PLAINS EXPLORATION & PRODUCTION CO - 10-Q Quarterly Report

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-Q

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

SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2003

¨ 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. Yes þ No ¨

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

24,225,075 shares of Common Stock, $0.01 par value, issued and outstanding at April 30, 2003.

PLAINS EXPLORATION & PRODUCTION COMPANY

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

PART I. FINANCIAL INFORMATION

ITEM 1. Financial Statements:

Consolidated Balance Sheets
March 31, 2003 (Unaudited) and December 31, 2002		1
Consolidated Statements of Income (Unaudited)
For the three months ended March 31, 2003 and 2002		2
Consolidated Statements of Cash Flows (Unaudited)
For the three months ended March 31, 2003 and 2002		3
Consolidated Statements of Comprehensive Income (Unaudited)
For the three months ended March 31, 2003 and 2002		4
Consolidated Statement of Changes in Stockholders' Equity (Unaudited)
For the three months ended March 31, 2003		5
Notes to Consolidated Financial Statements (Unaudited)		6

ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		19

ITEM 3. Quantitative and Qualitative Disclosures About Market Risk		29

ITEM 4. Controls and Procedures		31

PART II. OTHER INFORMATION		32

PLAINS EXPLORATION & PRODUCTION COMPANY

CONSOLIDATED BALANCE SHEETS (Unaudited)

(in thousands of dollars)

	March 31, 2003			December 31, 2002
ASSETS
Current Assets
Cash and cash equivalents	$	1,002		$	1,028
Accounts receivable—Plains All American Pipeline, L.P.		25,722			22,943
Other accounts receivable		3,545			5,925
Commodity hedging contracts		1,623			2,594
Inventories		5,993			5,198
Other current assets		1,133			1,051

		39,018			38,739

Property and Equipment, at cost
Oil and natural gas properties—full cost method
Subject to amortization		661,769			629,454
Not subject to amortization		30,779			30,045
Other property and equipment		2,286			2,207

		694,834			661,706
Less allowance for depreciation, depletion and amortization		(145,174	)		(168,494	)

		549,660			493,212

Other Assets		19,047			18,929

	$	607,725		$	550,880

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts payable and other current liabilities	$	44,815		$	40,012
Commodity hedging contracts		24,012			24,572
Royalties payable		13,187			11,873
Interest payable		4,780			9,207
Current maturities of long-term debt		511			511

		87,305			86,175

Long-Term Debt
8.75% senior subordinated notes		196,908			196,855
Revolving credit facility		32,500			35,800
Other		511			511

		229,919			233,166

Asset Retirement Obligation		26,240			—

Other Long-Term Liabilities		9,464			6,303

Deferred Income Taxes		61,932			51,416

Commitments and Contingencies (Note 6)
Stockholders’ Equity
Common stock		244			244
Additional paid-in capital		175,025			174,279
Retained earnings		33,082			12,155
Accumulated other comprehensive income		(15,486	)		(12,858	)

		192,865			173,820

	$	607,725		$	550,880

See notes to consolidated financial statements.

PLAINS EXPLORATION & PRODUCTION COMPANY

CONSOLIDATED STATEMENTS OF INCOME (Unaudited)

(in thousands, except per share data)

	Three Months Ended March 31,
	2003			2002
Revenues
Oil sales to Plains All American Pipeline, L.P.	$	64,738		$	35,241
Oil hedging		(17,311	)		3,444
Gas sales		4,104			1,988
Other operating revenues		207			—

		51,738			40,673

Costs and Expenses
Production expenses		19,978			16,105
Production and ad valorem taxes		1,035			1,124
General and administrative
Stock appreciation rights		(1,363	)		—
Other		4,439			2,452
Depreciation, depletion and amortization		7,723			6,691
Accretion of asset retirement obligation		582			—

		32,394			26,372

Income from Operations		19,344			14,301
Other Income (Expense)
Interest expense		(4,856	)		(4,692	)
Interest and other income		33			18

Income Before Income Taxes and Cumulative Effect of Accounting Change		14,521			9,627
Income tax expense
Current		(1,181	)		(2,045	)
Deferred		(4,737	)		(1,718	)

Income Before Cumulative Effect of Accounting Change		8,603			5,864
Cumulative effect of accounting change, net of tax		12,324			—

Net Income	$	20,927		$	5,864

Earnings Per Share (in dollars)
Basic
Income before cumulative effect of accounting change	$	0.36		$	0.24
Cumulative effect of accounting change		0.51			—

	$	0.87		$	0.24

Diluted
Income before cumulative effect of accounting change	$	0.35		$	0.24
Cumulative effect of accounting change		0.51			—

	$	0.86		$	0.24

Weighted Average Shares Outstanding
Basic		24,015			24,200
Diluted		24,225			24,200

See notes to consolidated financial statements.

PLAINS EXPLORATION & PRODUCTION COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(in thousands of dollars)

	Three Months Ended March 31,
	2003			2002
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	20,927		$	5,864
Items not affecting cash flows from operating activities
Depreciation, depletion and amortization		7,723			6,691
Accretion of asset retirement obligation		582			—
Deferred income taxes		4,737			1,718
Cumulative effect of adoption of accounting change		(12,324	)		—
Noncash compensation		(1,632	)		—
Other noncash items		59			—
Change in assets and liabilities from operating activities
Accounts receivable and other assets		344			(356	)
Inventories		(795	)		(591	)
Accounts payable and other liabilities		(1,594	)		(3,788	)

Net cash provided by operating activities		18,027			9,538

CASH FLOWS FROM INVESTING ACTIVITIES
Additions to oil and gas properties		(12,768	)		(23,941	)
Other		(2,372	)		(20	)

Net cash used in investing activities		(15,140	)		(23,961	)

CASH FLOWS FROM FINANCING ACTIVITIES
Change in revolving credit facility		(3,300	)		—
Debt issuance costs		(123	)		—
Receipts from Plains Resources Inc.		—			14,411
Contribution from Plains Resources Inc.		510			—

Net cash provided by (used in) financing activities		(2,913	)		14,411

Net increase (decrease) in cash and cash equivalents		(26	)		(12	)
Cash and cash equivalents, beginning of period		1,028			13

Cash and cash equivalents, end of period	$	1,002		$	1

See notes to consolidated financial statements.

PLAINS EXPLORATION & PRODUCTION COMPANY

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited)

(in thousands of dollars)

	Three Months Ended March 31,
	2003			2002
Net Income	$	20,927		$	5,864

Other Comprehensive Income (Loss)
Commodity hedging contracts
Change in fair value		(12,891	)		(21,007	)
Reclassification adjustment for settled contracts		10,257			(2,171	)
Interest rate swap		6			—

		(2,628	)		(23,178	)

Comprehensive Income (Loss)	$	18,299		$	(17,314	)

See notes to consolidated financial statements.

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		Accumulated Other Comprehensive Income
	Shares	Amount		Additional Paid-in Capital		Contribution Receivable			Retained Earnings		Accumulated Other Comprehensive Income			Total
Balance at December 31, 2002	24,224		244		174,789		(510	)		12,155		(12,858	)		173,820
Net income	—		—		—		—			20,927		—			20,927
Contributions by
Plains Resources Inc.	—		—		—		510			—		—			510
Issuance of common stock	1		—		6		—			—		—			6
Restricted stock awards
Deferred compensation	—		—		230		—			—		—			230
Other comprehensive income	—		—		—		—			—		(2,628	)		(2,628	)

Balance at March 31, 2003	24,225	$	244	$	175,025	$	—		$	33,082	$	(15,486	)	$	192,865

See notes to consolidated financial statements.

PLAINS EXPLORATION & PRODUCTION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

Note 1—Organization and Significant Accounting Policies

Organization

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

Under the terms of a Master Separation Agreement between us and Plains Resources Inc. (“Plains Resources”), on July 3, 2002 Plains Resources contributed to us: (i) 100% of the capital stock of its wholly-owned subsidiaries that own oil and gas properties offshore California and in Illinois; and (ii) all amounts payable to it by us and our subsidiary companies (the “reorganization”). 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.

These financial statements include allocations of direct and indirect corporate and administrative costs of Plains Resources made prior to the reorganization. The methods by which such costs were estimated and allocated to us were deemed reasonable by Plains Resources’ management; however, such allocations and estimates are not necessarily indicative of the costs and expenses that would have been incurred had we operated as a separate entity. Allocations of such costs are considered to be related party transactions and are discussed in Note 5.

These consolidated financial statements and related notes present our consolidated financial position as of March 31,2003 and December 31, 2002, the results of our operations, our cash flows and our comprehensive income for the three months ended March 31, 2003 and 2002 and the changes in our stockholders’ equity for the three months ended March 31, 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 months ended March 31, 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 regarding interim financial reporting. Accordingly, they do not include all of the information and notes required by accounting principles generally accepted in the United States of America for complete financial statements and should be read in conjunction with the audited consolidated financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2002.

Accounting Policies

Asset Retirement Obligations. Effective January 1, 2003 we adopted Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations” (“SFAS 143”). SFAS 143 requires entities to record the fair value of a liability for a legal obligation to retire an asset in the period in which the liability is incurred. A legal obligation is a liability that a party is required to settle as a result of an existing or enacted law, statute, ordinance or contract. When the liability is initially recorded, the entity should capitalize the retirement cost of the related long-lived asset. Each period the liability is accreted to its then present value, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized. In prior periods we included estimated future costs of abandonment and dismantlement in our full cost amortization base and these costs were amortized as a component of our depletion expense.

At January 1, 2003 the present value of our future Asset Retirement Obligation for oil and gas properties and equipment was $26.5 million. The cumulative effect of our adoption of SFAS No. 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. There will be no impact on our cash flows as a result of adopting SFAS No. 143.

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

	Three Months Ended March 31,
	2003			2002
				Pro forma
Asset retirement obligation—beginning of period	$	26,540		$	21,278
Accretion expense		582			466

Asset retirement obligation—end of period	$	27,122	(1)	$	21,744

(1) $882,000 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 months ended March 31, 2002 (thousands of dollars, except per share data):

		Three Months Ended March 31, 2002
Net income—as reported		$5,864
Adjustment for effect of change in accounting that is retroactively applied, net of tax		244

Pro forma net income		$6,108

Earnings per share:
Basic—as reported		$ 0.24
Adjustment for effect of change in accounting that is retroactively applied, net of tax		0.01

Basic—pro forma		$ 0.25

Diluted—as reported		$ 0.24
Adjustment for effect of change in accounting that is retroactively applied, net of tax		0.01

Diluted—pro forma		$ 0.25

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 first quarter of 2002. The weighted average shares outstanding for computing both basic and diluted earnings per share was 24,200,000 shares for the first quarter of 2002. For the first quarter of 2003, weighted average shares outstanding for computing basic and diluted earnings per share were 24,015,000 and 24,225,000, respectively. The weighted average shares outstanding for computing diluted earnings per share include 210,000 restricted shares that have not vested. In computing EPS, no adjustments were made to reported net income.

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

	March 31, 2003		December 31, 2002
Oil	$	777	$	730
Materials and supplies		5,216		4,468

	$	5,993	$	5,198

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

	March 31, 2003		December 31, 2002
Land	$	8,853	$	8,853
Commodity hedging contracts		203		1,432
Debt issue costs, net		5,306		5,485
Other		4,685		3,159

	$	19,047	$	18,929

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” on April 30, 2003. The statement is effective for contracts entered into or modified after June 30, 2003 and for hedging relationships designated after June 30, 2003. At this time, we cannot reasonably estimate the effect of the adoption of SFAS No. 149 on either our financial position or results of operations.

Note 2—Proposed Merger

On February 3, 2003 we announced that we entered into a definitive agreement pursuant to which we will acquire 3TEC Energy Corporation (“3TEC”) (the “merger”), for approximately $340.0 million including merger related costs (based on $9.47 per PXP common share, the average closing price of our common stock during the five business day period commencing two business days before the merger was announced) plus the assumption of debt, which totaled $106.0 million at March 31, 2003. Under the terms of the merger agreement, 3TEC common stockholders will receive $8.50 of cash and 0.85 of a share of our common stock for each share of 3TEC common stock they own. This exchange ratio is subject to an upward or downward adjustment should the market price of our common stock fall below $7.65 per share or rise above $12.35 per share, respectively. This mechanism is intended to provide that the total value of the consideration received by 3TEC common stockholders at the effective time of the merger will be between $15.00 and $19.00 per share of 3TEC common stock. For this purpose, the market price of our common stock will be the average closing price of our common stock for the 20 consecutive trading days immediately preceding the third trading day prior to closing. In addition, if the market price of our common stock is less than $6.25, we may either (i) terminate the merger agreement or (ii) in lieu of issuing more common stock increase the cash consideration paid per share of 3TEC common stock by the amount our common stock market price is less than $6.25 times the exchange ratio after adjustment.

The merger is expected to qualify as a tax free reorganization under Section 368(a) of the Internal Revenue Code. Accordingly, the merger is expected to be tax free to our stockholders and tax free for the stock portion of the consideration received by 3TEC stockholders.

The Boards of Directors of both companies have approved the merger agreement and each has recommended it to their respective stockholders for approval. The transaction is subject to stockholder approval from both companies and other customary conditions. Assuming the market price of our common stock is between $7.65 and $12.35, after the merger is completed, 3TEC common stockholders will own approximately 40% of the combined company and our stockholders will own approximately 60% of the combined company.

We have entered into a new credit facility (see Note 4) that will be used to fund the cash portion of the merger.

Note 3—Derivative Instruments and Hedging Activities

We have entered into various derivative instruments to reduce our exposure to fluctuations in the market price of oil. The derivative instruments consist primarily of oil 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 and SFAS 138 (“SFAS 133”). All derivative instruments are recorded on the balance sheet at fair value. If the derivative does not qualify as a hedge or is not designated as a hedge, the gain or loss on the derivative is recognized currently in earnings. If the derivative qualifies for hedge accounting, the unrealized gain or loss on the derivative is deferred in Accumulated Other Comprehensive Income (“OCI”), a component of Stockholder’s Equity. At March 31, 2003 all open positions qualified for hedge accounting.

Unrealized gains and losses on hedging instruments reflected in OCI, and adjustments to carrying amounts on hedged volumes, are included in oil and gas revenues in the period that the related volumes are delivered. Gains and losses of hedging instruments that represent hedge ineffectiveness, as well as any amounts excluded from the assessment of hedge effectiveness, are recognized currently in oil and gas revenues.

At March 31, 2003, OCI consisted of $25.7 million ($15.2 million net of tax) of unrealized losses on our oil hedging instruments, $0.3 million ($0.2 million, net of tax) loss related to our interest rate swap and $0.2 million ($0.1 million, net of tax) related to pension liabilities. The assets and liabilities related to our open hedging instruments were included in current assets ($1.6 million), other assets ($0.2 million), current liabilities ($24.0 million), other long-term liabilities ($3.7 million) and deferred income taxes (a tax benefit of $10.5 million).

During the first quarter of 2003, $17.3 million ($10.3 million net of tax) in losses from the settlement of oil hedging instruments were reclassified from OCI and charged to income as a reduction of oil sales revenues. As of March 31, 2003, $22.2 million ($13.2 million, net of tax) of deferred net losses on oil hedging instruments recorded in OCI are expected to be reclassified to earnings during the next twelve-month period.

Our average realized price for oil is sensitive to changes in location and quality differential adjustments as set forth in our oil sales contracts. At March 31, 2003 we had basis risk swap contracts on our Illinois Basin production through September 30, 2003. The swaps fix the location differential portion of 2,600 barrels per day at $0.57 and $0.39 per barrel for the second and third quarters of 2003, respectively, and 2,500 barrels per day at $0.31 per barrel for the fourth quarter of 2003.

At March 31, 2003 we had the following open oil hedge positions:

	Bbls Per Day
	2003	2004	2005
Swaps
Average price $23.81 per Bbl	19,250	—	—
Average price $23.82 per Bbl	—	17,500	—
Average price $23.57 per Bbl	—	—	5,000

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

We utilize interest rate swaps to manage the interest rate exposure on our long-term debt. We currently have an interest rate swap agreement that expires in October 2004 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 (1.4% at March 31, 2003).

Note 4—Long-Term Debt

At March 31, 2003 long-term debt consisted of:

	Current		Long-Term
$300 million revolving credit facility	$	—	$	32,500
8.75% senior subordinated notes, net of
unamortized discount of $3.1 million		—		196,908
Other		511		511

	$	511	$	229,919

$300 million revolving credit facility

As of March 31, 2003 we had $32.5 million in borrowings, bearing interest at 3.0%, and $5.2 million in letters of credit outstanding under our $300.0 million revolving credit facility. The credit facility provides for a borrowing base of $225.0 million that will be reviewed every six months, with the lenders and us each having the right to one annual interim unscheduled redetermination, and adjusted based on our oil and gas properties, reserves, other indebtedness and other relevant factors, and matures in 2005. The credit facility contains a $30.0 million sub-limit on letters of credit. To secure borrowings, we pledged 100% of the shares of stock of our domestic subsidiaries, who also guaranteed payments under the credit facility, and gave mortgages covering 80% of the total present value of our domestic oil and gas properties.

Amounts borrowed under the credit facility bear an annual interest rate, at our election, equal to either: (i) the Eurodollar rate, plus from 1.375% to 1.75%; or (ii) the greatest of (1) the prime rate, as determined by JPMorgan Chase Bank, (2) the certificate of deposit rate, plus 1.0%, or (3) the federal funds rate, plus 0.5%; plus an additional 0.125% to 0.5% for each of (1)-(3). The amount of interest payable on outstanding borrowings is based on (1) the utilization rate as a percentage of the total amount of funds borrowed under the credit facility to the borrowing base and (2) our long-term debt rating. Commitment fees and letter of credit fees under the credit facility are based on the utilization rate and long-term debt rating. Commitment fees range from 0.375% to 0.5% of the unused portion of the borrowing base. Letter of credit fees range from 1.375% to 1.75%. The issuer of any letter of credit receives an issuing fee of 0.125% of the undrawn amount.

The credit facility contains negative covenants that limit our ability, as well as the ability of our subsidiaries, among other things, to incur additional debt, pay dividends on stock, make distributions of cash or property, change the nature of our business or operations, redeem stock or redeem subordinated debt, make investments, create liens, enter into leases, sell assets, sell capital stock of subsidiaries, create subsidiaries, guarantee other indebtedness, enter into agreements that restrict dividends from subsidiaries, enter into certain types of swap agreements, enter into gas imbalance or take-or-pay arrangements, merge or consolidate and enter into transactions with affiliates. In addition, the credit facility requires us to maintain a current ratio, which includes availability, of at least 1.0 to 1.0 and a ratio of total debt to earnings before interest, depreciation, depletion, amortization and income taxes of no more than 4.5 to 1.0. At March 31, 2003, we were in compliance with the covenants contained in the credit facility and could have borrowed the full $225.0 million available under the credit facility.

$500 million revolving credit facility

We have 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. Funding will occur upon closing of the merger. The credit facility provides for a borrowing base of $425.0 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 combined 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 will pledge 100% of the shares of stock of our domestic subsidiaries and will give mortgages covering 80% of the total present value of our domestic oil and gas properties.

Amounts borrowed under this credit facility will 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 will be based on (1) the utilization rate as a percentage of the total amount of funds borrowed under the credit facility to the borrowing base and (2) our long-term debt rating.

8.75% senior subordinated notes

We have $200.0 million principal amount of 8.75% senior subordinated notes due 2012 (the “8.75% notes”) outstanding. The 8.75% notes are our unsecured general obligations, are subordinated in right of payment to all of our existing and future senior indebtedness and are jointly and severally guaranteed on a full, unconditional basis by all of our existing and future domestic restricted subsidiaries. The indenture also limits our ability, as well as the ability of our subsidiaries, among other things, to incur additional indebtedness, make certain investments, make restricted payments, sell assets, enter into agreements containing dividends and other payment restrictions affecting subsidiaries, enter into transactions with affiliates, create liens, merge, consolidate and transfer assets and enter into different lines of business. In the event of a change of control, as defined in the indenture, we will be required to make an offer to repurchase the notes at 101% of the principal amount thereof, plus accrued and unpaid interest to the date of the repurchase. The indenture governing the 8.75% notes permitted the spin-off and the spin-off did not, in itself, constitute a change of control for purposes of the indenture.

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

The merger does not constitute a change of control for purposes of the indenture. Although we currently believe that no waivers or consents are required under the indenture, we plan to obtain all necessary waivers or consents under the indenture if required.

Other

We also have a note with an outstanding principal balance of $1.0 million at March 31, 2003 that was issued in connection with the purchase of a production payment on certain of our producing properties. The note bears interest at 8%, payable annually, and requires an annual principal payment of $511,000 through 2004.

In the first quarter of 2003 we made cash payments for interest and fees totalling $9.5 million.

Note 5—Related Party Transactions

In connection with the reorganization and the spin-off we entered into certain agreements with Plains Resources, including a master separation agreement; an intellectual property agreement; the Plains Exploration & Production transition services agreement; the Plains Resources transition services agreement; and a technical services agreement. For the three months ended March 31, 2003 we billed Plains Resources $136,000 for services provided by us under these agreements and Plains Resources billed us $38,000 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 an aircraft owned by our Chief Executive Officer. In the first quarter of 2003, we paid Gulf Coast $0.3 million in connection with charter services in which our Chief Executive Officer’s aircraft was used. The charter services were arranged through arms-length dealings and the rates were market-based.

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 quarter of 2002 we were charged $5.4 million of interest on amounts payable to Plains Resources. Of such amount $4.7 million was included in interest expense and $0.7 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 quarter of 2002 totaled $2.4 million. Of such amount $1.7 million was included in general and administrative expense and $0.7 million was capitalized in oil and gas properties.

Note 6—Commitments and Contingencies

In the ordinary course of business, we are a claimant and/or defendant in various legal proceedings. In particular, we are required to indemnify Plains Resources for any liabilities it incurs in connection with a lawsuit it (through a predecessor interest in Stocker Resources, Inc.) has regarding an electric services contract with Commonwealth Energy Corporation. In this lawsuit, Plains Resources is seeking a declaratory judgment that it was entitled to terminate the contract and that Commonwealth has no basis for proceeding against a related $1.5 million performance bond. In a 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.

Note 7—Consolidating Financial Statements

We and Plains E&P Company are the co-issuers of the 8.75% notes discussed in Note 3. The 8.75% notes are jointly and severally guaranteed on a full and unconditional basis by 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.

PLAINS EXPLORATION & PRODUCTION COMPANY

CONSOLIDATING BALANCE SHEET (Unaudited)

MARCH 31, 2003

(in thousands)

	Issuer			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
ASSETS
Current Assets
Cash and cash equivalents	$	1,001		$	1		$	—		$	1,002
Accounts receivable and other current assets		21,549			8,851			—			30,400
Commodity hedging contracts		1,623			—			—			1,623
Inventories		4,676			1,317			—			5,993

		28,849			10,169			—			39,018

Property and Equipment, at cost
Oil and natural gas properties—full cost method
Subject to amortization		529,235			132,534			—			661,769
Not subject to amortization		18,368			12,411			—			30,779
Other property and equipment		2,088			198			—			2,286

		549,691			145,143			—			694,834
Less allowance for depreciation, depletion and amortization		(53,064	)		(92,110	)		—			(145,174	)

		496,627			53,033			—			549,660

Investment in and Advances to Subsidiaries		30,674			—			(30,674	)		—

Other Assets		20,040			(993	)		—			19,047

	$	576,190		$	62,209		$	(30,674	)	$	607,725

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts payable and other current liabilities	$	50,254		$	12,528		$	—		$	62,782
Commodity hedging contracts		14,258			9,754			—			24,012
Current maturities on long-term debt		511			—			—			511

		65,023			22,282			—			87,305

Long-Term Debt		229,919			—			—			229,919

Asset Retirement Obligation		15,674			10,566			—			26,240

Other Long-Term Liabilities		5,586			3,878			—			9,464

Payable to Parent		—			57,726			(57,726	)		—

Deferred Income Taxes		67,123			(5,191	)		—			61,932

Stockholders’ Equity
Stockholders’ equity		208,351			(19,944	)		19,944			208,351
Accumulated other comprehensive income		(15,486	)		(7,108	)		7,108			(15,486	)

		192,865			(27,052	)		27,052			192,865

	$	576,190		$	62,209		$	(30,674	)	$	607,725

PLAINS EXPLORATION & PRODUCTION COMPANY

CONSOLIDATING BALANCE SHEET

DECEMBER 31, 2002

(in thousands)

	Issuer			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
ASSETS
Current Assets
Cash and cash equivalents	$	1,004		$	24		$	—		$	1,028
Accounts receivable and other current assets		21,273			8,646			—			29,919
Commodity hedging contracts		2,594			—			—			2,594
Inventories		4,009			1,189			—			5,198

		28,880			9,859			—			38,739

Property and Equipment, at cost
Oil and natural gas properties—full cost method
Subject to amortization		507,501			121,953			—			629,454
Not subject to amortization		17,621			12,424			—			30,045
Other property and equipment		2,008			199			—			2,207

		527,130			134,576			—			661,706
Less allowance for depreciation, depletion and amortization		(75,007	)		(93,487	)		—			(168,494	)

		452,123			41,089			—			493,212

Investment in and Advances to Subsidiaries		33,243			—			(33,243	)		—

Other Assets		19,221			(292	)		—			18,929

	$	533,467		$	50,656		$	(33,243	)	$	550,880


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts payable and other current liabilities	$	50,996		$	10,096		$	—		$	61,092
Commodity hedging contracts		15,188			9,384			—			24,572
Current maturities on long-term debt		511			—			—			511

		66,695			19,480			—			86,175

Long-Term Debt		233,166			—			—			233,166

Other Long-Term Liabilities		4,101			2,202			—			6,303

Payable to Parent		—			61,179			(61,179	)		—

Deferred Income Taxes		55,685			(4,269	)		—			51,416

Stockholders’ Equity
Stockholders’ equity		186,678			(22,240	)		22,240			186,678
Accumulated other comprehensive income		(12,858	)		(5,696	)		5,696			(12,858	)

		173,820			(27,936	)		27,936			173,820

	$	533,467		$	50,656		$	(33,243	)	$	550,880

PLAINS EXPLORATION & PRODUCTION COMPANY

CONSOLIDATING STATEMENTS OF INCOME (Unaudited)

THREE MONTHS ENDED MARCH 31, 2003

(in thousands)

	Issuer			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
Revenues
Oil sales to Plains All American Pipeline, L.P.	$	42,953		$	21,785		$	—		$	64,738
Oil hedging		(10,731	)		(6,580	)		—			(17,311	)
Gas sales		4,104			—			—			4,104
Other operating revenues		—			207			—			207

		36,326			15,412			—			51,738

Costs and Expenses
Production expenses		11,760			8,218			—			19,978
Production and ad valorem taxes		919			116			—			1,035
General and administrative
Stock appreciation rights		(1,363	)		—			—			(1,363	)
Other		3,998			441			—			4,439
Depreciation, depletion and amortization		5,809			1,914			—			7,723
Accretion of asset retirement obligation		355			227			—			582

		21,478			10,916			—			32,394

Income from Operations		14,848			4,496			—			19,344
Other Income (Expense)
Equity in earnings of subsidiaries		2,296			—			(2,296	)		—
Interest expense		(3,169	)		(1,687	)		—			(4,856	)
Interest and other income		24			9			—			33

Income Before Income Taxes and Cumulative Effect of Accounting Change		13,999			2,818			(2,296	)		14,521
Income tax expense
Current		226			(1,407	)		—			(1,181	)
Deferred		(4,977	)		240			—			(4,737	)

Income Before Cumulative Effect of Accounting Change		9,248			1,651			(2,296	)		8,603
Cumulative effect of accounting change, net of tax benefit		11,679			645			—			12,324

Net Income	$	20,927		$	2,296		$	(2,296	)	$	20,927

PLAINS EXPLORATION & PRODUCTION COMPANY

CONSOLIDATING STATEMENTS OF INCOME (Unaudited)

THREE MONTHS ENDED MARCH 31, 2002

(in thousands)

	Issuer			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
Revenues
Oil sales to Plains All American Pipeline, L.P.	$	25,568		$	9,673		$	—		$	35,241
Oil hedging		2,179			1,265			—			3,444
Gas sales		1,988			—			—			1,988

		29,735			10,938			—			40,673

Costs and Expenses
Production expenses		10,904			5,201			—			16,105
Production and ad valorem taxes		1,077			47			—			1,124
General and administrative		2,111			341			—			2,452
Depreciation, depletion and amortization		4,824			1,867			—			6,691

		18,916			7,456			—			26,372

Income from Operations		10,819			3,482			—			14,301
Other Income (Expense)
Equity in earnings of subsidiaries		1,235			—			(1,235	)		—
Interest expense		(3,045	)		(1,647	)		—			(4,692	)
Interest and other income		9			9			—			18

Income Before Income Taxes		9,018			1,844			(1,235	)		9,627
Income tax expense
Current		(1,365	)		(680	)		—			(2,045	)
Deferred		(1,789	)		71			—			(1,718	)

Net Income	$	5,864		$	1,235		$	(1,235	)	$	5,864

PLAINS EXPLORATION & PRODUCTION COMPANY

CONSOLIDATING STATEMENTS OF CASH FLOWS (Unaudited)

THREE MONTHS ENDED MARCH 31, 2003

(in thousands of dollars)

	Issuer			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	20,927		$	2,296		$	(2,296	)	$	20,927
Items not affecting cash flows from operating activities
Depreciation, depletion and amortization		5,809			1,914			—			7,723
Accretion of asset retirement obligation		355			227			—			582
Equity in earnings of subsidiaries		(2,296	)		—			2,296			—
Deferred income taxes		4,977			(240	)		—			4,737
Cumulative effect of adoption of accounting change		(11,679	)		(645	)		—			(12,324	)
Noncash compensation		(1,632	)		—			—			(1,632	)
Other noncash items		59			—			—			59
Change in assets and liabilities from operating activities
Accounts receivable and other assets		308			36			—			344
Inventories		(667	)		(128	)		—			(795	)
Accounts payable and other liabilities		(573	)		(1,021	)		—			(1,594	)

Net cash provided by operating activities		15,588			2,439			—			18,027

CASH FLOWS FROM INVESTING ACTIVITIES
Additions to oil and gas properties		(10,306	)		(2,462	)		—			(12,768	)
Other		(2,372	)		—			—			(2,372	)

Net cash used in investing activities		(12,678	)		(2,462	)		—			(15,140	)

CASH FLOWS FROM FINANCING ACTIVITIES
Change in revolving credit facility		(3,300	)		—			—			(3,300	)
Proceeds from debt issuance		(123	)		—			—			(123	)
Receipts from (payments to) Plains Resources Inc.		—			—			—			—
Contribution from Plains Resources Inc.		510			—			—			510

Net cash provided by (used in) financing activities		(2,913	)		—			—			(2,913	)

Net increase (decrease) in cash and cash equivalents		(3	)		(23	)		—			(26	)
Cash and cash equivalents, beginning of period		1,004			24			—			1,028

Cash and cash equivalents, end of period	$	1,001		$	1		$	—		$	1,002

PLAINS EXPLORATION & PRODUCTION COMPANY

CONSOLIDATING STATEMENTS OF CASH FLOWS (Unaudited)

THREE MONTHS ENDED MARCH 31, 2002

(in thousands of dollars)

	Issuer			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	5,864		$	1,235		$	(1,235	)	$	5,864
Items not affecting cash flows from operating activities
Depreciation, depletion and amortization		4,824			1,867			—			6,691
Equity in earnings of subsidiaries		(1,235	)		—			1,235			—
Deferred income taxes		1,789			(71	)		—			1,718
Change in assets and liabilities from operating activities
Accounts receivable and other assets		(3,430	)		3,074			—			(356	)
Inventories		(409	)		(182	)		—			(591	)
Accounts payable and other liabilities		2,188			(5,976	)		—			(3,788	)

Net cash provided by operating activities		9,591			(53	)		—			9,538

CASH FLOWS FROM INVESTING ACTIVITIES
Additions to oil and gas properties		(20,681	)		(3,260	)		—			(23,941	)
Additions to other property and equipment		(18	)		(2	)		—			(20	)

Net cash used in investing activities		(20,699	)		(3,262	)		—			(23,961	)

CASH FLOWS FROM FINANCING ACTIVITIES
Receipts from Plains Resources Inc.		11,098			3,313			—			14,411

Net cash provided by (used in) financing activities		11,098			3,313			—			14,411

Net increase (decrease) in cash and cash equivalents		(10	)		(2	)		—			(12	)
Cash and cash equivalents, beginning of period		11			2			—			13

Cash and cash equivalents, end of period	$	1		$	—		$	—		$	1

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.

Proposed Merger with 3TEC Energy Corporation

On February 3, 2003 we announced that we entered into a definitive agreement pursuant to which we will acquire 3TEC Energy Corporation, or 3TEC, the “merger”, for approximately $340.0 million including merger related costs (based on $9.47 per PXP common share, the average closing price of our common stock during the five business day period commencing two business days before the merger was announced) plus the assumption of debt, which totaled $106.0 million at March 31, 2003. Under the terms of the merger agreement, 3TEC common stockholders will receive $8.50 of cash and 0.85 of a share of our common stock for each share of 3TEC common stock they own. This exchange ratio is subject to an upward or downward adjustment should the market price of our common stock fall below $7.65 per share or rise above $12.35 per share, respectively. This mechanism is intended to provide that the total value of the consideration received by 3TEC common stockholders at the effective time of the merger will be between $15.00 and $19.00 per share of 3TEC common stock. For this purpose, the market price of our common stock will be the average closing price of our common stock for the 20 consecutive trading days immediately preceding the third trading day prior to closing. In addition, if the market price of our common stock is less than $6.25, we may either (i) terminate the merger agreement or (ii) in lieu of issuing more common stock increase the cash consideration paid per share of 3TEC common stock by the amount our common stock market price is less than $6.25 times the exchange ratio after adjustment.

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; 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 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 sales price fluctuations. Our hedging arrangements provide us protection on the hedged volumes if oil prices decline below the prices at which these hedges are set. However, if oil prices increase, ceiling prices in our hedges may cause us to receive less revenues on the hedged volumes than we would receive in the absence of hedges. We do not currently have any gas hedges. Gains and losses from hedging transactions are recognized as revenues when the associated production is sold.

Our oil and gas production expenses include salaries and benefits of personnel involved in production activities, electric costs, maintenance costs, production, ad valorem and severance taxes, and other costs necessary to operate our producing properties. Depletion of capitalized costs of producing oil and gas properties is provided using the units of production method based upon proved reserves. For the purposes of computing depletion, proved reserves are redetermined as of the end of each year and on an interim basis when deemed necessary. General and administrative expenses consist primarily of salaries and related benefits of administrative personnel, office rent, systems costs and other administrative costs. We estimate that as a result of 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 and spin-off costs) reflecting the incremental costs of operating as a separate, publicly held company.

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

Results of Operations

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

	Three Months Ended March 31,
	2003			2002
Sales Volumes
Oil (MBbls)		2,181			2,033
Gas (MMcf)		729			877
MBOE		2,303			2,179
Daily Average Sales Volumes
Oil (Bbls)
Onshore California		15,855			16,214
Offshore California		6,022			3,731
Illinois		2,360			2,640

		24,237			22,585

Gas (Mcf)
Onshore California		8,099			9,743

BOE		25,587			24,209

Unit Economics (in dollars)
Average Oil Sales Price ($/Bbl)
Average NYMEX	$	33.80		$	21.63
Hedging revenue (cost)		(7.94	)		1.69
Differential		(4.11	)		(4.29	)

Net realized	$	21.75		$	19.03

Average Gas Sales Price ($/Mcf)	$	5.63		$	2.27
Average Sales Price per BOE	$	22.38		$	18.67
Average Production Expenses per BOE		(8.67	)		(7.39	)
Average Production and Ad Valorem
Taxes per BOE		(0.45	)		(0.52	)

Gross Margin per BOE		13.26			10.76
G&A per BOE (1)		(1.34	)		(1.13	)

Gross Profit per BOE	$	11.92		$	9.63

DD&A per BOE (oil and gas properties)	$	3.18		$	3.04

(1)

After $0.49 per BOE net reduction in G&A expense ($1.1 million) related to SARs and noncash compensation in 2003.

Comparison of Three Months Ended March 31, 2003 to Three Months Ended March 31, 2002

Net income. We reported first quarter 2003 net income of $20.9 million, or $0.86 per diluted share compared to net income of $5.9 million, or $0.24 per diluted share for the first quarter of 2002. Net income in the first quarter of 2003 includes 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 revenues, excluding the effect of hedging, increased 84%, or $29.5 million, to $64.7 million for the first quarter of 2003 from $35.2 million for the first quarter of 2002. The increase was primarily due to increased sales prices that increased revenues by $25.1 million and higher volumes that increased revenues by $4.4 million.

Our average realized price for oil increased 14%, or $2.72, to $21.75 per Bbl for the first quarter of 2003 from $19.03 per Bbl for the first quarter of 2002. The increase is primarily attributable to an improvement in the NYMEX oil price, which averaged $33.80 per Bbl in 2003 versus $21.63 per Bbl in 2002. The average differential for location and quality decreased to $4.11 per Bbl in 2003 compared to $4.29 per Bbl in 2002. Hedging had the effect of decreasing our average price per Bbl by $7.94 in 2003 compared to an increase of $1.69 per Bbl in 2002.

Our gas revenues increased 106%, or $2.1 million, to $4.1 million for the first quarter of 2003 from $2.0 million

for the first quarter of 2002. The increase was primarily due to increased sales prices that increased revenues by $2.9 million partially offset by lower volumes that decreased revenues by $0.8 million.

Production expenses. Our production expenses increased 24%, or $3.9 million, to $20.0 million for the first quarter of 2003 from $16.1 million for the first quarter of 2002, primarily from our increased ownership percentage in the offshore California properties. On a per unit basis, production expenses increased 17%, or $1.28 per BOE, to $8.67 per BOE for the first quarter of 2003 from $7.39 per BOE for the first quarter of 2002, primarily due to higher fuel and electricity costs, as well as our increased ownership percentage in the offshore California properties which have a higher per unit production cost than our other properties. Unit production expenses for the offshore California properties will continue to increase as production declines due to the large component of fixed expenses for this asset.

Production and ad valorem taxes. Our production and ad valorem taxes decreased 8%, or $0.1 million, to $1.0 million for the first quarter of 2003 from $1.1 million for the first quarter of 2002.

General and administrative expense. Our general and administrative, or G&A, expense, excluding amounts attributable to stock appreciation rights, increased 81%, or $2.0 million, to $4.4 million for the first quarter of 2003 from $2.4 million for the first 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. These increases were partially offset by a credit of approximately $1.4 million attributable to the decline in the in-the-money value of stock appreciation rights issued on the spin-off date. G&A expense does not include amounts capitalized as part of our acquisition, exploration and development activities. We capitalized $2.0 million and $1.0 million of G&A expense in the first quarter of 2003 and 2002, respectively.

Depreciation, depletion and amortization, or DD&A. Our DD&A expense increased 15%, or $1.0 million, to $7.7 million for the first quarter of 2003 from $6.7 million for the first quarter of 2002. Approximately $0.7 million of the increase was attributable to our oil and gas DD&A as we had both a higher unit rate ($3.18 per BOE in 2003 versus $3.04 in 2002) and increased production volumes. Other DD&A expense increased approximately $0.3 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 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 3%, or $0.2 million, to $4.9 million for the first quarter of 2003 from $4.7 million for 2002, primarily reflecting a decrease in the amount of interest capitalized. We capitalized approximately $0.3 million and $0.7 million of interest in 2003 and 2002, respectively.

Income tax expense. Our income tax expense increased 57%, or $2.1 million, to $5.9 million for the first quarter of 2003 from $3.8 million for the first quarter of 2002. The increase was primarily due to increased pre-tax income. Our overall effective tax rate increased slightly to 40.8% in 2003 from 39.1% in 2002. Our currently payable effective tax rate was 8.1% for 2003 as compared to 21.2% 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.

Liquidity and Capital Resources

Our primary sources of liquidity are cash generated from our operations and our revolving credit facility. At April 30, 2003 we had approximately $187.0 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 March 31, 2003 we had a working capital deficit of $48.3 million. The working capital deficit includes $22.4 million attributable to the fair value of our hedges, $4.7 million attributable to accrued interest on the 8.75% notes and $1.6 million that reflects the in-the-money value of stock appreciation rights that were deemed vested at March 31, 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 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 $19.6 million will be financed through cash flow and borrowings under our credit facility.

As of April 30, 2003 we had $32.8 million in borrowings and $5.2 million in letters of credit outstanding under our $300.0 million revolving credit facility. The credit facility provides for a borrowing base of $225.0 million that will be reviewed every six months, with the lenders and us each having the right to one annual interim unscheduled redetermination, and adjusted based on our oil and gas properties, reserves, other indebtedness and other relevant factors, and matures in 2005. The credit facility contains a $30.0 million sub-limit on letters of credit. To secure borrowings, we pledged 100% of the shares of stock of our domestic subsidiaries, who also unconditionally guarantee payments under the credit facility, and gave mortgages covering 80% of the total present value of our domestic oil and gas properties.

The credit facility contains negative covenants that limit our ability, as well as the ability of our subsidiaries, among other things, to incur additional debt, pay dividends on stock, make distributions of cash or property, change the nature of our business or operations, redeem stock or redeem subordinated debt, make investments, create liens, enter into leases, sell assets, sell capital stock of subsidiaries, create subsidiaries, guarantee other indebtedness, enter into agreements that restrict dividends from subsidiaries, enter into certain types of swap agreements, enter into gas imbalance or take-or-pay arrangements, merge or consolidate and enter into transactions with affiliates. In addition, the credit facility requires us to maintain a current ratio, which includes availability, of at least 1.0 to 1.0 and a ratio of total debt to earnings before interest, depreciation, depletion, amortization and income taxes of no more than 4.5 to 1.0. At March 31, 2003, we were in compliance with the covenants contained in our credit facility and could have borrowed the full $225.0 million available under the credit facility.

We have $200.0 million of 8.75% senior subordinated notes due 2012, or 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 proposed merger with 3TEC does not constitute a change of control for purposes of the indenture. Although we currently believe that no waivers or consents are required under the indenture, we plan to obtain all necessary waivers or consents under the indenture if required.

We have been assigned a Ba3 senior implied rating and the 8.75% notes have been assigned a B2 rating by Moody’s Investor Service Inc. We have also been assigned a BB– corporate credit rating by Standard and Poor’s Ratings Group. All of these ratings are below investment grade. As a result, at times we may have difficulty accessing capital markets or raising capital on favorable terms.

Cash Flows

	Three Months Ended March 31,
	2003			2002
	(in millions)
Cash provided by (used in):
Operating activities	$	18.0		$	9.5
Investing activities		(15.1	)		(24.0	)
Financing activities		(2.9	)		14.4

Net cash provided by operating activities was $18.0 million and $9.5 million for the first quarter of 2003 and 2002, respectively. The increase primarily reflects higher prices and sales volumes, partially offset by higher production costs.

Net cash used in investing activities was $15.1 million in the first quarter of 2003 and $24.0 million in the first quarter of 2002, consisting primarily of costs incurred in connection with our oil and gas acquisition, development and exploration activities.

Net cash used in financing activities in 2003 was $2.9 million primarily reflecting a $3.3 million reduction in debt and the collection of a $0.5 million contribution receivable from Plains Resources.

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 $70-$80 million on our existing asset base. In connection with the 3TEC acquisition, we agreed to pay $8.50 in cash and 0.85 of a share of our common stock for each share of 3TEC common stock, subject to certain adjustments based on our common share price prior to closing. We estimate that the cash portion of the acquisition cost will be approximately $280.1 million, consisting of $174.1 million cash paid to 3TEC stockholders, plus the assumption of debt which totaled $106.0 million at March 31, 2003. In addition, we estimate that merger related costs will be approximately $15.0 million, including the cost of obtaining a new credit facility. Capital expenditures for the 3TEC properties are expected to be $45-$55 million pursuant to 3TEC’s current plan. Based on the foregoing, total capital expenditures for the combined asset base are estimated to be $115-$135 million for 2003. Subsequent to closing the 3TEC acquisition, we may reallocate capital between the two asset bases to optimize 2003 spending. In addition, we intend to continue to pursue the acquisition of underdeveloped producing properties.

We will incur cash expenditures upon the exercise of stock appreciation rights, or SARs, but our outstanding share count will not increase. At March 31, 2003 we had approximately 3.9 million SARs outstanding of which 1.3 million were vested. If all of the vested SARs were exercised, based on $8.25, the price of our common stock as of March 31, 2003, we would pay $1.6 million to holders of the SARs. See “Critical Accounting Policies and Factors that May Affect Future Results—Stock appreciation rights”.

Commitments and Contingencies

Contractual obligations. At March 31, 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	$	32,500	$	—	$	—	$	200,000
Producing property remediation		1,317		1,225		1,100		700		600		2,150
Operating leases		865		1,208		1,003		422		281		676

	$	2,693	$	2,944	$	34,603	$	1,122	$	881	$	202,826

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 three months ended March 31, 2003 we billed Plains Resources $136,000 for services provided by us under these agreements and Plains Resources billed us $38,000 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 which we have in place, certain factors may impact our future financial results. The most significant of these factors and their effect on certain of our accounting policies are discussed below.

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

Periodically, we enter into hedging arrangements relating to a portion of our oil production to achieve a more predictable cash flow, as well as to reduce our exposure to adverse price fluctuations. Hedging instruments used are typically fixed price swaps and collars and purchased puts and calls. While the use of these types of hedging instruments limits our downside risk to adverse price movements, we are subject to a number of risks, including instances in which the benefit to revenues is limited when commodity prices increase. For a further discussion concerning our risks related to oil and gas prices and our hedging programs, see “Item 3—Quantitative and Qualitative Disclosures about Market Risks”.

Write-downs under full cost ceiling test rules. Under the SEC’s full cost accounting rules, we review the carrying value of our proved oil and gas properties each quarter. Under these rules, capitalized costs of proved oil and gas properties (net of accumulated depreciation, depletion and amortization, and deferred income taxes) may not exceed a “ceiling” equal to: the standardized measure (including, for this test only, the effect of any related hedging activities); plus the lower of cost or fair value of unproved properties not included in the costs being amortized (net of related tax effects).

These rules generally require that we price our future oil and gas production at the oil and gas prices in effect at the end of each fiscal quarter and require a write-down if our capitalized costs exceed this “ceiling,” even if prices declined for only a short period of time. We have had no write-downs due to these ceiling test limitations since 1998. Given the volatility of oil and gas prices, it is likely that our estimate of discounted future net revenues from proved oil and gas reserves will change in the near term. If oil and gas prices decline significantly in the future, even if only for a short period of time, write-downs of our oil and gas properties could occur. Write-downs required by these rules do not directly impact our cash flows from operating activities.

Oil and gas reserves. Our proved reserve information is based on estimates prepared by outside engineering firms. Estimates prepared by others may be higher or lower than these estimates.

Estimates of proved reserves may be different from the actual quantities of oil and gas recovered because such estimates depend on many assumptions and are based on operating conditions and results at the time the estimate is made. The actual results of drilling and testing, as well as changes in production rates and recovery factors, can vary significantly from those assumed in the preparation of reserve estimates. As a result, such factors have historically, and can in the future, cause significant upward and downward revisions to proved reserve estimates.

You should not assume that the standardized measure is the current market value of our estimated proved oil and gas reserves. In accordance with SEC requirements, we base the estimated discounted future net revenues from proved reserves on prices and costs on the date of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of the estimate.

A large portion of our proved reserve base (approximately 95% at December 31, 2002) is comprised of oil properties that are sensitive to oil price volatility. Historically, we have experienced significant upward and downward revisions to our proved reserve volumes and values as a result of changes in year-end oil and gas prices and the corresponding adjustment to the projected economic life of such properties. Prices for oil and gas are likely to continue to be volatile, resulting in future downward and upward revisions to our proved reserve base.

Our rate of recording DD&A is dependent upon our estimate of proved reserves including future development and abandonment costs as well as our level of capital spending. If the estimates of proved reserves decline, the rate at which we record DD&A expense increases, reducing our net income. This decline may result from lower market prices, which may make it uneconomic to drill for and produce higher cost fields. The decline in proved reserve estimates may impact the outcome of the “ceiling” test discussed above. In addition, increases in costs required to develop our reserves would increase the rate at which we record DD&A expense. We are unable to predict changes in future development costs as such costs are dependent on the success of our exploitation and development program, as well as future economic conditions.

Stock appreciation rights. At the time of the spin-off, pursuant to our employee matters agreement with Plains Resources, all outstanding options to acquire Plains Resources common stock at the time of the spin-off were “split” into (1) an equal number of options to acquire Plains Resources common stock and (2) an equal number of SARs, with respect to our common stock. The exercise price of the original Plains Resources stock options was also “split” between the new Plains Resources stock options and the SARs based on the following relative amounts: the closing price (with dividend) of Plains Resources common stock on the spin-off date ($23.05 per share) less the closing price (on a “when-issued” basis) of our common stock on the spin-off date ($9.10 per share), both as reported on the NYSE, and such closing price of our common stock.

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

At March 31, 2003 we had approximately 3.9 million SARs outstanding of which 1.3 million were vested.

Adoption of SFAS 143

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 No. 143 and the change in accounting principle resulted in an increase in 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. There will be no impact on our cash flows as a result of adopting SFAS No. 143.

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” on April 30, 2003. The statement is effective for contracts entered into or modified after June 30, 2003 and for hedging relationships designated after June 30, 2003. At this time, we cannot reasonably estimate the effect of the adoption of SFAS No. 149 on either our financial position or results of operations.

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, if the merger is completed;

•

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

•

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

•

impact of oil and gas price fluctuations;

•

the effects of our indebtedness, which could adversely restrict our ability to operate, could make us vulnerable to general adverse economic and industry conditions, could place us at a competitive disadvantage compared to our competitors that have less debt, and could have other adverse consequences;

•

the effects of competition;

•

the success of our risk management activities;

•

the availability (or lack thereof) of acquisition or combination opportunities;

•

the impact of current and future laws and governmental regulations;

•

environmental liabilities that are not covered by an effective indemnity or insurance; and

•

general economic, market or business conditions.

All forward-looking statements in this Quarterly Report on Form 10-Q are made as of the date hereof, and you should not place undue certainty on these statements without also considering the risks and uncertainties associated with these statements and our business that are addressed in this Quarterly Report on Form 10-Q. Moreover, although we believe the expectations reflected in the forward-looking statements are based upon reasonable assumptions, we can give no assurance that we will attain these expectations or that any deviations will not be material. See —“Critical” Accounting Policies and Factors That May Affect Future Results” for an additional discussion of risks and uncertainties.

ITEM 3—Qualitative and Quantitative Disclosures About Market Risks

During the first quarter of 2003, $17.3 million ($10.3 million net of tax) in losses from the settlement of oil hedging instruments were reclassified from OCI and charged to income as a reduction of oil sales revenues. As of March 31, 2003, $22.2 million ($13.2 million, net of tax) of deferred net losses on derivative instruments recorded in OCI are expected to be reclassified to earnings during the next twelve-month period.

Commodity price risk. At April 30, 2003 we had the following open oil hedge positions:

	Bbls Per Day
	2003	2004	2005
Swaps
Average price $23.81 per Bbl	19,250	—	—
Average price $23.82 per Bbl	—	17,500	—
Average price $23.57 per Bbl	—	—	5,000

Assuming our first quarter 2003 production volumes are held constant in subsequent periods, these positions result in us hedging approximately 79%, 72% and 21% of oil production in 2003, 2004 and 2005, respectively. Location and quality differentials attributable to our properties are not included in the foregoing prices. Because of the quality and location of our oil production, these adjustments will reduce our net price per barrel.

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 an increase (decrease) in revenues of $(17.3) million, and $3.4 million for the first quarters of 2003 and 2002, respectively. As of March 31, 2003 we had an unrealized loss of $25.7 million ($15.2 million, net of tax) with respect to these contracts. The estimated fair value of the hedges is included in our balance sheet as of March 31, 2003.

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 March 31, 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 $0.57 and $0.39 per barrel for the second and third quarters of 2003, respectively, 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 are participating lenders in our revolving credit facility, with one counterparty holding contracts that represent approximately 24% of the fair value of all open positions as of March 31, 2003.

Our management intends to continue to maintain hedging arrangements for a significant portion of our production. These contracts may expose us to the risk of financial loss in certain circumstances. Our hedging arrangements provide us protection on the hedged volumes if 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.

ITEM 4—Controls and Procedures

Within 90 days before the date of this report on Form 10-Q, under the supervision and with the participation of our management, including our Chief Executive Officer (our principal executive officer) and our Chief Financial Officer (our principal financial officer), we evaluated the effectiveness of our disclosure controls and procedures (as defined under Rule 13a-14(c) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”)). Based on this evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that our disclosure controls and procedures are effective to ensure that information we are required to disclose in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.

There were no significant changes in our internal controls or in other factors that could significantly affect these controls subsequent to the date of such evaluation.

PART II. OTHER INFORMATION

ITEM 1—Legal Proceedings.

In the ordinary course of our business, we are a claimant or defendant in various legal proceedings. 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.

On September 18, 2002 Stocker Resources Inc., or Stocker, our general partner before we converted from a limited partnership to a corporation, filed a declaratory judgment action against Commonwealth Energy Corporation, or Commonwealth, in the Superior Court of Orange County, California relating to the termination of an electric service contract. Stocker is seeking a declaratory judgment that it was entitled to terminate the contract and that Commonwealth has no basis for proceeding against Stocker’s related $1.5 million performance bond. Also on September 18, 2002, Stocker was named a defendant in an action brought by Commonwealth in the Superior Court of Orange County, California for breach of the electric service contract. Commonwealth is seeking unspecified damages. The two cases have been consolidated and set for trial in December 2003. In December 2002, Stocker was merged into Plains Resources. Under our master separation agreement with Plains Resources, we must indemnify Plains Resources for damages it incurs as a result of this action. We understand that Plains Resources intends to defend its rights vigorously in this matter.

ITEM 6—Exhibits and Reports on Form 8-K

(a) Exhibits


10.1		First Supplemental Indenture, dated as of March 31, 2003, among PXP Gulf Coast Inc., Plains Exploration & Production Company, and Plains E&P Company, each other then existing Subsidiary Guarantor under the Indenture, and JPMorgan Chase Bank as Trustee under the Indenture

99.1		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

99.2		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

(b) Reports on Form 8-K

A Current Report on Form 8-K was filed on February 21, 2003 with respect to the Company’s press release reporting 2002 earnings and December 31, 2002 oil and gas reserve information.

A Current Report on Form 8-K was filed on February 20, 2003 with respect to current estimates of certain results for 2003.

A Current Report on Form 8-K was filed on February 3, 2003 with respect to the proposed merger with 3TEC Energy Corporation.

Items 2, 3, 4 & 5 are not applicable and have been omitted

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: May 14, 2003	By:	/s/ STEPHEN A. THORINGTON
		Stephen A. Thorington Executive Vice President and Chief Financial Officer (Principal Financial Officer)

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