense		(3,597	)		(1,412	)		—			(5,009	)
Interest and other income		(223	)		301			—			78
Expenses of terminated public equity offering		(1,700	)		—			—			(1,700	)
Income Before Income Taxes		10,683			3,907			(2,449	)		12,141
Income tax expense
Current		1,175			(2,817	)		—			(1,642	)
Deferred		(4,440	)		1,359			—			(3,081	)
Net Income	$	7,418		$	2,449		$	(2,449	)	$	7,418

27

PLAINS EXPLORATION & PRODUCTION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)—(Continued)

PLAINS EXPLORATION & PRODUCTION COMPANY

CONSOLIDATING STATEMENTS OF INCOME (Unaudited)

NINE MONTHS ENDED SEPTEMBER 30, 2003

(in thousands)

	Issuer(1)			Guarantor Subsidiaries(1)			Intercompany Eliminations(1)			Consolidated(1)
Revenues
Oil sales to Plains All American Pipeline, L.P.	$	121,163		$	57,333		$	—		$	178,496
Other oil sales		—			7,002			—			7,002
Gas sales		12,150			45,090			—			57,240
Hedging		(23,292	)		(9,135	)		—			(32,427	)
Other operating revenues		—			667			—			667
		110,021			100,957			—			210,978
Costs and Expenses
Production expenses		35,296			31,654			—			66,950
Production and ad valorem taxes		3,035			3,714			—			6,749
Transportation expenses		—			1,296			—			1,296
General and administrative		—			—			—			—
G&A, excluding items below		11,333			2,941			—			14,274
Stock appreciation rights		7,317			—			—			7,317
Merger related costs		3,104			—			—			3,104
Depreciation, depletion and amortization		14,100			19,321			—			33,421
Accretion of asset retirement obligation		1,086			820			—			1,906
		75,271			59,746			—			135,017
Income from Operations		34,750			41,211			—			75,961
Other Income (Expense)
Equity in earnings of subsidiaries		24,588			—			(24,588	)		—
Gain on derivatives		—			3,207			—			3,207
Extinguishment of debt		(224	)		—			—			(224	)
Interest expense		(13,015	)		(4,115	)		—			(17,130	)
Interest and other income		58			9			—			67
Income Before Income Taxes and Cumulative Effect of Accounting Change		46,157			40,312			(24,588	)		61,881
Income tax expense
Current		4,734			(7,434	)		—			(2,700	)
Deferred		(15,199	)		(8,935	)		—			(24,134	)
Income Before Cumulative Effect of Accounting Change		35,692			23,943			(24,588	)		35,047
Cumulative effect of accounting change, net of tax benefit		11,679			645			—			12,324
Net Income	$	47,371		$	24,588		$	(24,588	)	$	47,371
As previously reported:
Revenues
Hedging	$	(23,100	)	$	(16,376	)	$	—		$	(39,476	)
Total revenues		110,213			93,716			—			203,929
Costs and Expenses
Depreciation, depletion and amortization		14,100			18,983			—			33,083
Total expenses		75,271			59,408			—			134,679
Income from Operations		34,942			34,308			—			69,250
Other Income (Expense)
Equity in earnings of subsidiaries		18,598			—			(18,598	)		—
Gain on derivatives		—			—			—			—
Income Before Income Taxes and Cumulative Effect of Accounting Change		40,359			30,202			(18,598	)		51,963
Income tax expense
Deferred		(15,277	)		(4,815	)		—			(20,092	)
Net Income		41,495			18,598			(18,598	)		41,495

(1) As restated, see Note 2.

28

PLAINS EXPLORATION & PRODUCTION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)—(Continued)

PLAINS EXPLORATION & PRODUCTION COMPANY

CONSOLIDATING STATEMENTS OF INCOME (Unaudited)

NINE MONTHS ENDED SEPTEMBER 30, 2002

(in thousands)

	Issuer			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
Revenues
Oil sales to Plains All American Pipeline, L.P.	$	98,884		$	38,749		$	—		$	137,633
Gas sales		7,130			—			—			7,130
Hedging		(6,192	)		(1,878	)		—			(8,070	)
Other operating revenues		—			27			—			27
		99,822			36,898			—			136,720
Costs and Expenses
Production expenses		34,871			18,484			—			53,355
Production and ad valorem taxes		3,271			200			—			3,471
General and administrative		6,281			1,081			—			7,362
Depreciation, depletion and amortization		15,126			6,136			—			21,262
		59,549			25,901			—			85,450
Income from Operations		40,273			10,997			—			51,270
Other Income (Expense)
Equity in earnings of subsidiaries		4,039			—			(4,039	)		—
Interest expense		(9,600	)		(4,827	)		—			(14,427	)
Interest and other income		(200	)		314			—			114
Expenses of terminated public equity offering		(1,700	)		—			—			(1,700	)
Income Before Income Taxes		32,812			6,484			(4,039	)		35,257
Income tax expense
Current		(1,711	)		(3,949	)		—			(5,660	)
Deferred		(9,601	)		1,504			—			(8,097	)
Net Income	$	21,500		$	4,039		$	(4,039	)	$	21,500

29

PLAINS EXPLORATION & PRODUCTION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)—(Continued)

PLAINS EXPLORATION & PRODUCTION COMPANY

CONSOLIDATING STATEMENTS OF CASH FLOWS (Unaudited)

NINE MONTHS ENDED SEPTEMBER 30, 2003

(in thousands of dollars)

	Issuer(1)			Guarantor Subsidiaries(1)			Intercompany Eliminations(1)			Consolidated(1)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	47,371		$	24,588		$	(24,588	)	$	47,371
Items not affecting cash flows from operating activities
Depreciation, depletion and amortization		14,100			19,321			—			33,421
Accretion of asset retirement obligation		1,086			820			—			1,906
Equity in earnings of subsidiaries		(24,588	)		—			24,588			—
Gain on derivatives		—			(3,207	)		—			(3,207	)
Deferred income taxes		15,199			8,935			—			24,134
Cumulative effect of adoption of accounting change		(11,679	)		(645	)		—			(12,324	)
Noncash compensation		9,386			—			—			9,386
Other noncash items		352			—			—			352
Change in assets and liabilities from operating activities
Accounts receivable and other assets		(4,802	)		7,201			—			2,399
Accounts payable and other liabilities		6,792			(22,283	)		—			(15,491	)
Net cash provided by (used in) operating activities		53,217			34,730			—			87,947
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to oil and gas properties		(62,989	)		(32,035	)		—			(95,024	)
Acquisition of 3TEC Energy Corporation, net of cash acquired		—			(267,197	)		—			(267,197	)
Proceeds from property sales		8,643			(126	)		—			8,517
Other		(10,276	)		8,517			—			(1,759	)
Net cash used in investing activities		(64,622	)		(290,841	)		—			(355,463	)
CASH FLOWS FROM FINANCING ACTIVITIES
Change in revolving credit facility		190,400			—			—			190,400
Proceeds from debt issuance		80,061			—			—			80,061
Debt issuance costs		(4,143	)		—			—			(4,143	)
Advances/investments with affiliates		(256,088	)		256,088			—			—
Receipts from (payments to) Plains Resources Inc.		510			—			—			510
Other		(336	)		—			—			(336	)
Net cash provided by (used in) financing activities		10,404			256,088			—			266,492
Net increase (decrease) in cash and cash equivalents		(1,001	)		(23	)		—			(1,024	)
Cash and cash equivalents, beginning of period		1,004			24			—			1,028
Cash and cash equivalents, end of period	$	3		$	1		$	—		$	4
As previously reported:
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	41,495		$	18,598		$	(18,598	)	$	41,495
Items not affecting cash flows from operating activities
Depreciation, depletion and amortization		14,102			18,981			—			33,083
Equity in earnings of subsidiaries		(18,598	)		—			18,598			—
Deferred income taxes		15,276			4,816			—			20,092
Change in assets and liabilities from operating activities
Accounts payable and other liabilities		6,599			(29,890	)		—			(23,291	)
Net cash provided by (used in) operating activities		53,217			19,881			—			73,098
CASH FLOWS FROM INVESTING ACTIVITIES
Acquisition of 3TEC Energy Corporation, net of cash acquired		—			(252,348	)		—			(252,348	)
Net cash used in investing activities		(64,622	)		(275,992	)		—			(340,614	)

(1) As restated, see Note 2.

30

PLAINS EXPLORATION & PRODUCTION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)—(Continued)

PLAINS EXPLORATION & PRODUCTION COMPANY

CONSOLIDATING STATEMENTS OF CASH FLOWS (Unaudited)

NINE MONTHS ENDED SEPTEMBER 30, 2002

(in thousands of dollars)

	Issuer			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	21,500		$	4,039		$	(4,039	)	$	21,500
Items not affecting cash flows from operating activities
Depreciation, depletion and amortization		15,126			6,136			—			21,262
Equity in earnings of subsidiaries		(4,039	)		—			4,039			—
Deferred income taxes		9,601			(1,504	)		—			8,097
Other noncash items		372			—						372
Change in assets and liabilities from operating activities
Accounts receivable and other assets		(8,805	)		1,152			—			(7,653	)
Accounts payable and other liabilities		18,407			(3,632	)		—			14,775
Net cash provided by operating activities		52,162			6,191			—			58,353
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to oil and gas properties		(46,920	)		(6,669	)		—			(53,589	)
Additions to other property and equipment		(51	)		(4	)		—			(55	)
Net cash used in investing activities		(46,971	)		(6,673	)		—			(53,644	)
CASH FLOWS FROM FINANCING ACTIVITIES
Principal payments on long-term debt		(511	)		—			—			(511	)
Change in revolving credit facility		90,700			—			—			90,700
Proceeds from debt issuance		196,752			—			—			196,752
Debt issuance costs		(5,469	)		—			—			(5,469	)
Contributions from Plains Resources Inc.		5,000			—			—			5,000
Distribution to Plains Resources Inc.		(311,964	)		—			—			(311,964	)
Receipts from Plains Resources Inc.		21,034			502			—			21,536
Net cash provided by financing activities		(4,458	)		502			—			(3,956	)
Net increase (decrease) in cash and cash equivalents		733			20			—			753
Cash and cash equivalents, beginning of period		11			2			—			13
Cash and cash equivalents, end of period	$	744		$	22		$	—		$	766

31

ITEM 2.    Management’s Discussion and Analysis of Financial Condition and Results of Operations

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

Prior to December 18, 2002, we were a wholly owned subsidiary of Plains Resources Inc., or Plains Resources. On December 18, 2002, Plains Resources distributed 100% of the issued and outstanding shares of our common stock to its stockholders. Plains Resources received a favorable private letter ruling from the Internal Revenue Service stating that, for United States federal income tax purposes, the distribution by Plains Resources of our common stock qualified as a tax-free distribution under Section 355 of the Internal Revenue Code.

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

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

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 oil, gas and natural gas liquids. We recognize revenues when our production is sold and title is transferred. Our revenues are highly dependent upon the prices of, and demand for, oil and gas. Historically, the markets for oil and gas have been volatile and are likely to continue to be volatile in the future. The prices we receive for our oil and gas and our levels of production are subject to wide fluctuations and depend on numerous factors beyond our control, including supply and demand, economic conditions, foreign imports, the actions of OPEC, political conditions in other oil-producing countries, and governmental regulation, legislation and policies. Under the SEC’s full cost accounting rules, we review the carrying value of our proved oil and gas properties each quarter. These rules generally require that we price our future oil and gas production at the oil and gas prices in effect at the end of each fiscal quarter to determine a ceiling value of our properties. The rules require a write-down if our capitalized costs exceed the allowed “ceiling.” We have had no write-downs due to these ceiling test limitations since 1998. Given the volatility of oil and gas prices, it is likely that our estimate of discounted future net revenues from proved oil and gas reserves will fluctuate in the near term. If oil and gas prices decline significantly in the future, write-downs of our oil and gas properties could occur. Write-downs required by these rules do not directly impact our cash flows from operating activities. Decreases in oil and gas prices have had, and will likely have in the future, an adverse effect on the carrying value of our proved reserves and our revenues, profitability and cash flow.

32

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 and gas prices decline below the prices at which these hedges are set. However, if oil and gas prices increase, ceiling prices in our hedges may cause us to receive less revenue on the hedged volumes than we would receive in the absence of hedges. 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 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.

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.

Results of Operations

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2003(2)			2002			2003(1)(2)			2002
Total Period Production
Oil and Liquids (MBbls)		2,437			2,320			6,905			6,433
Gas (MMcf)		7,354			821			10,828			2,540
MBOE		3,663			2,457			8,710			6,856
Average Daily Production
Oil and Liquids (Bbls)		26,489			25,217			25,293			23,564
Gas (Mcf)		79,935			8,924			39,663			9,304
BOE		39,812			26,705			31,904			25,115
Unit Economics (in dollars)
Average Oil & Liquids Sales Price ($/Bbl)
Average NYMEX	$	30.21		$	28.25		$	30.94		$	25.45
Hedging revenue (expense)		(4.76	)		(3.28	)		(5.49	)		(1.25	)
Differential		(3.84	)		(4.13	)		(4.07	)		(4.06	)
Net realized price	$	21.61		$	20.84		$	21.38		$	20.14
Average Gas Sales Price ($/Mcf)
Average NYMEX	$	5.05		$	3.28		$	5.43		$	3.04
Hedging revenue (expense)		0.74			—			0.50			—
Differential		(0.02	)		(0.17	)		(0.14	)		(0.23	)
Net realized price	$	5.77		$	3.11		$	5.79		$	2.81
Average Realized Price per BOE	$	24.44		$	20.71		$	23.34		$	19.94
Costs and Expenses per BOE
Production expenses		6.72			8.38			7.69			7.78
Production and ad valorem taxes		1.06			0.47			0.77			0.51
Gathering and transportation		0.26			—			0.15			—
G&A
G&A excluding items below		1.51			1.07			1.64			1.07
Stock appreciation rights		1.27			—			0.84			—
Merger related costs		0.55			—			0.36			—
DD&A		4.04			3.04			3.66			3.04

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

(2) As restated, see Note 2 to the consolidated financial statements.

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Comparison of Three Months Ended September 30, 2003 to Three Months Ended September 30, 2002

Items in this section under the captions net income, oil and gas revenues, depreciation, depletion and amortization, gain on derivatives and income tax expense have been restated to reflect the adjustments described in Note 2 to the consolidated financial statements.

Net income.    Net income was $17.5 million, or $0.43 per diluted share for the third quarter of 2003 compared to net income of $7.4 million, or $0.31 per diluted share for the third quarter of 2002. The increase is due to higher production volumes attributable to the 3TEC acquisition and higher realized prices, partially offset by increased costs related to the 3TEC acquisition and our spin-off from Plains Resources Inc.

Oil and gas revenues.    Oil and gas revenues increased 87%, or $44.2 million, to $95.1 million for the third quarter of 2003 from $50.9 million for the third quarter of 2002. The increase is due to increased production volumes attributable to the 3TEC acquisition and higher realized prices.

Oil revenues increased 9%, or $4.4 million, to $52.7 million for the third quarter of 2003 from $48.3 million for the third quarter of 2002. A 5%, or 0.1 million barrel, increase in 2003 production volumes to 2.4 million barrels increased revenues by $2.5 million and higher realized prices increased revenues by $1.9 million. The 3TEC acquisition accounted for 190,000 barrels of 2003 production.

The average realized price for oil increased 4% to $21.61 per Bbl for the third quarter of 2003 from $20.84 per Bbl for the third quarter of 2002. The increase is attributable to an improvement in the NYMEX oil price, which averaged $30.21 per Bbl in 2003 versus $28.25 per Bbl in 2002 and an improvement in the average location and quality differential from $4.13 per Bbl in 2002 compared to $3.84 per Bbl in 2003. Hedging had the effect of decreasing our average price per Bbl by $4.76 in 2003 compared to $3.28 per Bbl in 2002.

Gas revenues increased 1,531%, or $39.8 million, to $42.4 million for the third quarter of 2003 from $2.6 million for the third quarter of 2002. A 796%, or 6.5 MMcf, increase in 2003 production volumes to 7.4 MMcf increased revenues by $37.7 million and higher realized prices increased revenues by $2.1 million. The 3TEC acquisition accounted for 6.6 MMcf of 2003 production.

The average realized price for gas increased 86% to $5.77 per Mcf for the third quarter of 2003 from $3.11 per Mcf for the third quarter of 2002. The increase is primarily attributable to an improvement in the NYMEX gas price, which averaged $5.05 per Mcf in 2003 versus $3.28 in 2002 and hedging revenues that increased our average price per Mcf by $0.74 in the third quarter of 2003. The average location and quality differential for our gas production improved from $0.17 per Mcf in 2002 to $0.02 per Mcf in 2003.

Production expenses.    Production expenses increased 19%, or $4.0 million, to $24.6 million for the third quarter of 2003 from $20.6 million for the third quarter of 2002, primarily as a result of the 3TEC acquisition. The 3TEC properties accounted for $4.0 million of 2003 production expenses. On a per unit basis, production expenses decreased 20%, or $1.66 per BOE, to $6.72 per BOE for the third quarter of 2003 from $8.38 per BOE for the third quarter of 2002 due to the acquisition of the 3TEC properties which have a lower per unit production cost than our other properties.

Production and ad valorem taxes.    Production and ad valorem taxes increased 241%, or $2.8 million, to $3.9 million for the third quarter of 2003 from $1.1 million for the third quarter of 2002 due to the 3TEC acquisition. Production and ad valorem taxes for the 3TEC properties totaled $2.7 million in the third quarter of 2003.

Gathering and transportation expenses.    Gathering and transportation expenses, which totaled $1.0 million in 2003, represent costs incurred to deliver oil and gas produced from certain of the 3TEC properties to the sales point.

General and administrative expense.    General and administrative, or G&A, expense, excluding amounts attributable to stock appreciation rights, or SARs, and merger-related costs, increased 109%, or $2.9 million, to $5.5 million for the third quarter of 2003 from $2.6 million for the third quarter of 2002. The increase is

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primarily a result of our reorganization and spin-off, reflecting the incremental costs of operating as a separate, publicly held company and to increased costs resulting from the 3TEC acquisition.

G&A expense for the third quarter of 2003 includes a non-cash charge of $4.7 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 September 30, 2003 was $12.47 as compared to $10.81 on June 30, 2003 we recorded a non-cash expense. G&A expense in the third quarter of 2003 includes $2.0 million of merger related expenses consisting primarily of severance and other compensation costs and accounting system integration and conversion expenses.

G&A expense does not include amounts capitalized as part of our acquisition, exploration and development activities. We capitalized $2.7 million and $1.7 million of G&A expense in the third quarter of 2003 and 2002, respectively.

Depreciation, depletion and amortization, or DD&A.    DD&A expense increased 99%, or $7.7 million, to $15.5 million for the third quarter of 2003 from $7.8 million for the third quarter of 2002 primarily due to a higher per unit rate ($4.04 per BOE versus $3.04 per BOE) and higher production.

Accretion of asset retirement obligation.    Accretion expense for the third quarter of 2003 was $0.7 million. Accretion expense represents the adjustment of our asset retirement obligation to its present value at the end of the period.

Interest expense.    Interest expense increased 38% to $6.9 million for the third quarter of 2003 from $5.0 million for 2002 due to higher outstanding debt as a result of the merger. Interest expense does not include interest capitalized on oil and gas properties not subject to amortization and in the process of development. We capitalized approximately $1.2 million and $0.5 million of interest in the third quarter of 2003 and 2002, respectively.

Extinguishment of debt.    In 2003 we expensed $0.2 million of costs related to refinancing our credit facility in connection with the merger.

Expenses of terminated public equity offering.    In conjunction with the termination of our proposed initial public equity offering we expensed costs incurred of $1.7 million in 2002.

Income tax expense.    Income tax expense increased to $14.8 million in the third quarter of 2003 from $4.7 million in the third quarter of 2002. Income tax expense, before the effect of certain provision to return adjustments, increased 119%, or $8.4 million, to $13.2 million for the third quarter of 2003 from $4.7 million for the third quarter of 2002. Our overall effective tax rate increased to 41% in 2003 from 38.9% in 2002. Our currently payable effective tax rate was 7.4% for 2003 as compared to 13.5% for 2002. The decreased currently payable effective rate in 2003 primarily reflects the treatment for tax purposes of certain items that are capitalized for financial reporting purposes. Tax expense and effective tax rates for the periods prior to our spin-off on December 18, 2002 were calculated based on the tax sharing agreement with Plains Resources.

Income tax expense for the third quarter of 2003 includes a net $1.6 million charge (a $3.7 million charge to deferred tax expense that includes a $1.7 million adjustment to reflect an increase in our effective state income tax rate and a $2.1 million credit (benefit) to current tax expense) to reflect differences between our provision for income taxes for the year ended December 31, 2002 and the final 2002 tax returns filed by us and Plains Resources. Such adjustment primarily relates to differences in the treatment of certain items related to our oil and gas operations.

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Comparison of Nine Months Ended September 30, 2003 to Nine Months Ended September 30, 2002

Items in this section under the captions net income, oil and gas revenues, depreciation, depletion and amortization, gain on derivatives and income tax expense have been restated to reflect the adjustments described in Note 2 to the consolidated financial statements.

Net income.    We reported net income of $47.4 million, or $1.51 per diluted share for the nine months ended September 30, 2003 compared to net income of $21.5 million, or $0.89 per diluted share for the first nine months of 2002. Net income in 2003 includes the effect of the 3TEC acquisition as of June 1, 2003 and an after-tax $12.3 million credit related to the adoption of Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations”.

Oil and gas revenues.    Oil and gas revenues increased 54%, or $73.6 million, to $210.3 million for the first nine months 2003 from $136.7 million for 2002. The increase is due to increased production volumes attributable to the 3TEC acquisition and higher realized prices.

Oil revenues increased 14%, or $18.0 million, to $147.6 million for first nine months of 2003 from $129.6 million for 2002. A 7%, or 0.5 million barrel, increase in 2003 production volumes to 6.9 million barrels increased revenues by $10.0 million and higher realized prices increased revenues by $8.0 million. The 3TEC acquisition accounted for 0.3 million barrels of increased production.

The average realized price for oil increased 6%, or $1.24, to $21.38 per Bbl for the first nine months of 2003 from $20.14 per Bbl for 2002. The increase is attributable to an improvement in the NYMEX oil price, which averaged $30.94 per Bbl in 2003 versus $25.45 per Bbl in 2002. Hedging had the effect of decreasing our average price per Bbl by $5.49 in 2003 compared to $1.25 per Bbl in 2002.

Gas revenues increased $55.6 million, to $62.7 million for the first nine months of 2003 from $7.1 million for 2002. A 326% increase in 2003 production volumes to 10.8 MMcf increased revenues by $48.0 million and higher realized prices increased revenues by $7.6 million. The 3TEC acquisition accounted for 8.6 MMcf of 2003 production.

The average realized price for gas increased 106%, or $2.98, to $5.79 per Mcf for the first nine months of 2003 from $2.81 per Mcf for 2002. The increase is primarily attributable to an improvement in the NYMEX gas price, which averaged $5.43 per Mcf in 2003 versus $3.04 in 2002 and hedging revenues that increased our average price per Mcf by $0.50 in 2003. The average location and quality differential for our gas production improved from $0.23 per Mcf in 2002 to $0.14 in 2003.

Production expenses.    Production expenses increased 25%, or $13.6 million, to $67.0 million for the first nine months of 2003 from $53.4 million for the first nine months of 2002, primarily from an increased ownership percentage in our offshore California properties and the acquisition of the 3TEC properties. The 3TEC properties accounted for $5.5 million of 2003 production expenses. On a per unit basis, production expenses decreased to $7.69 per BOE in 2003 versus $7.78 per BOE in 2002.

Production and ad valorem taxes.    Production and ad valorem taxes increased 94%, or $3.2 million, to $6.7 million for the first nine months of 2003 from $3.5 million for the comparative period of 2002 due to the 3TEC acquisition. Production and ad valorem taxes in the first nine months of 2003 include $3.4 million attributable to the 3TEC properties.

Gathering and transportation expenses.    Gathering and transportation expense, which totaled $1.3 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.    G&A, expense, excluding amounts attributable to stock appreciation rights and merger-related costs, increased 94%, or $6.9 million, to $14.3 million for the first nine months of 2003 from $7.4 million for the first nine months of 2002. The increase is primarily a result of our reorganization and spin-off, reflecting the incremental costs of operating as a separate, publicly held company and to increased costs resulting from the 3TEC acquisition.

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G&A expense for 2003 includes a non-cash charge of $7.3 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 September 30, 2003 was $12.47 as compared to $9.75 on December 31, 2002 we recorded a non-cash expense. G&A expense in 2003 includes $3.1 million of merger related expenses consisting primarily of severance and other compensation costs and accounting system integration and conversion expenses.

G&A expense does not include amounts capitalized as part of our acquisition, exploration and development activities. We capitalized $7.4 million and $4.7 million of G&A expense in the first nine months of 2003 and 2002, respectively.

Depreciation, depletion and amortization, or DD&A.    DD&A expense increased 57%, or $12.1 million, to $33.4 million for the first nine months of 2003 from $21.3 million for the first nine months of 2002. Approximately $11.0 million of the increase was attributable to our oil and gas DD&A due to a higher per unit rate and higher production. Our oil and gas unit of production rate increased to $4.04 per BOE for the period subsequent to the merger as compared to $3.02 per BOE prior to the merger. In the first nine months of 2002 our rate was $3.04 per BOE. Other DD&A expense increased approximately $1.1 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 nine months of 2003 was $1.9 million. Accretion expense represents the adjustment of our asset retirement obligation to its present value at the end of the period based.

Interest expense.    Interest expense increased 19%, or $2.7 million, to $17.1 million for the first nine months of 2003 from $14.4 million for 2002 due to higher outstanding debt as a result of the merger. Interest expense does not include interest capitalized on oil and gas properties not subject to amortization. We capitalized approximately $2.0 million and $1.9 million of interest in the first nine months of 2003 and 2002, respectively.

Extinguishment of debt.    In 2003 we expensed $0.2 million of costs related to refinancing our credit facility in connection with the merger.

Expenses of terminated public equity offering.    In conjunction with the termination of our proposed initial public equity offering we expensed costs incurred of $1.7 million in 2002.

Income tax expense.    Income tax expense increased to $26.8 million in the first nine months of 2003 from $13.8 million in the first nine months of 2002. Income tax expense, before the effect of certain provision to return adjustments, increased 75%, or $11.4 million, to $25.2 million for the first nine months of 2003 from $13.8 million for the first nine months of 2002. Our overall effective tax rate increased to 41% in 2003 from 39% in 2002. Our currently payable effective tax rate was 8% for 2003 as compared to 16% for 2002. The decreased currently payable effective rate in 2003 primarily reflects the treatment for tax purposes of certain items that are capitalized for financial reporting purposes. Tax expense and effective tax rates for the periods prior to our spin-off on December 18, 2002 were calculated based on the tax sharing agreement with Plains Resources.

Income tax expense for the first nine months of 2003 includes a net $1.6 million charge (a $3.7 million charge to deferred tax expense that includes a $1.7 million adjustment to reflect an increase in our effective state income tax rate and a $2.1 million credit (benefit) to current tax expense) to reflect differences between our provision for income taxes for the year ended December 31, 2002 and the final 2002 tax returns filed by us and Plains Resources. Such adjustment primarily relates to differences in the treatment of certain items related to our oil and gas operations.

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

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Liquidity and Capital Resources

Our primary sources of liquidity are cash generated from our operations and our revolving credit facility. At September 30, 2003, we had $170.8 million of availability under our revolving credit facility. We believe that we have sufficient liquidity through our cash from operations and borrowing capacity under our revolving credit facility to meet our short-term and long-term normal recurring operating needs, debt service obligations, contingencies and anticipated capital expenditures.

Financing Activities

At September 30, 2003, we had a working capital deficit of $61.2 million. The working capital deficit includes $27.1 million attributable to the fair value of our hedges and $7.2 million that reflects the in-the-money value of stock appreciation rights that were deemed vested at September 30, 2003. 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 will be financed through cash flow and borrowings under our credit facility.

In April 2003, we entered into a three-year, $500.0 million senior revolving credit facility with a group of lenders and with JP Morgan Chase Bank serving as administrative agent. The credit facility provides for a borrowing base of $402.5 million that will be redetermined on a semi-annual basis, with us and the lenders each having the right to one annual interim unscheduled redetermination, and adjusted based on our oil and gas properties, reserves, other indebtedness and other relevant factors. The credit facility matures in April 2006. 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 September 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.

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

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

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

Cash Flows

	Nine Months Ended September 30,
	2003(1)			2002
	(in millions)
Cash provided by (used in):
Operating activities	$	87.9		$	58.4
Investing activities		(355.4	)		(53.6	)
Financing activities		266.5			(4.0	)

(1) As restated, see Note 2 to the consolidated financial statements.

Net cash provided by operating activities was $87.9 million and $58.4 million for the first nine months of 2003 and 2002, respectively. The increase primarily reflects higher revenues, partially offset by higher production and G&A costs.

Net cash used in investing activities was $355.4 million in the first nine months of 2003 and $53.6 million in the first nine months of 2002. Such amount for 2003 includes $267.2 million related to the merger. Costs incurred in connection with our oil and gas acquisition, development and exploration activities totaled $95.0 million in 2003 compared to $53.6 million in 2002.

In September 2003 we sold our interest in 27 predominantly non-operated and non-core fields in the Permian Basin, the Texas Panhandle, the Mid-continent Area, Arkansas, Mississippi, and North Dakota for aggregate proceeds of approximately $14.3 million. Production from these fields was approximately 450 net equivalent barrels per day. Approximately $8.3 million of the proceeds were received in September and the remainder was received in the fourth quarter. The proceeds were used to retire outstanding debt.

In October 2003 we sold our interest in nine predominantly non-operated and non-core fields located in New Mexico, the Mid-Continent area, East Texas, and Alabama for aggregate proceeds of approximately $8.9 million. Production from these fields was approximately 350 net equivalent barrels per day.

We are evaluating the sale of our Illinois assets that are currently producing approximately 2,300 net equivalent barrels per day.

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Net cash provided by financing activities in 2003 was $266.5 million, primarily reflecting a $190.4 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.

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 $131 to $134 million, including expenditures on the 3TEC properties from June 1 through December 31, 2003.

We will incur cash expenditures upon the exercise of stock appreciation rights, or SARs, but our outstanding shares will not increase. At September 30, 2003 we had approximately 4.1 million SARs outstanding of which 1.5 million were vested. If all of the vested SARs were exercised, based on $12.47, the price of our common stock as of September 30, 2003, we would pay $5.9 million to holders of the SARs.

Commitments and Contingencies

Contractual obligations.    At September 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	$	—	$	226,200	$	—	$	275,000
Producing property
remediation		1,188		1,225		1,100		700		600		2,150
Operating leases		900		3,584		2,977		2,361		2,220		12,536
	$	2,088	$	5,320	$	4,077	$	229,261	$	2,820	$	289,686

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 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 nine months ended September 30, 2003 we billed Plains Resources $0.4 million for services provided by us under these agreements and Plains Resources billed us $0.1 million for services they provided to us under these agreements.

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

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Critical Accounting Policies and Factors that May Affect Future Results

Based on the accounting policies that 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.

Goodwill.    In a purchase transaction, goodwill represents the excess of the purchase price plus the liabilities assumed, including deferred income taxes recorded in connection with the merger, over the fair value of the net assets acquired. In our acquisition of 3TEC, goodwill totaled $149.7 million and represents 13% of our total assets at September 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.

Other significant accounting policies.    Other significant accounting policies related to commodity pricing and risk management activities, write-downs under full cost ceiling test rules, oil and gas reserves and stock appreciation rights are discussed in our Annual Report on Form 10-K for the year ended December 31, 2002.

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 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 had 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 had no impact on our financial statements.

Statement Regarding Forward-Looking Statements

This Quarterly Report on Form 10-Q includes forward-looking statements based on our current expectations and projections about future events. Statements that are predictive in nature, that depend upon or refer to future events or conditions, or that include words such as “will”, “would”, “should”, “plans”, “likely”, “expects”, “anticipates”, “intends”, “believes”, “estimates”, “thinks”, “may”, and similar expressions, are forward-looking statements. These statements involve known and unknown risks, uncertainties and other factors that may cause our actual results and performance to be materially different from any future results or performance expressed in or implied by these forward-looking statements. These factors include, among other things:

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

• the consequences of any potential change in the relationship between us and Plains Resources;

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• unexpected difficulties in integrating our and 3TEC’s operations;

• 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);

• 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 Quarterly Report on Form 10-Q are made as of the date hereof, and you should not place undue certainty on these statements without also considering the risks and uncertainties associated with these statements and our business that are addressed in this Quarterly Report on Form 10-Q. 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. See —”Critical Accounting Policies and Factors That May Affect Future Results” for an additional discussion of risks and uncertainties.

ITEM 3.    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). 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.

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.

At September 30, 2003, OCI consisted of $19.7 million ($11.7 million net of tax) of unrealized losses on our oil and gas hedging instruments, a $0.2 million ($0.1 million, net of tax) loss related to our interest rate swap and $0.1 million ($0.1 million, net of tax) related to pension liabilities. The assets and liabilities related to all of our open commodity derivative instruments were included in current assets ($2.6 million), other assets ($0.5 million), current liabilities ($29.7 million), other long-term liabilities ($9.0 million) and deferred income taxes (a tax benefit of $8.0 million).

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During the three and nine months ended September 30, 2003, $6.2 million ($3.7 million net of tax) and $32.4 million ($19.2 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 September 30, 2003, $14.3 million ($8.5 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 as the hedged volumes are produced and sold. In addition, during the three months and nine months ended September 30, 2003, $1.7 million and $3.2 million, respectively, of fair value changes for certain commodity derivatives acquired in the merger that do not qualify for hedge accounting is reflected in gain on derivatives.

Commodity price risk.    At October 31, 2003, we had the following open commodity derivative positions:

	Bbls / MMBtu Per Day
	2003	2004	2005	2006
Oil Swaps
Average price $24.10 per Bbl	20,250	—	—	—
Average price $23.89 per Bbl	—	18,500	—	—
Average price $24.79 per Bbl	—	—	17,500	—
Average price $25.28 per Bbl	—	—	—	15,000
Natural Gas Swaps
Average price $5.02 per MMBtu	50,000	—	—	—
Average price $4.45 per MMBtu	—	20,000	—	—
Natural Gas Costless Collars
Floor price of $4.00 per MMBtu
Cap price of $5.15 per MMBtu (1)	—	20,000	—	—
Floor price of $4.75 per MMBtu
Cap price of $5.67 per MMBtu	—	10,000	—	—

(1) Does not qualify for hedge accounting.

Assuming third quarter 2003 production volumes are held constant in subsequent periods, these positions result in us hedging approximately 76%, 70%, 66% and 57% of oil production in 2003, 2004, 2005 and 2006, respectively, and approximately 63% of gas production in 2003 and 2004. 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 affect our net realized prices.

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.

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 September 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 2,500 barrels per day at $0.31 per barrel for the fourth quarter of 2003.

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 42% of the fair value of all open positions as of September 30, 2003. No one counterparty holds contracts that represent more than 25% of the fair value of all open positions as of September 30, 2003.

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

	September 30, 2003					December 31, 2002
	Fair Value			Effect of 10% Price Decrease		Fair Value			Effect of 10% Price Decrease
Swaps and options contracts	$	(35.4	)	$	38.2	$	(20.9	)	$	29.3

The fair value of the swaps and option contracts are estimated based on quoted prices from independent reporting services compared to the contract price of the agreement and approximate the gain or loss that would have been realized if the contracts had been closed out at of September 30, 2003 and December 31, 2002. All such 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 percent 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 percent change in prompt month oil prices, the fair value of our derivative portfolio would typically change less than that shown in the table due to lower volatility in out-month prices.

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

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

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PART II. OTHER INFORMATION

ITEM 6.    Exhibits and Reports on Form 8-K

(a) Exhibits

31.1	Certification of Chief Executive Officer, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Certification of Chief Financial Officer, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1	Chief Executive Officer Certification Pursuant to 18 U.S.C Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2	Chief Financial Officer Certification Pursuant to 18 U.S.C Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	PLAINS EXPLORATION & PRODUCTION COMPANY
Date: March 10, 2004	By:	/s/    STEPHEN A. THORINGTON
		Stephen A. Thorington Executive Vice President and Chief Financial Officer (Principal Financial Officer)

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