Plains Exploration & Production 10-Q/A 2003 Q2 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 June 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.)

500 Dallas Street, Suite 700

Houston, Texas 77002

(Address of principal executive offices)

(Zip Code)

(713) 739-6700

(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 July 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 June 30, 2003, which was filed with the SEC on August 14, 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 June 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 six months ended June 30, 2003 have been adjusted to reflect the correct accounting for the derivative contracts. The net effect of these adjustments was an increase of $24.3 million to total assets, which primarily relates to the increase to oil and gas properties subject to amortization, as of June 30, 2003, an increase to net income of $1.7 million for the three and six months ended June 30, 2003 and an increase to other comprehensive income of $13.6 million for the three and six months ended June 30, 2003. These adjustments also increased net cash provided by operating activities and net cash used in investing activities by $14.7 million for the six months ended June 30, 2003.

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

2

PLAINS EXPLORATION & PRODUCTION COMPANY

CONSOLIDATED BALANCE SHEETS (Unaudited)

(in thousands of dollars)

	June 30, 2003(1)			December 31, 2002
ASSETS
Current Assets
Cash and cash equivalents	$	3,466		$	1,028
Accounts receivable—Plains All American Pipeline, L.P.		23,103			22,943
Other accounts receivable		20,179			5,925
Commodity hedging contracts		1,675			2,594
Inventories		7,706			5,198
Other current assets		8,215			1,051
		64,344			38,739
Property and Equipment, at cost
Oil and gas properties—full cost method
Subject to amortization		1,000,216			629,454
Not subject to amortization		85,268			30,045
Other property and equipment		3,165			2,207
		1,088,649			661,706
Less allowance for depreciation, depletion and amortization		(155,078	)		(168,494	)
		933,571			493,212
Goodwill		146,301			—
Other Assets		18,616			18,929
	$	1,162,832		$	550,880
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts payable and other current liabilities	$	74,586		$	40,012
Commodity hedging contracts		39,748			24,572
Royalties payable		14,993			11,873
Interest payable		9,974			9,207
Current maturities of long-term debt		511			511
		139,812			86,175
Long-Term Debt
8.75% senior subordinated notes		276,991			196,855
Revolving credit facility		233,000			35,800
Other		511			511
		510,502			233,166
Asset Retirement Obligation		31,411			—
Other Long-Term Liabilities		17,577			6,303
Deferred Income Taxes		108,192			51,416
Commitments and Contingencies (Note 7)
Stockholders’ Equity
Common stock		405			244
Additional paid-in capital		327,705			174,279
Retained earnings		41,982			12,155
Accumulated other comprehensive income		(14,754	)		(12,858	)
		355,338			173,820
	$	1,162,832		$	550,880

(1) As restated, see Note 2

See notes to consolidated financial statements.

3

PLAINS EXPLORATION & PRODUCTION COMPANY

CONSOLIDATED STATEMENTS OF INCOME (Unaudited)

(in thousands, except per share data)

	Three Months Ended June 30,						Six Months Ended June 30,
	2003(1)			2002			2003(1)			2002
Revenues
Oil sales to Plains All American Pipeline, L.P.	$	54,855		$	46,435		$	119,593		$	81,676
Other oil sales		1,636			—			1,636			—
Oil hedging		(8,957	)		(3,898	)		(26,268	)		(454	)
Gas sales		16,125			2,590			20,229			4,578
Gas hedging		(1	)		—			(1	)		—
Other operating revenues		200			13			407			13
		63,858			45,140			115,596			85,813
Costs and Expenses
Production expenses		22,373			16,649			42,351			32,754
Production and ad valorem taxes		1,821			1,204			2,856			2,328
Gathering and transportation expenses		327			—			327			—
General and administrative
G&A excluding items below		4,561			2,274			8,757			4,726
Stock appreciation rights		4,010			—			2,647			—
Merger related costs		854			—			1,097			—
Depreciation, depletion and amortization		10,227			6,816			17,950			13,507
Accretion of asset retirement obligation		594			—			1,176			—
		44,767			26,943			77,161			53,315
Income from Operations		19,091			18,197			38,435			32,498
Other Income (Expense)
Interest expense		(5,338	)		(4,726	)		(10,194	)		(9,418	)
Gain on derivatives		1,466			—			1,466			—
Interest and other income (expense)		(200	)		18			(167	)		36
Income Before Income Taxes and Cumulative Effect of Accounting Change		15,019			13,489			29,540			23,116
Income tax expense
Current		(1,248	)		(1,973	)		(2,429	)		(4,018	)
Deferred		(4,871	)		(3,298	)		(9,608	)		(5,016	)
Income Before Cumulative Effect of Accounting Change		8,900			8,218			17,503			14,082
Cumulative effect of accounting change, net of tax		—			—			12,324			—
Net Income	$	8,900		$	8,218		$	29,827		$	14,082
Earnings Per Share (in dollars)
Basic
Income before cumulative effect of accounting change	$	0.31		$	0.34		$	0.66		$	0.58
Cumulative effect of accounting change		—			—			0.47			—
	$	0.31		$	0.34		$	1.13		$	0.58
Diluted
Income before cumulative effect of accounting change	$	0.31		$	0.34		$	0.66		$	0.58
Cumulative effect of accounting change		—			—			0.46			—
	$	0.31		$	0.34		$	1.12		$	0.58
Weighted Average Shares Outstanding
Basic		28,787			24,200			26,414			24,200
Diluted		29,111			24,200			26,682			24,200

(1) As restated, see Note 2

See notes to consolidated financial statements.

4

PLAINS EXPLORATION & PRODUCTION COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(in thousands of dollars)

	Six Months Ended June 30,
	2003(1)			2002
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	29,827		$	14,082
Items not affecting cash flows from operating activities
Depreciation, depletion and amortization		17,950			13,507
Accretion of asset retirement obligation		1,176			—
Gain on derivatives		(1,466	)		—
Deferred income taxes		9,608			5,016
Cumulative effect of adoption of accounting change		(12,324	)		—
Noncash compensation		2,685			—
Other noncash items		377			324
Change in assets and liabilities from operating activities, net of effect of acquisition
Accounts receivable and other assets		3,047			(2,839	)
Inventories		(2,297	)		(384	)
Accounts payable and other liabilities		(5,935	)		(9,930	)
Net cash provided by operating activities		42,648			19,776
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to oil and gas properties		(46,780	)		(42,341	)
Acquisition of 3TEC Energy Corporation, net of cash acquired		(266,617	)		—
Other		(740	)		(17	)
Net cash used in investing activities		(314,137	)		(42,358	)
CASH FLOWS FROM FINANCING ACTIVITIES
Change in revolving credit facility		197,200			—
Proceeds from debt issuance		80,061			—
Debt issuance costs		(4,069	)		—
Receipts from Plains Resources Inc.		510			22,576
Other		225			—
Net cash provided by financing activities		273,927			22,576
Net increase (decrease) in cash and cash equivalents		2,438			(6	)
Cash and cash equivalents, beginning of period		1,028			13
Cash and cash equivalents, end of period	$	3,466		$	7

(1) As restated, see Note 2

See notes to consolidated financial statements.

5

PLAINS EXPLORATION & PRODUCTION COMPANY

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited)

(in thousands of dollars)

	Three Months Ended June 30,						Six Months Ended June 30,
	2003(1)			2002			2003(1)			2002
Net Income	$	8,900		$	8,218		$	29,827		$	14,082
Other Comprehensive Income (Loss)
Commodity hedging contracts, net of tax
Change in fair value		(4,646	)		(3,973	)		(17,537	)		(24,980	)
Reclassification adjustment for settled contracts		5,308			2,112			15,565			(59	)
Interest rate swap, net of tax		10			—			16			—
Minimum pension liability adjustment, net of tax		60			—			60			—
		732			(1,861	)		(1,896	)		(25,039	)
Comprehensive Income (Loss)	$	9,632		$	6,357		$	27,931		$	(10,957	)

(1) As restated, see Note 2

See notes to consolidated financial statements.

6

PLAINS EXPLORATION AND PRODUCTION COMPANY

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY (Unaudited)

(share and dollar amounts in thousands)

	Common Stock			Additional Paid-in Capital		Contribution Receivable			Retained Earnings(1)		Accumulated Other Comprehensive Income(1)			Total(1)
	Shares	Amount
Balance at December 31, 2002	24,224	$	244	$	174,789	$	(510	)	$	12,155	$	(12,858	)	$	173,820
Net income	—		—		—		—			29,827		—			29,827
Contributions by Plains Resources Inc.	—		—				510					—			510
Issuance of common stock
Acquisition of 3TEC Energy Corporation	16,070		161		152,025		—			—		—			152,186
Other	18		—		9		—			—		—			9
Restricted stock awards
Deferred compensation	—		—		882		—			—		—			882
Other comprehensive income	—		—		—		—			—		(1,896	)		(1,896	)
Balance at June 30, 2003	40,312	$	405	$	327,705	$	—		$	41,982	$	(14,754	)	$	355,338

(1) As restated, see Note 2

See notes to consolidated financial statements.

7

PLAINS EXPLORATION & PRODUCTION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

Note 1—Organization and Significant Accounting Policies

Organization

The consolidated financial statements of Plains Exploration & Production Company (“Plains”, “PXP”, “us”, “our”, or “we”) include the accounts of our wholly-owned subsidiaries. We are an independent energy company engaged in the “upstream” oil and gas business of acquiring, exploiting, developing, exploring for and producing oil and gas. Our activities are all located in the United States.

Under the terms of a Master Separation Agreement between us and Plains Resources Inc. (“Plains Resources”), on July 3, 2002 Plains Resources contributed to us: (i) 100% of the capital stock of its wholly-owned subsidiaries that owned oil and gas properties offshore California and in Illinois; and (ii) all amounts payable to it by us and our subsidiary companies (the “reorganization”). In September 2002 we were converted from a limited partnership to a Delaware corporation and capitalized with 24.2 million shares of common stock, all of which were owned by Plains Resources. On December 18, 2002 Plains Resources distributed 24.1 million of the issued and outstanding shares of our common stock to its stockholders (the “spin-off”) and contributed the remaining 0.1 million shares to us.

On June 4, 2003, we acquired 3TEC Energy Corporation, or 3TEC. We have accounted for the acquisition as a purchase with effect from June 1, 2003. See Note 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 June 30, 2003 and December 31, 2002, the results of our operations and our comprehensive income for the three and six months ended June 30, 2003 and 2002, our cash flows for the six months ended June 30, 2003 and 2002 and the changes in our stockholders’ equity for the six months ended June 30, 2003. All adjustments, consisting only of normal recurring adjustments, that in the opinion of management were necessary for a fair statement of the results for the interim periods, have been reflected. All significant intercompany transactions have been eliminated. Certain reclassifications have been made to prior year statements to conform to the current year presentation. The results for the three and six months ended June 30, 2003, are not necessarily indicative of the final results to be expected for the full year.

These financial statements have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (SEC) regarding interim financial reporting. Accordingly, they do not include all of the information and notes required by accounting principles generally accepted in the United States of America for complete financial statements and should be read in conjunction with the audited consolidated financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2002.

Accounting Policies

Asset Retirement Obligations. Effective January 1, 2003 we adopted Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations” (SFAS 143). SFAS 143 requires entities to record the fair value of a liability for a legal obligation to retire an asset in the period in which the liability is

8

PLAINS EXPLORATION & PRODUCTION COMPANY

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

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

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

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

	Six Months Ended June 30,
	2003			2002
				Pro forma
Asset retirement obligation—beginning of period	$	26,540		$	21,278
Liabilities incurred		5,014
Accretion expense		1,176			932
Asset retirement costs incurred		(143	)
Asset retirement obligation—end of period	$	32,587	(1)	$	22,210

⁽¹⁾ $1,176 included in current liabilities.

The following table illustrates on a pro forma basis the effect on our net income and earnings per share as if SFAS 143 had been applied during the three and six months ended June 30, 2002 (thousands of dollars, except per share data):

	Proforma
	Three Months Ended June 30, 2002		Six Months Ended June 30, 2002
Net income—as reported	$	8,218	$	14,082
Adjustment for effect of change in accounting
that is retroactively applied, net of tax		254		498
Pro forma net income	$	8,472	$	14,580
Earnings per share:
Basic—as reported	$	0.34	$	0.58
Adjustment for effect of change in accounting that is retroactively applied, net of tax		0.01		0.02
Basic—pro forma	$	0.35	$	0.60
Diluted—as reported	$	0.34	$	0.58
Adjustment for effect of change in accounting that is retroactively applied, net of tax		0.01		0.02
Diluted—pro forma	$	0.35	$	0.60

9

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 24,200,000 shares of common stock, all of which were owned by Plains Resources. In accordance with SEC Staff Accounting Bulletin No. 98, this capitalization has been retroactively reflected for purposes for calculating earnings per share for the three months and six months ended June 30, 2002. The weighted average shares outstanding for computing both basic and diluted earnings per share was 24,200,000 shares for such periods in 2002.

For the three months and six months ended June 30, 2003 the weighted average shares outstanding for computing basic earning per share were 28,787,000 and 26,414,000, respectively, and the weighted average shares outstanding for computing diluted earning per share were 29,111,000 and 26,682,000, respectively. The weighted average shares outstanding for computing diluted earnings per share in 2003 include the effect of unvested restricted stock and restricted stock units. In computing EPS, no adjustments were made to reported net income.

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

Inventory.    Oil inventories are carried at the lower of the cost to produce or market value. Reinjected gas inventories are carried at the lower of cost or market value. Materials and supplies inventory is stated at the lower of cost or market with cost determined on an average cost method. Inventory consists of the following (in thousands):

	June 30, 2003		December 31, 2002
Oil	$	776	$	730
Reinjected gas		1,812		—
Materials and supplies		5,118		4,468
	$	7,706	$	5,198

10

PLAINS EXPLORATION & PRODUCTION COMPANY

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

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

	June 30, 2003		December 31, 2002
Land	$	8,853	$	8,853
Commodity hedging contracts		712		1,432
Debt issue costs, net		8,759		5,485
Other		292		3,159
	$	18,616	$	18,929

Recent Accounting Pronouncements.    The Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards No. 149 “Amendment of Statement 133 on Derivative Instruments and Hedging Activities” (SFAS 149) on April 30, 2003. SFAS 149 amends and clarifies accounting for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities under SFAS No. 133. The statement is effective for contracts entered into or modified after June 30, 2003 and for hedging relationships designated after June 30, 2003. The adoption of SFAS No. 149 will have no effect on either our financial position or results of operations.

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

Statement of Financial Accounting Standards No. 141,Business Combinations (SFAS 141) and Statement of Financial Accounting Standards, No. 142, Goodwill and Intangible Assets (SFAS 142) were issued by the FASB in June 2001 and became effective for us on July 1, 2001 and January 1, 2002, respectively. SFAS 141 requires all business combinations initiated after June 30, 2001 to be accounted for using the purchase method. Additionally, SFAS 141 requires companies to disaggregate and report separately from goodwill certain intangible assets. SFAS 142 establishes new guidelines for accounting for goodwill and other intangible assets. Under SFAS 142, goodwill and certain other intangible assets are not amortized, but rather are reviewed annually for impairment. The FASB, the SEC and others continue to discuss the appropriate application of SFAS 141 and 142 to oil and gas mineral rights held under lease and other contractual arrangements representing the right to extract such reserves. Depending on the outcome of such discussions, these oil and gas mineral rights held under lease and other contractual arrangements representing the right to extract such reserves for both undeveloped and developed leaseholds may be classified separately from oil and gas properties, as intangible assets on our balance sheets. In addition, the disclosures required by SFAS 141 and 142 relative to intangibles would be included in the notes to financial statements. Historically, we, like many other oil and gas companies, have included these oil and gas mineral rights held under lease and other contractual arrangements representing the right to extract such reserves as part of the oil and gas properties, even after SFAS 141 and 142 became effective.

As applied to companies like us that have adopted full cost accounting for oil and gas activities, we understand that this interpretation of SFAS 141 and 142 would only affect our balance sheet classification of proved oil and gas leaseholds acquired after June 30, 2001 and our unproved oil and gas leaseholds. Our results of operations and cash flows would not be affected, since these oil and gas mineral rights held under lease and other contractual arrangements representing the right to extract such reserves would continue to be amortized in accordance with full cost accounting rules.

11

PLAINS EXPLORATION & PRODUCTION COMPANY

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

As of June 30, 2003, we had undeveloped leaseholds of approximately $74 million that would be classified on our balance sheet as “intangible undeveloped leasehold” and developed leaseholds of an estimated $278 million that would be classified as “intangible developed leasehold” if we applied the interpretations currently being discussed. The amounts that would be subject to this classification included in our historical balance sheet prior to the acquisition of 3TEC is not material.

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

Note 2—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 June 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.

12

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 June 30, 2003						Six Months Ended June 30, 2003
	Previously Reported			As Restated			Previously Reported			As Restated
Consolidated Statements of Income
Oil hedging	$	(8,944	)	$	(8,957	)	$	(26,255	)	$	(26,268	)
Gas hedging		(1,448	)		(1	)		(1,448	)		(1	)
Total revenues		62,424			63,858			114,162			115,596
Depletion, depreciation and amortization		10,145			10,227			17,868			17,950
Total costs and expenses		44,685			44,767			77,079			77,161
Income from operations		17,739			19,091			37,083			38,435
Gain on derivatives		—			1,466			—			1,466
Income tax expense—deferred		(3,723	)		(4,871	)		(8,460	)		(9,608	)
Income before cumulative effect of accounting change		7,230			8,900			15,833			17,503
Net income		7,230			8,900			28,157			29,827
Earnings per share
Basic
Income before cumulative effect of accounting change	$	0.25		$	0.31		$	0.60		$	0.66
Net income		0.25			0.31			1.07			1.13
Diluted
Income before cumulative effect of accounting change		0.25			0.31			0.59			0.66
Net income		0.25			0.31			1.06			1.12
Consolidated Statements of Cash Flows
Cash flows from operating activities
Net income							$	28,157		$	29,827
Items not affecting cash flows from operating activities
Depreciation, depletion and amortization								17,868			17,950
Gain on derivatives								—			(1,466	)
Deferred income taxes								8,460			9,608
Change in assets and liabilities from operating activities, net of effect of acquisition
Accounts payable and other liabilities								(19,235	)		(5,935	)
Net cash provided by operating activities								35,250			42,648
Cash flows from investing activities
Acquisition of 3TEC Energy Corporation, net of cash acquired								(251,883	)		(266,617	)
Net cash used in investing activities								(299,403	)		(314,137	)
Consolidated Statements of Other Comprehensive Income
Net income	$	7,230		$	8,900		$	28,157		$	29,827
Commodity hedging contracts—change in fair value		(19,130	)		(4,646	)		(32,021	)		(17,537	)
Commodity hedging contracts—reclassification adjustment for settled contracts		6,157			5,308			16,414			15,565
Comprehensive income (loss)		(5,673	)		9,632			12,626			27,931

(table continued on following page)

13

PLAINS EXPLORATION & PRODUCTION COMPANY

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

	June 30, 2003
	Previously Reported			As Restated
Consolidated Balance Sheet
Oil and gas properties—subject to amortization	$	978,202		$	1,000,216
Total property and equipment		1,066,635			1,088,649
Allowance for depreciation, depletion and amortization		(154,996	)		(155,078	)
Net property and equipment		911,639			933,571
Goodwill		143,962			146,301
Total assets		1,138,561			1,162,832
Deferred income taxes		99,226			108,192
Stockholders’ equity
Retained earnings		40,312			41,982
Accumulated other comprehensive income		(28,389	)		(14,754	)
Total stockholders’ equity		340,033			355,338
Total liabilities and stockholders’ equity		1,138,561			1,162,832

Note 3—Acquisition of 3TEC Energy Corporation

On June 4, 2003 we acquired 3TEC, 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 with effect from June 1, 2003.

The calculation of the purchase price and the preliminary allocation to assets and liabilities as of June 4, 2003 are shown below. The average PXP common stock price is based on the average closing price of PXP common stock during the five business days commencing two days before the merger was announced. The purchase price allocation is preliminary because certain items such as the determination of the final tax bases and fair value of the assets and liabilities as of the acquisition date have not been completed.

	(in thousands, except share price) (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		4,269
Total purchase price	$	407,240
Fair value of assets acquired and liabilities assumed:
Current assets		24,773
Oil and gas properties and equipment
Subject to amortization		294,356
Not subject to amortization		61,116
Other properties and equipment		218
Goodwill		146,301
Current liabilities		(74,243	)
Deferred tax liability related to the merger		(40,887	)
Other long-term liabilities		(4,394	)
Total purchase price	$	407,240

(1) As restated, see Note 2

14

PLAINS EXPLORATION & PRODUCTION COMPANY

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

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

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

Pro Forma Information

The following unaudited pro forma information for the three and six months ended June 30, 2003 and 2002 has been prepared based on our historical consolidated statements of income and the historical consolidated statements of income of 3TEC. Such pro forma information for 2003 and 2002 assumes the merger and the issuance of $75.0 million of 8.75% senior subordinated notes on May 31, 2003 occurred on January 1, 2003 and January 1, 2002, 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 5.

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 June 30,				Six Months Ended June 30,
	2003(1)		2002(1)		2003(1)		2002(1)
	(in thousands, except per share data)
Revenues	$	89,124	$	73,082	$	189,191	$	132,212
Income from operations		32,315		29,313		82,332		47,301
Income before the cumulative effect of accounting change		146		17,156		19,145		16,124
Net income		146		17,156		31,469		16,124
Earnings per share
Basic
Before cumulative effect of accounting change	$	—	$	0.43	$	0.48	$	0.40
Cumulative effect of accounting change		—		—		0.31		—
Net income		—		0.43		0.79		0.40
Diluted
Before cumulative effect of accounting change	$	—	$	0.43	$	0.47	$	0.40
Cumulative effect of accounting change		—		—		0.31		—
Net income		—		0.43		0.78		0.40
Weighted average shares outstanding
Basic		40,089		40,263		40,087		40,263
Diluted		40,413		40,271		40,355		40,271

(1) As restated, see Note 2

15

PLAINS EXPLORATION & PRODUCTION COMPANY

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

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 ($23.0) million and ($22.4) million for the three months and six months ended June 30, 2003, respectively, and $9.0 million and ($12.4) million for the three months and six months ended June 30, 2002, respectively. At the time of the merger such derivative instruments were assigned to us and in accordance with the provisions of SFAS 133 all such derivative instruments, except for one natural gas collar, were qualified for hedge accounting.

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 Stockholder’s 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 June 30, 2003, OCI consisted of $24.5 million ($14.5 million net of tax) of unrealized losses on our oil and gas hedging instruments, $0.3 million ($0.2 million, net of tax) loss related to our interest rate swap and $0.1 million ($0.1 million, net of tax) related to pension liabilities. The assets and liabilities related to all of our open commodity derivative instruments were included in current assets ($1.7 million), other assets ($0.7 million), current liabilities ($39.5 million), other long-term liabilities ($10.4 million) and deferred income taxes (a tax benefit of $10.0 million).

During the three and six months ended June 30, 2003, $9.0 million ($5.3 million net of tax) and $26.3 million ($15.6 million net of tax) in losses from the settlement of oil and gas hedging instruments were reclassified from OCI and charged to income as a reduction of oil and gas revenues. As of June 30, 2003, $18.9 million ($11.2 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. In addition, during the three and six months ended June 30, 2003, $1.4 million 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 in each of the periods.

16

PLAINS EXPLORATION & PRODUCTION COMPANY

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

At June 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	—	—	5,000
Natural Gas Swaps
Average price $5.02 per MMBtu	50,000	—	—
Average price $4.45 per MMBtu	—	20,000	—
Natural Gas Costless Collar(1)	—	20,000	—
Floor price of $4.00 per MMBtu
Cap price of $5.15 per MMBtu

(1) Does not qualify for hedge accounting

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

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

We utilize interest rate swaps to manage the interest rate exposure on our long-term debt. We currently have an interest rate swap agreement that expires in October 2004 that fixes the interest rate on $7.5 million of borrowings under our credit facility at 3.9% plus the LIBOR margin set forth in the credit facility (1.625% at June 30, 2003).

Note 5—Long-Term Debt

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

	Current		Long-Term
Revolving credit facility	$	—	$	233,000
8.75% senior subordinated notes, including unamortized premium of $2.0 million		—		276,991
Other		511		511
	$	511	$	510,502

Revolving credit facility

On May 30, 2003, $30.1 million in borrowings outstanding under our $300.0 million revolving credit facility were repaid and the facility was terminated.

17

PLAINS EXPLORATION & PRODUCTION COMPANY

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

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

Amounts borrowed under the credit facility bear an annual interest rate, at our election, equal to either: (i) the Eurodollar rate, plus from 1.375% to 2.00%; or (ii) the greatest of (1) the prime rate, as determined by JP Morgan Chase Bank, (2) the certificate of deposit rate, plus 1.0%, or (3) the federal funds rate, plus 0.5%; plus an additional 0.125% to 0.75% for each of (1)-(3). The amount of interest payable on outstanding borrowings is based on (1) the utilization rate as a percentage of the total amount of funds borrowed under the credit facility to the borrowing base and (2) our long-term debt rating. Commitment fees and letter of credit fees under the credit facility are based on the utilization rate and long-term debt rating. Commitment fees range from 0.375% to 0.5% of the unused portion of the borrowing base. Letter of credit fees range from 1.375% to 2.0%. The issuer of any letter of credit receives an issuing fee of 0.125% of the undrawn amount.

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

8.75% senior subordinated notes

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

At June 30, 2003 we had $275.0 million principal amount of 8.75% notes outstanding. The 8.75% notes are our unsecured general obligations, are subordinated in right of payment to all of our existing and future senior indebtedness and are jointly and severally guaranteed on a full, unconditional basis by all of our existing and future domestic restricted subsidiaries. The indenture governing the 8.75% notes contains covenants that limit our ability, as well as the ability of our subsidiaries, among other things, to incur additional indebtedness, make certain investments, make restricted payments, sell assets, enter into agreements containing dividends and other payment restrictions affecting subsidiaries, enter into transactions with affiliates, create liens, merge, consolidate and transfer assets and enter into different lines of business. In the event of a change of control, as defined in the indenture, we will be required to make an offer to repurchase the notes at 101% of the principal amount thereof, plus accrued and unpaid interest to the date of the repurchase. The indenture governing the 8.75% notes permitted the spin-off and the spin-off did not, in itself, constitute a change of control for purposes of the indenture. The merger did not constitute a change of control for purposes of the indenture.

18

PLAINS EXPLORATION & PRODUCTION COMPANY

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

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 six months ended June 30, 2003 we billed Plains Resources $0.3 million for services provided by us under these agreements and Plains Resources billed us $0.1 million for services they provided to us under these agreements.

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

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

To compensate Plains Resources for services rendered, we were allocated direct and indirect corporate and administrative costs of Plains Resources. Such costs for the first six months of 2002 totaled $4.4 million. Of such amount $3.1 million was included in general and administrative expense and $1.3 million was capitalized in oil and gas properties.

Plains All American Pipeline, L.P. (“PAA”), a publicly-traded master limited partnership, is an affiliate of Plains Resources. Certain of our officers and directors are officers and directors of Plains Resources. PAA is the exclusive marketer/purchaser for all of our equity oil production, including the royalty share of production, from properties owned prior to the merger. The marketing agreement provides that PAA will purchase for resale at market prices all of our equity oil production for which PAA charges a fee of $0.20 per barrel. During the three months and six months ended June 30, 2003 and 2002, the following amounts were recorded with respect to such transactions (in thousands of dollars).

	Three Months Ended June 30,				Six Months Ended June 30,
	2003		2002		2003		2002
Sales of oil to PAA
PXP’s share	$	54,855	$	46,435	$	119,593	$	81,676
Royalty owners’ share		10,425		8,244		22,785		14,935
	$	65,280	$	54,679	$	142,378	$	96,611
Charges for PAA marketing fees	$	433	$	402	$	857	$	797

19

PLAINS EXPLORATION & PRODUCTION COMPANY

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

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 interest in Stocker Resources, Inc.) has regarding an electric services contract with Commonwealth Energy Corporation. In this lawsuit, Plains Resources is seeking a declaratory judgment that it was entitled to terminate the contract and that Commonwealth has no basis for proceeding against a related $1.5 million performance bond. In a countersuit against Plains Resources, Commonwealth is seeking unspecified damages. The two cases have been consolidated and set for trial in December 2003. We understand that Plains Resources intends to defend its rights vigorously in this matter. We do not believe that the outcome of these legal proceedings, individually or in the aggregate, will have a material adverse effect on our financial condition, results of operations or cash flows.

Note 8—Supplemental Cash Flow Information

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2003		2002		2003		2002
Cash payments for interest	$	9,468	$	—	$	741	$	—
Cash payments for taxes	$	2,203	$	—	$	2,802	$	326

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

Common stock issued	$	152,186
Current liabilities assumed		74,243
Other long-term liabilities assumed		4,394
Deferred income tax liability		40,887
	$	271,710

As restated, see Note 2.

Note 9—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.

20

PLAINS EXPLORATION & PRODUCTION COMPANY

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

CONSOLIDATING BALANCE SHEET (Unaudited)

JUNE 30, 2003

(in thousands)

	Issuer(1)			Guarantor Subsidiaries(1)			Intercompany Eliminations(1)			Consolidated(1)
ASSETS
Current Assets
Cash and cash equivalents	$	1,003		$	2,463		$	—		$	3,466
Accounts receivable and other current assets		24,650			26,847			—			51,497
Commodity hedging contracts		1,167			508			—			1,675
Inventories		6,032			1,674			—			7,706
		32,852			31,492			—			64,344
Property and Equipment, at cost
Oil and natural gas properties—full cost method
Subject to amortization		549,920			450,296			—			1,000,216
Not subject to amortization		21,746			63,522			—			85,268
Other property and equipment		2,745			420			—			3,165
		574,411			514,238			—			1,088,649
Less allowance for depreciation, depletion and amortization		(57,864	)		(97,214	)		—			(155,078	)
		516,547			417,024			—			933,571
Goodwill		—			146,301			—			146,301
Investment in and Advances to Subsidiaries		466,943			—			(466,943	)		—
Other Assets		19,207			(591	)		—			18,616
	$	1,035,549		$	594,226		$	(466,943	)	$	1,162,832
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts payable and other current liabilities		60,070		$	39,483		$	—		$	99,553
Commodity hedging contracts		16,648			23,100			—			39,748
Current maturities on long-term debt		511			—			—			511
		77,229			62,583			—			139,812
Long-Term Debt		510,502			—			—			510,502
Asset Retirement Obligation		16,307			15,104			—			31,411
Other Long-Term Liabilities		8,761			8,816			—			17,577
Payable to Parent		—			483,736			(483,736	)		—
Deferred Income Taxes		67,412			40,780			—			108,192
Stockholders’ Equity
Stockholders’ equity		370,092			(13,622	)		13,622			370,092
Accumulated other comprehensive income		(14,754	)		(3,171	)		3,171			(14,754	)
		355,338			(16,793	)		16,793			355,338
	$	1,035,549		$	594,226		$	(466,943	)	$	1,162,832

(1) As restated, see Note 2.

Table continued on following page

21

PLAINS EXPLORATION & PRODUCTION COMPANY

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

	Issuer			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
As previously reported
Oil and gas properties—subject to amortization	$	549,920		$	428,282		$	—		$	978,202
Total property and equipment		574,411			492,224			—			1,066,635
Allowance for depreciation, depletion and amortization		(57,864	)		(97,132	)		—			(154,996	)
Net property and equipment		516,546			395,092						911,639
Goodwill		—			143,962						143,962
Investment in and advances to subsidiaries		451,823			—			(451,823	)		—
Total assets		1,020,429			569,955			(451,823	)		1,138,561
Deferred income taxes		67,597			31,629			—			99,226
Stockholders’ equity		368,422			(15,300	)		15,300			368,422
Accumulated other comprehensive income		(28,389	)		(17,068	)		17,068			(28,389	)
Total stockholders’ equity		340,033			(32,368	)		32,368			340,033
Total liabilities and stockholders’ equity		1,020,429			569,955			(451,823	)		1,138,561

22

PLAINS EXPLORATION & PRODUCTION COMPANY

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

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

23

PLAINS EXPLORATION & PRODUCTION COMPANY

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

CONSOLIDATING STATEMENTS OF INCOME (Unaudited)

THREE MONTHS ENDED JUNE 30, 2003

(in thousands)

	Issuer(1)				Guarantor Subsidiaries(1)			Intercompany Eliminations(1)			Consolidated(1)
Revenues
Oil sales to Plains All American Pipeline, L.P.	$	36,968			$	17,887		$	—		$	54,855
Other oil sales		—				1,636			—			1,636
Gas sales		4,125				12,000			—			16,125
Hedging		(5,404	)			(3,554	)		—			(8,958	)
Other operating revenues		—				200			—			200
		35,689				28,169			—			63,858
Costs and Expenses
Production expenses		11,526				10,847			—			22,373
Production and ad valorem taxes		985		��		836			—			1,821
Transportation expenses		—				327			—			327
General and administrative
G&A, excluding items below		3,991				570			—			4,561
Stock appreciation rights		4,010				—			—			4,010
Merger related costs		854				—			—			854
Depreciation, depletion and amortization		5,125				5,102			—			10,227
Accretion of asset retirement obligation		363				231			—			594
		26,854				17,913			—			44,767
Income from Operations		8,835				10,256			—			19,091
Other Income (Expense)
Equity in earnings of subsidiaries		6,321				—			(6,321	)		—
Interest expense		(4,205	)			(1,133	)		—			(5,338	)
Gain on derivatives		—				1,466			—			1,466
Interest and other income (expense)		(200	)			—			—			(200	)
Before Income Taxes and Cumulative Effect Income of Accounting Change		10,751				10,589			(6,321	)		15,019
Income tax expense
Current		644				(1,892	)		—			(1,248	)
Deferred		(2,495	)			(2,376	)		—			(4,871	)
Net Income	$	8,900			$	6,321		$	(6,321	)	$	8,900
As previously reported:
Hedging		(5,391	)			(5,001	)		—			(10,392	)
Total revenues		35,702				26,722			—			62,424
Depletion, depreciation and amortization		5,125				5,020			—			10,145
Total costs and expenses		26,854				17,831			—			44,685
Income from operations		8,848				8,891			—			17,739
Gain on derivatives		—				—			—			—
Income before income taxes and cumulative effect of accounting change		9,086				7,758			(4,643	)		12,201
Income tax expense—deferred		(2,500	)			(1,223	)		—			(3,723	)
Net income		7,230				4,643			(4,643	)		7,230

(1) As restated, see Note 2.

24

PLAINS EXPLORATION & PRODUCTION COMPANY

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

CONSOLIDATING STATEMENTS OF INCOME (Unaudited)

THREE MONTHS ENDED JUNE 30, 2002

(in thousands)

	Issuer			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
Revenues
Oil sales to Plains All American Pipeline, L.P.	$	35,150		$	11,285		$	—		$	46,435
Gas sales		2,590			—			—			2,590
Hedging		(2,877	)		(1,021	)		—			(3,898	)
Other operating revenues		—			13			—			13
		34,863			10,277			—			45,140
Costs and Expenses
Production expenses		11,048			5,601			—			16,649
Production and ad valorem taxes		1,120			84			—			1,204
General and administrative		1,834			440			—			2,274
Depreciation, depletion and amortization		5,161			1,655			—			6,816
		19,163			7,780			—			26,943
Income from Operations		15,700			2,497			—			18,197
Other Income (Expense)
Equity in earnings of subsidiaries		355			—			(355	)		—
Interest expense		(2,958	)		(1,768	)		—			(4,726	)
Interest and other income		14			4			—			18
Income Before Income Taxes		13,111			733			(355	)		13,489
Income tax expense
Current		(1,521	)		(452	)		—			(1,973	)
Deferred		(3,372	)		74			—			(3,298	)
Net Income	$	8,218		$	355		$	(355	)	$	8,218

25

PLAINS EXPLORATION & PRODUCTION COMPANY

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

CONSOLIDATING STATEMENTS OF INCOME (Unaudited)

SIX MONTHS ENDED JUNE 30, 2003

(in thousands)

	Issuer(1)			Guarantor Subsidiaries(1)			Intercompany Eliminations(1)			Consolidated(1)
Revenues
Oil sales to Plains All American Pipeline, L.P.	$	79,921		$	39,672		$	—		$	119,593
Other oil sales		—			1,636			—			1,636
Gas sales		8,229			12,000			—			20,229
Hedging		(16,135	)		(10,134	)		—			(26,269	)
Other operating revenues		—			407			—			407
		72,015			43,581			—			115,596
Costs and Expenses
Production expenses		23,286			19,065			—			42,351
Production and ad valorem taxes		1,904			952			—			2,856
Transportation expenses		—			327			—			327
General and administrative
G&A, excluding items below		7,746			1,011			—			8,757
Stock appreciation rights		2,647			—			—			2,647
Merger related costs		1,097			—						1,097
Depreciation, depletion and amortization		10,934			7,016			—			17,950
Accretion of asset retirement obligation		718			458			—			1,176
		48,332			28,829			—			77,161
Income from Operations		23,683			14,752			—			38,435
Other Income (Expense)
Equity in earnings of subsidiaries		8,617			—			(8,617	)		—
Interest expense		(7,374	)		(2,820	)		—			(10,194	)
Gain on derivatives		—			1,466			—			1,466
Interest and other income (expense)		(176	)		9			—			(167	)
Income Before Income Taxes and Cumulative Effect of Accounting Change		24,750			13,407			(8,617	)		29,540
Income tax expense
Current		870			(3,299	)		—			(2,429	)
Deferred		(7,472	)		(2,136	)		—			(9,608	)
Income Before Cumulative Effect of Accounting Change		18,148			7,972			(8,617	)		17,503
Cumulative effect of accounting change, net of tax benefit		11,679			645			—			12,324
Net Income	$	29,827		$	8,617		$	(8,617	)	$	29,827
As previously reported:
Hedging	$	(16,122	)	$	(11,581	)	$	—		$	(27,703	)
Total revenues		72,028			42,134			—			114,162
Depletion, depreciation and amortization		10,934			6,934			—��			17,868
Total costs and expenses		48,332			28,747			—			77,079
Income from operations		23,696			13,387			—			37,083
Gain on derivatives		—			—			—			—
Income before income taxes and cumulative effect of accounting change		23,085			10,576			(6,939	)		26,722
Income tax expense—deferred		(7,477	)		(983	)		—			(8,460	)
Net income		28,157			6,939			(6,939	)		28,157

(1) As restated, see Note 2.

26

PLAINS EXPLORATION & PRODUCTION COMPANY

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

CONSOLIDATING STATEMENTS OF INCOME (Unaudited)

SIX MONTHS ENDED JUNE 30, 2002

(in thousands)

	Issuer			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
Revenues
Oil sales to Plains All American Pipeline, L.P.	$	60,718		$	20,958		$	—		$	81,676
Gas sales		4,578			—			—			4,578
Hedging		(698	)		244			—			(454	)
Other operating revenues		—			13			—			13
		64,598			21,215			—			85,813
Costs and Expenses
Production expenses		21,952			10,802			—			32,754
Production and ad valorem taxes		2,197			131			—			2,328
General and administrative		3,945			781			—			4,726
Depreciation, depletion and amortization		9,985			3,522			—			13,507
		38,079			15,236			—			53,315
Income from Operations		26,519			5,979			—			32,498
Other Income (Expense)
Equity in earnings of subsidiaries		1,590			—			(1,590	)		—
Interest expense		(6,003	)		(3,415	)		—			(9,418	)
Interest and other income		23			13			—			36
Income Before Income Taxes		22,129			2,577			(1,590	)		23,116
Income tax expense
Current		(2,886	)		(1,132	)		—			(4,018	)
Deferred		(5,161	)		145			—			(5,016	)
Net Income	$	14,082		$	1,590		$	(1,590	)	$	14,082

27

PLAINS EXPLORATION & PRODUCTION COMPANY

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

CONSOLIDATING STATEMENTS OF CASH FLOWS (Unaudited)

SIX MONTHS ENDED JUNE 30, 2003

(in thousands of dollars)

	Issuer(1)			Guarantor Subsidiaries(1)			Intercompany Eliminations(1)			Consolidated(1)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	29,827		$	8,617		$	(8,617	)	$	29,827
Items not affecting cash flows from operating activities
Depreciation, depletion and amortization		10,934			7,016			—			17,950
Accretion of asset retirement obligation		718			458			—			1,176
Gain on derivatives		—			(1,466	)		—			(1,466	)
Equity in earnings of subsidiaries		(8,617	)		—			8,617			—
Deferred income taxes		7,472			2,136			—			9,608
Cumulative effect of adoption of accounting change		(11,679	)		(645	)		—			(12,324	)
Noncash compensation		2,685			—			—			2,685
Other noncash items		377			—			—			377
Change in assets and liabilities from operating activities
Accounts receivable and other assets		(693	)		3,740			—			3,047
Inventories		(2,024	)		(273	)		—			(2,297	)
Accounts payable and other liabilities		9,363			(15,298	)		—			(5,935	)
Net cash provided by (used in) operating activities		38,363			4,285			—			42,648
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to oil and gas properties		(37,275	)		(9,505	)		—			(46,780	)
Acquisition of 3TEC Energy Corporation, net of cash acquired		—			(266,617	)		—			(266,617	)
Other		(737	)		(3	)		—			(740	)
Net cash used in investing activities		(38,012	)		(276,125	)		—			(314,137	)
CASH FLOWS FROM FINANCING ACTIVITIES
Change in revolving credit facility		197,200			—			—			197,200
Proceeds from debt issuance		80,061			—			—			80,061
Debt issuance costs		(4,069	)		—			—			(4,069	)
Advances/investments with affiliates		(274,279	)		274,279			—			—
Receipts from (payments to) Plains Resources Inc.		510			—			—			510
Other		225			—			—			225
Net cash provided by (used in) financing activities		(352	)		274,279			—			273,927
Net increase (decrease) in cash and cash equivalents		(1	)		2,439			—			2,438
Cash and cash equivalents, beginning of period		1,004			24			—			1,028
Cash and cash equivalents, end of period	$	1,003		$	2,463		$	—		$	3,466
As previously reported:
Cash Flows from Operating Activities
Net income	$	28,157		$	6,939		$	(6,939	)	$	28,157
Items from affecting cash flows from operating activities
Depreciation, depletion and amortization		10,934			6,934			—			17,868
Gain on derivatives		—			—			—			—
Equity in earnings of subsidiaries		(6,939	)		—			6,939			—
Deferred income taxes		7,478			982			—			8,460
Change in assets and liabilities from operating activities
Accounts payable and other liabilities		9,350			(28,585	)		—			(19,235	)
Net cash provided by (used in) operating activities		38,364			(10,450	)		—			27,914
Cash Flows from Investing Activities
Acquisition of 3TEC Energy Corporation, net of cash acquired		—			(251,883	)		—			(251,883	)
Net cash used in investing activities		(38,012	)		(261,391	)		—			(299,403	)

(1) As restated, see Note 2.

28

PLAINS EXPLORATION & PRODUCTION COMPANY

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

CONSOLIDATING STATEMENTS OF CASH FLOWS (Unaudited)

SIX MONTHS ENDED JUNE 30, 2002

(in thousands of dollars)

	Issuer			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	14,082		$	1,590		$	(1,590	)	$	14,082
Items not affecting cash flows from operating activities
Depreciation, depletion and amortization		9,985			3,522			—			13,507
Equity in earnings of subsidiaries		(1,590	)		—			1,590			—
Deferred income taxes		5,161			(145	)		—			5,016
Other noncash items		277			47						324
Change in assets and liabilities from operating activities
Accounts receivable and other assets		(5,833	)		2,994			—			(2,839	)
Inventories		(244	)		(140	)		—			(384	)
Accounts payable and other liabilities		(2,990	)		(6,940	)		—			(9,930	)
Net cash provided by operating activities		18,848			928			—			19,776
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to oil and gas properties		(34,902	)		(7,439	)		—			(42,341	)
Additions to other property and equipment		(15	)		(2	)		—			(17	)
Net cash used in investing activities		(34,917	)		(7,441	)		—			(42,358	)
CASH FLOWS FROM FINANCING ACTIVITIES
Receipts from Plains Resources Inc.		16,058			6,518			—			22,576
Net cash provided by financing activities		16,058			6,518			—			22,576
Net increase (decrease) in cash and cash equivalents		(11	)		5			—			(6	)
Cash and cash equivalents, beginning of period		11			2			—			13
Cash and cash equivalents, end of period	$	—		$	7		$	—		$	7

29

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 with effect from June 1, 2003.

General

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

• onshore California, primarily in the LA Basin;

• offshore California in the Point Arguello unit;

• East Texas;

• the Gulf Coast; and

• the Illinois Basin in southern Illinois and Indiana.

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

30

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

To manage our exposure to commodity price risks, we use various derivative instruments to hedge our exposure to oil and gas sales price fluctuations. Our hedging arrangements provide us protection on the hedged volumes if oil 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. We estimate that as a result of our reorganization and spin-off, our annual general and administrative expenses will increase by approximately $4.1 million over the amount reported for the year ended December 31, 2002 (excluding expense related to stock appreciation rights, spin-off costs and the effect of acquiring 3TEC) reflecting the incremental costs of operating as a separate, publicly held company.

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

31

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 June 30,						Six Months Ended June 30,
	2003(1)(2)			2002			2003(1)(2)			2002
Total Period Production
Oil and Liquids (MBbls)		2,287			2,080			4,468			4,113
Gas (MMcf)		2,745			842			3,474			1,719
MBOE		2,745			2,220			5,047			4,400
Average Daily Production
Oil and Liquids (Bbls)		25,132			22,857			24,685			22,724
Gas (Mcf)		30,165			9,253			19,193			9,497
BOE		30,160			24,399			27,884			24,307
Unit Economics (in dollars)
Average Oil & Liquids Sales Price ($/Bbl)
Average NYMEX	$	28.91		$	26.27		$	31.32		$	24.02
Hedging revenue (expense)		(3.92	)		(1.87	)		(5.88	)		(0.11	)
Differential		(4.21	)		(3.95	)		(4.18	)		(4.16	)
Net realized price	$	20.78		$	20.45		$	21.26		$	19.75
Average Gas Sales Price ($/Mcf)
Average NYMEX	$	5.57		$	3.41		$	5.63		$	2.93
Hedging revenue (expense)		—			—			—			—
Differential		0.31			(0.33	)		0.20			(0.27	)
Net realized price	$	5.88		$	3.08		$	5.83		$	2.66
Average realized price per BOE	$	23.19		$	20.33		$	22.82		$	19.50
Production expenses per BOE		(8.15	)		(7.50	)		(8.39	)		(7.44	)
Production and ad valorem taxes per BOE		(0.66	)		(0.54	)		(0.57	)		(0.53	)
Gathering and transportation per BOE		(0.12	)		—			(0.06	)		—
Gross margin per BOE		14.26			12.29			13.80			11.53
G&A per BOE
G&A excluding items below		(1.66	)		(1.02	)		(1.74	)		(1.07	)
Stock appreciation rights		(1.46	)		—			(0.52	)		—
Merger related costs		(0.31	)		—			(0.22	)		—
Gross profit per BOE	$	10.83		$	11.27		$	11.32		$	10.46

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

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

Comparison of Three Months Ended June 30, 2003 to Three Months Ended June 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 second quarter 2003 net income of $8.9 million, or $0.31 per diluted share compared to net income of $8.2 million, or $0.34 per diluted share for the second quarter of 2002. Net income in the second quarter of 2003 includes the effect of the properties acquired in the acquisition of 3TEC, or the 3TEC properties, as of June 1, 2003.

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Oil and gas revenues.    Our oil and gas revenues, excluding the effect of hedging and the 3TEC properties, increased 21%, or $10.2 million, to $59.2 million for the second quarter of 2003 from $49.0 million for the second quarter of 2002. The increase was primarily due to increased sales prices that increased revenues by $6.9 million and higher volumes that increased revenues by $3.3 million. Oil and gas revenues from the 3TEC properties totaled $13.6 million in the second quarter of 2003. Hedging had the effect of decreasing our oil and gas revenues by $9.0 million in 2003 compared to $3.9 million in 2002.

Our average realized price for oil increased 2%, or $0.33, to $20.78 per Bbl for the second quarter of 2003 from $20.45 per Bbl for the second quarter of 2002. The increase is primarily attributable to an improvement in the NYMEX oil price, which averaged $28.91 per Bbl in 2003 versus $26.27 per Bbl in 2002. The average differential for location and quality increased to $4.21 per Bbl in 2003 compared to $3.95 per Bbl in 2002. Hedging had the effect of decreasing our average price per Bbl by $3.92 in 2003 compared to $1.87 per Bbl in 2002.

Our average realized price for gas increased 91%, or $3.08, to $5.88 per Mcf for the second quarter of 2003 from $3.08 per Mcf for the second quarter of 2002. The increase is primarily attributable to an improvement in the NYMEX average price, which averaged $5.57 in 2003 versus $3.41 in 2002. Our average differential improved by $0.64 per Mcf from the 2002 period.

Production expenses.    Our production expenses increased 35%, or $5.8 million, to $22.4 million for the second quarter of 2003 from $16.6 million for the second quarter of 2002, primarily from our increased ownership percentage in the offshore California properties and the acquisition of the 3TEC properties. The 3TEC properties accounted for $1.4 million of our 2003 production expenses. On a per unit basis, production expenses increased 9%, or $0.65 per BOE, to $8.15 per BOE for the second quarter of 2003 from $7.50 per BOE for the second quarter of 2002, primarily due to our increased ownership percentage in the offshore California properties which have a higher per unit production cost than our other properties, as well as higher fuel and electricity costs. Unit production expenses for the offshore California properties will continue to increase as production declines due to the large component of fixed expenses for this asset.

Production and ad valorem taxes.    Our production and ad valorem taxes increased 50%, or $0.6 million, to $1.8 million for the second quarter of 2003 from $1.2 million for the second quarter of 2002. Production and ad valorem taxes attributable to the 3TEC properties totaled $0.7 million in the second quarter of 2003.

Gathering and transportation expenses.    Gathering and transportation expense, which totaled $0.3 million in 2003, represents costs incurred to deliver oil and gas produced from certain of the 3TEC properties to the sales point.

General and administrative expense.    Our general and administrative, or G&A, expense, excluding amounts attributable to stock appreciation rights, or SARs, and certain merger-related costs, increased 100%, or $2.3 million, to $4.6 million for the second quarter of 2003 from $2.3 million for the second quarter of 2002. As a result of our reorganization and spin-off our G&A expenses have increased, reflecting the incremental costs of operating as a separate, publicly held company.

G&A expense for 2003 includes a non-cash charge of $4.0 million related to outstanding SARs. Accounting for SARs requires that we record an expense or credit to the income statement depending on whether, during the period, our stock price either rose or fell, respectively. Accordingly, since our stock price at June 30, 2003 was $10.81 as compared to $8.25 on March 31, 2003 we recorded a non-cash expense. Second quarter of 2003 G&A expense included $0.9 million related to the merger.

G&A expense does not include amounts capitalized as part of our acquisition, exploration and development activities. We capitalized $2.5 million and $1.3 million of G&A expense in the second quarter of 2003 and 2002, respectively.

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Depreciation, depletion and amortization, or DD&A.    Our DD&A expense increased 50%, or $3.4 million, to $10.2 million for the second quarter of 2003 from $6.8 million for the second quarter of 2002 due to a higher per unit rate and higher production. Approximately $3.0 million of the increase was attributable to our oil and gas DD&A. Our oil and gas unit of production rate increased to $4.04 per BOE for the period subsequent to the merger as compared to $3.18 per BOE prior to the merger. In the second quarter of 2002 our rate was $3.04 per BOE. DD&A attributable to production from the 3TEC properties totaled $1.7 million in the second quarter of 2003. Other DD&A expense increased approximately $0.4 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 second quarter of 2003 was $0.6 million. Accretion expense represents the adjustment of our asset retirement obligation to its present value at the end of the period based on our credit adjusted risk free rate.

Interest expense.    Our interest expense increased 13%, or $0.6 million, to $5.3 million for the second quarter of 2003 from $4.7 million for 2002 due to higher outstanding debt as a result of the merger. We capitalized approximately $0.5 million and $0.7 million of interest in the second quarter of 2003 and 2002, respectively.

Gain on derivatives.    We have a derivative gas collar that does not qualify for hedge accounting. In the second quarter of 2003 we recognized a $1.4 million fair value gain on the gas collar.

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

Income tax expense.    Our income tax expense increased 15%, or $0.8 million, to $6.1 million for the second quarter of 2003 from $5.3 million for the second quarter of 2002 primarily due to higher pre-tax income. Our overall effective tax rate increased slightly to 40.7% in 2003 from 39.1% in 2002. Our currently payable effective tax rate was 8.3% for 2003 as compared to 14.6% 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.

Comparison of Six Months Ended June 30, 2003 to Six Months Ended June 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 six months 2003 net income of $29.8 million, or $1.12 per diluted share compared to net income of $14.1 million, or $0.58 per diluted share for the first six months of 2002. Net income in the first six months of 2003 includes the effect of the properties acquired in the 3TEC acquisition as of June 1, 2003 and an after-tax $12.3 million credit related to the adoption of Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations”.

Oil and gas revenues.    Our oil and gas revenues, excluding the effect of hedging and the 3TEC properties, increased 48%, or $41.8 million, to $128.1 million for the first six months of 2003 from $86.3 million for the first six months of 2002. The increase was primarily due to increased sales prices that increased revenues by $34.8 million and higher volumes that increased revenues by $7.0 million. Oil and gas revenues from the 3TEC properties totaled $13.6 million in the first six months of 2003. Hedging had the effect of decreasing our oil and gas revenues by $26.3 million in 2003 compared to $0.5 million in 2002.

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

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Our average realized price for gas increased 119%, or $3.17, to $5.83 per Mcf for the six months of 2003 from $2.66 per Mcf for the year earlier period. The increase is primarily attributable to an improvement in the NYMEX average price, which averaged $5.63 in 2003 versus $2.93 in 2002. Our average differential improved $0.47 per Mcf from the year earlier period.

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

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

Gathering and transportation expenses.    Gathering and transportation expense, which totaled $0.3 million in 2003, represents costs incurred to deliver oil and gas produced from certain of the 3TEC properties to the sales point.

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

G&A expense for 2003 includes a non-cash charge of $2.6 million related to outstanding SARs. Accounting for SARs requires that we record an expense or credit to the income statement depending on whether, during the period, our stock price either rose or fell, respectively. Accordingly, since our stock price at June 30, 2003 was $10.81 as compared to $9.75 on December 31, 2002 we recorded a non-cash expense. G&A expense for the first six months of 2003 includes $1.1 million related to the merger.

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

Depreciation, depletion and amortization, or DD&A.    Our DD&A expense increased 33%, or $4.5 million, to $18.0 million for the first six months of 2003 from $13.5 million for the first six months of 2002. Approximately $3.7 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 $3.18 per BOE prior to the merger. In the first six months of 2002 our rate was $3.38 per BOE. DD&A attributable to production from the 3TEC properties totaled $1.7 million in the first six months of 2003. Other DD&A expense increased approximately $0.8 million, primarily from amortization of debt issue costs related to our senior subordinated debt and our revolving credit facility.

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

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

Gain on derivatives.    We have a derivative gas collar that does not qualify for hedge accounting. In the first six months of 2003 we recognized a $1.4 million fair value gain on the gas collar.

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

Income tax expense.    Our income tax expense increased 33%, or $3.0 million, to $12.0 million for the first six months of 2003 from $9.0 million for the first six months of 2002. Our overall effective tax rate increased to 40.8% in 2003 from 39.1% in 2002. Our currently payable effective tax rate was 8.2% for 2003 as compared to 17.4% for 2002. The decreased currently payable effective rate in 2003 primarily reflects the treatment for tax purposes of certain items that are capitalized for financial reporting purposes. Tax expense and effective tax rates for the periods prior to our spin-off on December 18, 2002 were calculated based on the tax sharing agreement with Plains Resources.

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

Pro Forma Financial Information

The following unaudited pro forma information for the three and six months ended June 30, 2003 and 2002 has been prepared based on our historical consolidated statements of income and the historical consolidated statements of income of 3TEC. Such pro forma information for 2003 and 2002 assumes the merger and the issuance of $75.0 million of 8.75% senior subordinated notes on May 31, 2003 occurred on January 1, 2003 and January 1,2002, 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 to the consolidated financial statements; and (ii) the July 3, 2002 issuance of $200.0 million of 8.75% senior subordinated notes, discussed in Note 5 to the consolidated financial statements.

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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 June 30,				Six Months Ended June 30,
	2003(1)		2002(1)		2003(1)		2002(1)
	(in thousands, except per share data)
Revenues	$	89,124	$	73,082	$	189,191	$	132,212
Income from operations		32,315		29,313		82,332		47,301
Income before the cumulative effect of accounting change		146		17,156		19,145		16,124
Net income		146		17,156		31,469		16,124
Earnings per share
Basic
Before cumulative effect of accounting change	$	—	$	0.43	$	0.48	$	0.40
Cumulative effect of accounting change		—		—		0.31		—
Net income		—		0.43		0.79		0.40
Diluted
Before cumulative effect of accounting change	$	—	$	0.43	$	0.47	$	0.40
Cumulative effect of accounting change		—				0.31		—
Net income		—		0.43		0.78		0.40
Weighted average shares outstanding
Basic		40,089		40,263		40,087		40,263
Diluted		40,413		40,271		40,355		40,271

(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 ($23.0) million and ($22.4) million for the three months and six months ended June 30, 2003, respectively, and $9.0 million and ($12.4) million for the three months and six months ended June 30, 2002, respectively. At the time of the merger such derivative instruments were assigned to us and in accordance with the provisions of SFAS 133 all such derivative instruments, except for one gas collar, were qualified for hedge accounting. If such qualifying derivative instruments had been qualified for hedge accounting by 3TEC proforma net income would have been $41.5 million ($1.03 per diluted share) for the six months ended June 30, 2003 and $23.9 million ($0.59 per diluted share) for the six months ended June 30, 2002.

Liquidity and Capital Resources

Our primary sources of liquidity are cash generated from our operations and our revolving credit facility. At June 30, 2003 we had $164.3 million of availability under our 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 June 30, 2003 we had a working capital deficit of $75.5 million. The working capital deficit includes $38.1 million attributable to the fair value of our hedges, $9.3 million attributable to accrued interest on our 8.75% notes and $3.8 million that reflects the in-the-money value of stock appreciation rights that were deemed

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

On April 14, 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 June 30, 2003, we were in compliance with the covenants contained in our credit facility and could have borrowed the full amount available under the credit facility.

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.

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

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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

	Six Months Ended June 30,
	2003(1)			2002
	(in millions)
Cash provided by (used in):
Operating activities	$	42.6		$	19.8
Investing activities		(314.1	)		(42.4	)
Financing activities		273.9			22.6

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

Net cash provided by operating activities was $42.6 million and $19.8 million for the first six months of 2003 and 2002, respectively. The increase primarily reflects higher revenues, partially offset by higher production costs.

Net cash used in investing activities was $299.4 million in the first six months of 2003 and $42.4 million in the first six months of 2002. Such amount for 2003 includes $251.9 million related to the merger. Costs incurred in connection with our oil and gas acquisition, development and exploration activities totaled $46.8 million in 2003 compared to $42.3 million in 2002.

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

Capital Requirements

We have made and will continue to make substantial capital expenditures for the acquisition, exploitation, development and exploration of oil and gas. During 2003, we expect to make aggregate capital expenditures of approximately $112 to $119 million on our existing asset base, 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 share count will not increase. At June 30, 2003 we had approximately 3.7 million SARs outstanding of which 1.5 million were vested. If all of the vested SARs were exercised, based on $10.81, the price of our common stock as of June 30, 2003, we would pay $3.5 million to holders of the SARs.

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Commitments and Contingencies

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

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

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

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

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

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 interest in Stocker Resources, Inc.) has regarding an electric services contract with Commonwealth Energy Corporation. In this lawsuit, Plains Resources is seeking a declaratory judgment that it was entitled to terminate the contract and that Commonwealth has no basis for proceeding against a related $1.5 million performance bond. In a counter suit against Plains Resources, Commonwealth is seeking unspecified damages. The two cases have been consolidated and set for trial in December 2003. We understand that Plains Resources intends to defend its rights vigorously in this matter. We do not believe that the outcome of these legal proceedings, individually or in the aggregate, will have a material adverse effect on our financial condition, results of operations or cash flows.

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 $146.3 million and represents 13% of our total assets at June 30, 2003.

Goodwill is not amortized, but instead must be tested at least annually for impairment by applying a fair-value based test. Goodwill is deemed impaired to the extent of any excess of its carrying amount over the residual fair value of the reporting unit. Such impairment could significantly reduce earnings during the period in which the impairment occurs and would result in a corresponding reduction to goodwill and stockholders’ equity.

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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 will have no effect on either our financial position or results of operations.

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

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;

• 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;

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• 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 June 30, 2003, OCI consisted of $24.5 million ($14.5 million net of tax) of unrealized losses on our oil and gas hedging instruments, $0.3 million ($0.2 million, net of tax) loss related to our interest rate swap and $0.1 million ($0.1 million, net of tax) related to pension liabilities. The assets and liabilities related to all of our open commodity derivative instruments were included in current assets ($1.7 million), other assets ($0.7 million), current liabilities ($39.5 million), other long-term liabilities ($10.4 million) and deferred income taxes (a tax benefit of $10.0 million).

During the three and six months ended June 30, 2003, $9.0 million ($5.3 million net of tax) and $26.3 million ($15.6 million net of tax) in losses from the settlement of oil and gas hedging instruments were reclassified from OCI and charged to income as a reduction of oil and gas revenues. As of June 30, 2003, $18.9 million ($11.2 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. In addition, during the three and six months ended June 30, 2003, $1.4 million 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 in each of the periods.

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At July 31, 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)	—	20,000	—
Floor price of $4.00 per MMBtu
Cap price of $5.15 per MMBtu

(1) Does not qualify for hedge accounting

Assuming second quarter 2003 production volumes (on a pro forma basis to include the 3TEC properties for the entire quarter) are held constant in subsequent periods, these positions result in us hedging approximately 76%, 69% and 28% of oil production in 2003, 2004 and 2005, respectively, and approximately 66% and 53% of gas production in 2003 and 2004, respectively. Location and quality differentials attributable to our properties are not included in the foregoing prices. Because of the quality and location of our production, these adjustments will 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 sales revenues. These contracts resulted in a decrease in revenues of $27.7 million, and $0.5 million for the first six months of 2003 and 2002, respectively.

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

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 41% of the fair value of all open positions as of June 30, 2003. No one counterparty holds contracts that represent more than 19% of the fair value of all open positions as of June 30, 2003.

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):

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

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The fair value of the swaps and option contracts are estimated based on quoted prices from independent reporting services compared to the contract price of the swap and approximate the gain or loss that would have been realized if the contracts had been closed out at of June 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

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 and 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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