PLAINS RESOURCES INC - 10-Q Quarterly Report

Back to GetFilings.com

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-Q

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

SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2002

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

SECURITIES EXCHANGE ACT OF 1934

Commission file number: 0-9808

PLAINS RESOURCES INC.

(Exact name of registrant as specified in its charter)

Delaware

(State or other jurisdiction of

incorporation or organization)

13-2898764

(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 ü No

23,996,000 shares of common stock, $0.10 par value, issued and outstanding at October 31, 2002.

PLAINS RESOURCES INC. AND SUBSIDIARIES

TA BLE OF CONTENTS

		Page
PART I. FINANCIAL INFORMATION

CONSOLIDATED FINANCIAL STATEMENTS:


Condensed Consolidated Balance Sheets: September 30, 2002 and December 31, 2001		3
Consolidated Income Statements: For the three and nine months ended September 30, 2002 and 2001		4
Consolidated Statements of Cash Flows: For the nine months ended September 30, 2002 and 2001		5
Consolidated Statements of Changes in Stockholders' Equity For the nine months ended September 30, 2002		6
Notes to Consolidated Financial Statements		7

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		16

PART II. OTHER INFORMATION		42

PLAINS RESOURCES INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)

(in thousands of dollars)

	September 30, 2002			December 31, 2001
ASSETS
Current Assets
Cash and cash equivalents	$	1,186		$	1,179
Accounts receivable
Plains All American Pipeline, L.P.		25,927			13,726
Other		6,309			6,313
Commodity hedging contracts		454			23,257
Inventory		7,793			6,721
Other current assets		2,889			1,527

		44,558			52,723

Property and Equipment
Oil and natural gas properties—full cost method		999,578			941,404
Other property and equipment		4,122			4,003

		1,003,700			945,407
Less allowance for depreciation, depletion and amortization		(461,925	)		(437,982	)

		541,775			507,425

Investment in Plains All American Pipeline, L.P.		73,677			64,626

Other Assets		20,248			24,014

	$	680,258		$	648,788


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts payable and other current liabilities	$	55,239		$	53,895
Commodity hedging contracts		24,980			—
Interest payable		4,859			8,286
Notes payable		511			511

		85,589			62,692

Long-Term Debt
Bank debt		90,700			11,500
Subordinated debt		196,803			269,539
Other		511			1,022

		288,014			282,061

Other Long-Term Liabilities		6,987			4,889

Deferred Income Taxes		41,640			44,294

Stockholders’ Equity		258,028			254,852

	$	680,258		$	648,788

See notes to consolidated financial statements.

PLAINS RESOURCES INC. AND SUBSIDIARIES

CONS OLIDATED STATEMENTS OF INCOME (Unaudited)

(in thousands, except per share data)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2002			2001			2002			2001
Revenues
Crude oil sales to Plains All American Pipeline, L.P.	$	52,545		$	50,771		$	140,653		$	143,486
Natural gas sales		2,553			3,352			7,130			26,870
Other operating revenues		14			45			27			468

		55,112			54,168			147,810			170,824

Costs and Expenses
Production expenses		23,494			19,054			61,501			53,084
General and administrative		3,948			2,734			12,049			18,294
Depreciation, depletion and amortization		8,697			7,163			24,531			20,547

		36,139			28,951			98,081			91,925

Income from Operations		18,973			25,217			49,729			78,899
Other Income (Expense)
Equity in earnings of Plains All American Pipeline, L.P.		4,454			5,207			14,060			15,798
Gain on interest in Plains All American Pipeline, L.P.		14,512			918			14,512			151,089
Loss on debt extinguishment		(10,319	)		—			(10,319	)		—
Expenses of terminated public equity offering		(1,700	)		—			(1,700	)		—
Interest expense		(7,333	)		(6,313	)		(20,228	)		(20,136	)
Interest and other income		314			93			377			91

Income Before Income Taxes and Cumulative Effect of Accounting Change		18,901			25,122			46,431			225,741
Income tax benefit (expense)
Current		(647	)		(1,118	)		1,290			(10,045	)
Deferred		(7,069	)		(8,850	)		(20,266	)		(79,488	)

Income Before Cumulative Effect of Accounting Change		11,185			15,154			27,455			136,208
Cumulative effect of accounting change, net of tax benefit		—			—			—			(1,986	)

Net Income		11,185			15,154			27,455			134,222
Preferred dividend requirement		(350	)		(350	)		(1,050	)		(26,896	)

Income Attributable to Common Shares	$	10,835		$	14,804		$	26,405		$	107,326

Earnings per Share
Income Before Cumulative Effect of Accounting Change
Basic	$	0.45		$	0.63		$	1.11		$	5.41
Diluted	$	0.44		$	0.58		$	1.08		$	4.03
Net Income
Basic	$	0.45		$	0.63		$	1.11		$	5.31
Diluted	$	0.44		$	0.58		$	1.08		$	3.95
Weighted Average Shares Outstanding
Basic		23,956			23,464			23,826			20,204
Diluted		25,549			26,227			25,387			27,904

See notes to consolidated financial statements.

PLAINS RESOURCES INC. AND SUBSIDIARIES

CONS OLIDATED STATEMENTS OF CASH FLOWS

(in thousands of dollars)

(unaudited)

	Nine Months Ended September 30,
	2002			2001
Cash Flows from Operating Activities
Net income	$	27,455		$	134,222
Items not affecting cash flows from operating activities:
Depreciation, depletion and amortization		24,531			20,547
Equity in earnings of Plains All American Pipeline, L.P.		(14,060	)		(15,798	)
Noncash gains		(14,512	)		(151,089	)
Deferred income taxes		20,266			79,488
Cumulative effect of accounting change		—			1,986
Change in derivative fair value		—			1,227
Noncash compensation		865			4,514
Other		1,891			1,664
Distributions from Plains All American Pipeline, L.P.		21,558			24,596
Change in assets and liabilities from operating activities:
Current and other assets		(11,505	)		15,052
Current and other liabilities		(2,365	)		(31,104	)

Net cash provided by operating activities		54,124			85,305

Cash Flows from Investing Activities
Oil and gas properties		(59,230	)		(100,097	)
Other property and equipment		(119	)		(530	)
Sale of interest in Plains All American Pipeline, L.P.		—			106,941
Investment in Plains All American Pipeline, L.P.		(1,334	)		(2,816	)

Net cash provided by (used in) investing activities		(60,683	)		3,498

Cash Flows from Financing Activities
Net change in Plains Exploration & Production credit facility		90,700			—
Net change in Plains Resources credit facility		(11,500	)		(27,300	)
Proceeds from debt issuance		196,752			—
Retirement of long-term debt		(267,961	)		(511	)
Debt issuance costs		(5,469	)		—
Exercise of stock options		4,748			5,543
Treasury stock purchases		—			(42,749	)
Preferred stock dividends paid		(700	)		(7,998	)
Other		(4	)		(98	)

Net cash provided by (used in) financing activities		6,566			(73,113	)

Net increase in cash and cash equivalents		7			15,690
Decrease in cash due to deconsolidation of Plains All American Pipeline, L.P.		—			(3,425	)
Cash and cash equivalents, beginning of period		1,179			5,080

Cash and cash equivalents, end of period	$	1,186		$	17,345

See notes to consolidated financial statements.

PLAINS RESOURCES INC. AND SUBSIDIARIES

CONSOLIDATED STATE MENTS OF CHANGES IN STOCKHOLDERS’ EQUITY

(in thousands)

(unaudited)

	Nine Months Ended September 30, 2002
	Shares		Amount
Series D Cumulative Convertible Preferred Stock
Balance, beginning and end of period	47		$	23,300

Common Stock
Balance, beginning of period	27,677			2,768
Common stock issued upon exercise of stock options and other	167			17

Balance, end of period	27,844			2,785

Additional Paid-in Capital
Balance, beginning of period				268,520
Common stock issued upon exercise of stock options and other				4,128

Balance, end of period				272,648

Retained Earnings
Balance, beginning of period				37,676
Net income				27,455
Preferred stock dividends				(1,050	)
Treasury stock issued for less than cost				(926	)

Balance, end of period				63,155

Accumulated Other Comprehensive Income
Balance, beginning of period				13,930
Other comprehensive income				(30,775	)

Balance, end of period				(16,845	)

Treasury Stock
Balance, beginning of period	(4,121	)		(91,342	)
Treasury stock issued upon exercise of stock options and other	267			4,327

Balance, end of period	(3,854	)		(87,015	)

			$	258,028

See notes to consolidated financial statements.

PLAINS RESOURCES INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Note 1—Organization and Accounting Policies

These consolidated financial statements include the accounts of Plains Resources Inc. (“Plains”, “our”, or “we”) and our wholly owned subsidiaries. We account for our interest in Plains All American Pipeline, L.P. (“PAA”) on the equity method of accounting.

These consolidated financial statements and related notes present our consolidated financial position as of September 30, 2002 and December 31, 2001, the results of our operations and our cash flows for the three and nine months ended September 30, 2002 and 2001 and the changes in our stockholders’ equity for the nine months ended September 30, 2002. The results for the nine months ended September 30, 2002, are not necessarily indicative of the final results to be expected for the full year. These financial statements have been prepared in accordance with the instructions with respect to interim reporting as prescribed by the Securities and Exchange Commission (“SEC”). For further information, refer to our Form 10-K for the year ended December 31, 2001, filed with the SEC.

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.

We are an independent energy company that is engaged in the “Upstream” oil and gas business. The Upstream business acquires, exploits, develops, explores for and produces crude oil and natural gas. Our Upstream activities are all located in the United States. We conduct our Upstream operations in Illinois and onshore and offshore California through Plains Exploration & Production Company (“PXP”, a wholly-owned subsidiary) and its wholly-owned subsidiaries. Our Upstream operations in Florida are conducted by Calumet Florida L.L.C. (a wholly-owned subsidiary). We participate in the “Midstream” oil and gas business, which consists of the marketing, transportation and terminalling of crude oil, through our investment in PAA. All of PAA’s Midstream activities are conducted in the United States and Canada.

We evaluate the capitalized costs of our oil and gas properties on an ongoing basis and have utilized the most recently available information to estimate our reserves at September 30, 2002 in order to determine the realizability of such capitalized costs. Future events, including drilling activities, product prices and operating costs, may affect future estimates of such reserves.

Inventories. Crude oil inventories are carried at the lower of the cost to produce or market value. Materials and supplies inventories are stated at the lower of cost or market, with cost determined on the average cost method. Crude oil inventories totaled $2.1 million at September 30, 2002 and $1.5 million at December 31, 2001. Materials and supplies inventories totaled $5.7 million at September 30, 2002 and $5.2 million at December 31, 2001.

Recent Accounting Pronouncements. In June 2001 Statement of Financial Accounting Standards (“SFAS”) No. 143, Accounting for Asset Retirement Obligations was issued. SFAS No. 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. Subsequently, the asset retirement cost should be allocated to expense using a systematic and rational method. SFAS No. 143 is effective for fiscal years beginning after June 15, 2002. We are currently assessing the impact of SFAS No. 143 and at this time cannot reasonably estimate the effect of this statement on our consolidated financial position, results of operations or cash flows.

PLAINS RESOURCES INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

In April 2002, SFAS No. 145, “Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13, and Technical Corrections,” was issued. SFAS 145 rescinds SFAS 4 and SFAS 64 related to classification of gains and losses on debt extinguishment such that most debt extinguishment gains and losses will no longer be classified as extraordinary. SFAS 145 also amends SFAS 13 with respect to sales-leaseback transactions. The provisions of SFAS 145 with respect to sales-leaseback transactions have no effect on our financial statements. As a result of the provisions of SFAS 145 with respect to debt extinguishments, the $10.3 million of debt extinguishment costs related to our refinancing of certain debt instruments in the third quarter of 2002 are not classified as an extraordinary item in our statement of income. We had no gains or losses on debt extinguishments in 2001.

In July 2002, SFAS No. 146, “Accounting For Costs Associated with Exit or Disposal Activities” was issued. SFAS 146 is effective for exit or disposal activities initiated after December 31, 2002 and does not require previously issued financial statements to be restated. We will account for exit or disposal activities initiated after December 31, 2002 in accordance with the provisions of SFAS 146.

Note 2—Proposed Spin-Off of PXP and Terminated Public Equity Offering

On May 22, 2002 we received a favorable private letter ruling from the Internal Revenue Service (the “IRS”), stating that, for United States federal income tax purposes, a distribution of the capital stock of PXP to our stockholders would generally be tax-free to both us and our stockholders. We call this proposed distribution the “spin-off.”

We expect to announce a record date for the spin-off before the end of November 2002, after final approvals are received from the IRS and the SEC. Upon distribution, the shares of PXP are expected to trade on the New York Stock Exchange under the symbol “PXP.”

On June 21, 2002 PXP filed a registration statement on Form S-1 with the Securities and Exchange Commission, or SEC, for the initial public offering, or IPO, of PXP’s common stock. We terminated the IPO in October 2002, primarily due to market conditions. As a result, costs and expenses of $1.7 million incurred in connection with the IPO were charged to expense during the third quarter of 2002.

Note 3—Investment in PAA

Our investment in PAA is accounted for using the equity method of accounting, under which we record only our proportionate share of PAA’s results of operations, adjusted for the effect of general partner incentive distributions, and other comprehensive income.

In August 2002, PAA issued 6.3 million common units in a public equity offering. We recognized a gain of $14.5 million resulting from the increase in the book value of our equity in PAA to reflect our proportionate share of the increase in the underlying net assets of PAA due to the sale of the units. As a result of the offering, we made a general partner capital contribution of approximately $1.3 million, and our aggregate ownership interest in PAA was reduced to approximately 25%.

At September 30, 2002, our aggregate ownership interest in PAA was 25%. Our ownership interest consisted of: (i) a 44% ownership interest in the 2% general partner interest and incentive distribution rights, (ii) 45%, or approximately 4.5 million, of the Subordinated Units and (iii) 20% or approximately 7.9 million of the common units (including approximately 1.3 million Class B common units).

PLAINS RESOURCES INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

The following table presents unaudited summarized financial statement information of PAA (in thousands of dollars):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2002		2001		2002		2001
Revenues	$	2,344,089	$	2,191,310	$	5,874,759	$	5,298,051
Cost of sales and operations		2,299,823		2,151,666		5,750,398		5,189,288
Gross margin		44,266		39,644		124,361		108,763
Net income		16,317		15,161		47,549		35,243

					At Sep. 30, 2002		At Dec. 31, 2001
Current assets					$	582,352	$	558,082
Property and equipment, net						944,914		604,919
Pipeline linefill						51,416		57,367
Other assets						52,808		40,883
Total assets						1,631,490		1,261,251
Current liabilities						600,145		505,160
Long-term debt						509,053		351,677
Other long-term liabilities						4,317		1,617
Partners’ capital						517,975		402,797
Total liabilities and partners’ capital						1,631,490		1,261,251

Note 4—Derivative Instruments and Hedging Activities

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”). Under SFAS 133, all derivative instruments are recorded on the balance sheet at fair value. If the derivative does not qualify as a hedge or is not designated as a hedge, the gain or loss on the derivative is recognized currently in earnings. If the derivative qualifies for hedge accounting, the unrealized gain or loss on the derivative is deferred in accumulated Other Comprehensive Income (“OCI”), a component of Stockholders’ Equity. At September 30, 2002 all open positions qualified for hedge accounting.

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

At December 31, 2001, OCI consisted of $27.4 million ($16.6 million, net of tax) of unrealized gains on our open crude oil hedging instruments, $3.8 million ($2.3 million, net of tax) equity in the unrealized OCI losses of PAA and a $0.7 million ($0.4 million, net of tax) loss related to our interest rate swap and certain pension adjustments. As oil prices increased significantly during the first nine months of 2002 the fair value of our open crude oil hedging positions decreased $59.5 million ($35.6 million after tax). At September 30, 2002, OCI consisted of $24.6 million ($14.5 million after tax) of unrealized losses on our open crude oil hedging instruments, $2.9 million ($1.7 million, net of tax) equity in the unrealized OCI losses of PAA and a $1.0 million ($0.6 million, net of tax) loss related to our interest rate swap and certain pension adjustments. At September 30, 2002 the assets and

0PLAINS RESOURCES INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

liabilities related to our open crude oil hedging instruments were included in other assets ($2.2 million), current liabilities ($25.0 million), other long-term liabilities ($1.8 million) and deferred income taxes (a tax benefit of $10.1 million).

During the first nine months of 2002, $7.5 million ($4.4 million net of tax) in losses from the settlement of crude oil hedging instruments were reclassified from OCI and charged to income as a reduction of oil sales revenues. Oil sales revenues for the period have also been reduced by a $1.0 million non-cash expense related to the amortization of option premiums. As of September 30, 2002, $14.7 million of deferred net losses on derivative instruments recorded in OCI are expected to be reclassified to earnings during the next twelve-month period.

We utilize various derivative instruments to hedge our exposure to price fluctuations on crude oil sales. The derivative instruments consist primarily of cash-settled crude oil option and swap contracts entered into with financial institutions. We do not currently have any natural gas hedges. We also utilize interest rate swaps and collars to manage the interest rate exposure on our long-term debt. We currently have an interest rate swap agreement that expires in October 2004, under which we receive LIBOR and pay 3.9% on a notional amount of $7.5 million. The interest rate swap fixes the interest rate on $7.5 million of borrowings under our credit facility at 3.9% plus the LIBOR margin set forth in the credit facility (5.3% at September 30, 2002).

Our average realized price for crude oil is sensitive to changes in location and quality differential adjustments as set forth in our crude oil sales contracts. At September 30, 2002 we had basis risk swap contracts on our Illinois Basin production through September 30, 2003. The swaps fix the location differential portion of 2,600 barrels per day at $0.38, $0.43, $0.57, and $0.39 per barrel for the fourth quarter of 2002, and the first, second and third quarters of 2003, respectively .

At September 30, 2002 we had the following open crude oil hedge positions (barrels per day):

	4th Qtr 2002	2003	2004
Puts
Average price $20.00/bbl	2,000	—	—
Calls
Average price $35.17/bbl	9,000	—	—
Collars
Average floor price of $22.00/bbl
Average cap price of $27.04/bbl	—	2,000	—
Swaps
Average price $24.22/bbl	20,000	—	—
Average price $23.43/bbl	—	15,750	—
Average price $23.53/bbl	—	—	12,500

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

PLAINS RESOURCES INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Note 5—Comprehensive Income

Comprehensive income includes net income and certain items recorded directly to Stockholders’ Equity and classified as OCI. The following table reflects comprehensive income for the three and nine months ended September 30, 2002 and 2001 (in thousands of dollars):

	Three Months Ended September 30,						Nine Months Ended September 30,
	2002			2001			2002			2001
Net Income	$	11,185		$	15,154		$	27,455		$	134,222

Other Comprehensive Income (Loss)
Cumulative effect of change in accounting principle—January 1, 2001		—			—			—			6,856
Reclassification adjustment for settled contracts		4,367			113			4,414			1,916
Change in fair value of open hedging positions		(9,924	)		7,106			(35,630	)		(2,243	)
Equity in OCI changes of PAA		(1,388	)		(1,077	)		616			(2,265	)
Interest rate swap and other		(113	)		—			(175	)		—

Other Comprehensive Income (Loss)		(7,058	)		6,142			(30,775	)		4,264

Comprehensive Income (Loss)	$	4,127		$	21,296		$	(3,320	)	$	138,486

Note 6—Earnings Per Share

The following is a reconciliation of the numerators and the denominators of the basic and diluted earnings per share computations for income from continuing operations before the cumulative effect of accounting change for the three and nine months ended September 30, 2002 and 2001 (dollar amounts and shares in thousands, except per share data):

	For the Three Months Ended September 30,
	2002						2001
	Income (Numerator)			Shares (Denominator	Per Share Amount		Income (Numerator)			Shares (Denominator)	Per Share Amount
Income before cumulative effect of accounting change	$	11,185					$	15,154
Less: preferred stock dividends		(350	)					(350	)

Income available to common stockholders		10,835		23,956	$	0.45		14,804		23,464	$	0.63

Effect of dilutive securities:
Convertible preferred stock		350		932				350		1,790
Employee stock options and warrants		—		661				—		973

Income available to common stockholders assuming dilution	$	11,185		25,549	$	0.44	$	15,154		26,227	$	0.58

PLAINS RESOURCES INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

	For the Nine Months Ended September 30,
	2002						2001
	Income (Numerator)			Shares (Denominator	Per Share Amount		Income (Numerator)			Shares (Denominator)	Per Share Amount
Income before cumulative effect of accounting change	$	27,455					$	136,208
Less: preferred stock dividends		(1,050	)					(26,896	)

Income available to common stockholders		26,405		23,826	$	1.11		109,312		20,204	$	5.41

Effect of dilutive securities:
Convertible preferred stock		1,050		932				3,015		6,790
Employee stock options and warrants		—		629				—		910

Income available to common stockholders assuming dilution	$	27,455		25,387	$	1.08	$	112,327		27,904	$	4.03

The $2.0 million cumulative effect of accounting change, net of tax benefit, recognized in the first quarter of 2001 resulted in a reduction in our basic and diluted earnings per share for the nine months ended September 30, 2001 of $0.10 and $0.08, respectively.

Note 7—Long-Term Debt

At June 30, 2002, long-term debt consisted of (i) $17.5 million outstanding under Plains Resources’ revolving credit facility (the “Plains credit facility”) and (ii) $267.5 million principal amount of our 10.25% Senior Subordinated Notes (the “10.25% notes”).

On July 3, 2002, PXP and Plains E&P Company (a wholly owned subsidiary of PXP that has no material assets and was formed for the sole purpose of being a corporate co-issuer of certain notes) issued $200.0 million principal amount of 8.75% Senior Subordinated Notes due 2012 (the “8.75% notes”) at an issue price of 98.376%. The 8.75% notes are PXP’s unsecured general obligations, are subordinated in right of payment to all of PXP’s existing and future senior indebtedness and are jointly and severally guaranteed on a full, unconditional basis by all of PXP’s existing and future domestic restricted subsidiaries Also on July 3, 2002 PXP entered into a $300.0 million credit facility with a $225.0 million borrowing base (the “PXP credit facility”).

The proceeds from the 8.75% notes, $195.3 million after deducting $3.2 million in issue discount and $1.5 million in underwriting fees, and $117.6 million initially borrowed under the PXP credit facility were used to: (i) redeem the 10.25% notes; (ii) retire the $25.0 million outstanding under the Plains credit facility on July 3, 2002; and (iii) pay $0.9 million in fees related to the PXP credit facility. Upon payment of the amount outstanding under the Plains credit facility, that agreement was terminated. The portion of the proceeds used to redeem the 10.25% notes consisted of: (i) the $267.5 million principal amount; (ii) a $9.1 million call premium due as a result of the early redemption of the notes; and (iii) $10.4 million in interest accrued and payable on the redemption date. All of the outstanding 10.25% notes were redeemed on August 3, 2002 and all guarantees with respect to the 10.25% notes were terminated. In connection with the redemption of the 10.25% notes and the termination of the Plains credit facility, in the third quarter of 2002 we recognized a $10.3 million charge to income for debt extinguishment costs.

PLAINS RESOURCES INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

As of September 30, 2002 $90.7 million was outstanding under the PXP credit facility. The PXP credit facility provides for a borrowing base of $225.0 million that will be reviewed every six months, with the lenders and PXP each having the right to one annual interim unscheduled redetermination, and adjusted based on PXP’s oil and gas properties, reserves, other indebtedness and other relevant factors, and matures in 2005. Additionally, the PXP credit facility contains a $30.0 million sub-limit on letters of credit (of which $5.2 million had been issued as of September 30, 2002). To secure borrowings, PXP pledged 100% of the shares of stock of its domestic subsidiaries and gave mortgages covering 80% of the total present value of its domestic oil and gas properties.

Amounts borrowed under the PXP credit facility bear an annual interest rate, at PXP’s 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 JPMorganChase 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) PXP’s long-term debt rating. Commitment fees and letter of credit fees under the PXP 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 will receive an issuing fee of 0.125% of the undrawn amount.

The PXP credit facility contains negative covenants that limit PXP’s ability, as well as the ability of its subsidiaries, to make dividends to Plains Resources or enter into other transactions with Plains Resources and its subsidiaries (other than PXP and its subsidiaries). In addition, the PXP credit facility, among other things, limits PXP’s ability to incur additional debt, pay dividends on stock, make distributions of cash or property, change the nature of its 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 PXP credit facility requires PXP 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 September 30, 2002, PXP was in compliance with the covenants contained in the PXP credit facility and could have borrowed the full $225.0 million available under the PXP credit facility.

The 8.75% notes are PXP’s unsecured general obligations, are subordinated in right of payment to all of PXP’s existing and future senior indebtedness and are jointly and severally guaranteed on a full, unconditional basis by all of PXP’s existing and future domestic restricted subsidiaries. The indenture governing the notes limits PXP’s ability to make dividends to us or enter into other transactions with us and our subsidiaries (other than PXP and its subsidiaries). The indenture also limits PXP’s ability, as well as the ability of its 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, PXP will be required to make an offer to repurchase the

PLAINS RESOURCES INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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 will permit the spin-off and the spin-off will 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 PXP’s 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 8—Commitments and Contingencies

In connection with the sale of a portion of our interest in PAA in June 2001, we entered into a value assurance agreement with each of the purchasers of PAA subordinated units. In the event PAA’s annual distribution is less than $1.85 per unit on its subordinated units, the value assurance agreements require us to pay to the purchasers an amount per fiscal year, payable on a quarterly basis, equal to the difference between $1.85 per unit and the actual amount distributed during that period. The value assurance agreements will expire upon the earlier of the conversion of the subordinated units to common units, or June 8, 2006.

Also in connection with the June 2001 sale of a portion of our interest in PAA, we entered into a separation agreement with PAA whereby, among other things, (1) we agreed to indemnify PAA, its general partner, and its subsidiaries against (a) any claims related to the upstream business, whenever arising, and (b) any claims related to federal or state securities laws or the regulations of any self-regulatory authority, or other similar claims, resulting from alleged acts or omissions by us, our subsidiaries, PAA, or PAA’s subsidiaries occurring on or before June 8, 2001, and (2) PAA agreed to indemnify us and our subsidiaries against any claims related to the midstream business, whenever arising.

Under the amended terms of an asset purchase agreement with respect to certain of our onshore California properties, commencing with the year beginning January 1, 2000, and each year thereafter, we are required to plug and abandon 20% of the then remaining inactive wells, which currently aggregate approximately 149. To the extent we elect not to plug and abandon the number of required wells, we are required to escrow an amount equal to the greater of $25,000 per well or the actual average plugging cost per well in order to provide for the future plugging and abandonment of such wells. In addition, we are required to expend a minimum of $600,000 per year in each of the ten years beginning January 1, 1996, and $300,000 per year in each of the succeeding five years to remediate oil contaminated soil from existing well sites, provided there are remaining sites to be remediated. In the event we do not expend the required amounts during a calendar year, we are required to contribute an amount equal to 125% of the actual shortfall to an escrow account. We may withdraw amounts from the escrow account to the extent we expend excess amounts in a future year. Through September 30, 2002, we have not been required to make contributions to an escrow account.

In connection with the acquisition of our interests in the Point Arguello field, offshore California, we assumed our 52.6% share of (1) plugging and abandoning all existing well bores, (2) removing conductors, (3) flushing hydrocarbons from all lines and vessels and (4) removing/abandoning all structures, fixtures and conditions created subsequent to closing. The seller retained the obligation for all other abandonment costs, including but not limited to (1) removing, dismantling and disposing of the existing offshore platforms, (2) removing and disposing of all existing pipelines and (3) removing, dismantling, disposing and remediation of all existing onshore facilities.

PLAINS RESOURCES INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Although we obtained environmental studies on our properties in California and Illinois and we believe that such properties have been operated in accordance with standard oil field practices, certain of the fields have been in operation for more than 90 years, and current or future local, state and federal environmental laws and regulations may require substantial expenditures to comply with such rules and regulations. In connection with the purchase of certain of our onshore California properties, we received a limited indemnity for certain conditions if they violate applicable local, state and federal environmental laws and regulations in effect on the date of such agreement. We believe that we do not have any material obligations for operations conducted prior to our acquisition of the properties, other than our obligation to plug existing wells and those normally associated with customary oil field operations of similarly situated properties. There can be no assurance that current or future local, state or federal rules and regulations will not require us to spend material amounts to comply with such rules and regulations or that any portion of such amounts will be recoverable under the indemnity.

Consistent with normal industry practices, substantially all of our crude oil and natural gas leases require that, upon termination of economic production, the working interest owners plug and abandon non-producing wellbores, remove tanks, production equipment and flow lines and restore the wellsite. Based on our year-end 2001 reserve reports we estimate that the costs to perform these tasks is approximately $24.4 million, net of salvage value and other considerations.

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

On September 18, 2002 Stocker Resources Inc., or Stocker, our wholly-owned subsidiary, filed a declaratory judgment action against Commonwealth Energy Corporation (doing business as electricAmerica), or Commonwealth, in the Superior Court of Orange County, California relating to the termination of an electric service contract between Stocker and Commonwealth. Pursuant to the agreement, Commonwealth had agreed to supply Stocker with electricity and Stocker had obtained a $1.5 million performance bond in favor of Commonwealth to secure its payment obligations under the agreement. Stocker terminated the contract in accordance with its terms and Commonwealth notified Stocker of its intent to draw upon the performance bond. 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 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 alleges that Stocker breached the terms of the contract by the termination and its implied covenant of good faith and fair dealing and is seeking unspecified damages. Under a master separation agreement that we entered into with PXP in connection with the proposed spin-off, PXP is required to indemnify Stocker and us for damages we or Stocker incur as a result of this action. At this time we are not in a position to express a judgment concerning the potential exposure or likely outcome of this matter. We intend to vigorously defend this matter.

In the ordinary course of our business, we are a claimant and/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 materially adverse effect on our financial condition, results of operations or cash flows.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

General

The following updates information as to our financial condition provided in our Form 10-K for the year ended December 31, 2001, and analyzes the changes in the results of operations between the three and nine month periods ended September 30, 2002 and the comparable periods in 2001. There have been no significant changes in our business or properties during the first nine months of 2002.

The following are abbreviations and definitions of certain terms commonly used in the oil and gas industry:


Bbl		One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons.

BOE		One stock tank barrel equivalent of oil, calculated by converting gas volumes to equivalent oil barrels at a ratio of 6 Mcf to 1 Bbl of oil.

Differential		An adjustment to the price of oil to reflect differences in the quality and/or location of oil.

Gas		Natural gas.

MBbl		One thousand barrels of oil or other liquid hydrocarbons.

MBOE		One thousand BOE.

Mcf		One thousand cubic feet of gas.

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

MMBbl		One million barrels of oil or other liquid hydrocarbons.

MMBOE		One million BOE.

MMcf		One million cubic feet of gas.

NYMEX		New York Mercantile Exchange.

Oil		Crude oil, condensate and natural gas liquids.

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

We follow the full cost method of accounting whereby all costs associated with property acquisition, exploration, exploitation and development activities are capitalized. 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 field personnel, 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.

Financings

On July 3, 2002, Plains Exploration & Production Company, L.P., or PXP, and Plains E&P Company (both of which are wholly owned subsidiaries) issued in a private offering, at an issue price of 98.376%, $200.0 million of 8.75% Senior Subordinated Notes due 2012, or the 8.75% notes. The 8.75% notes are PXP’s unsecured general obligations, are subordinated in right of payment to all of PXP’s existing and future senior indebtedness and are jointly and severally guaranteed on a full, unconditional basis by all of PXP’s existing and future domestic restricted subsidiaries. Also on July 3, 2002 PXP entered into a $300.0 million revolving credit facility with a $225.0 million borrowing base, or the PXP credit facility. PXP conducts our upstream onshore and offshore California and Illinois operations.

The proceeds from the 8.75% notes, $195.3 million after deducting issue discount and underwriting fees, and $117.6 million initially borrowed under the PXP credit facility were used to: (i) redeem $267.5 million of outstanding 10.25% Senior Subordinated Notes, or the 10.25% notes; (ii) retire the $25.0 million outstanding under Plains Resources’ credit facility, or the Plains credit facility on July 3, 2002; and (iii) pay $0.9 million in fees related to the PXP credit facility. All outstanding 10.25% notes were redeemed on August 3, 2002 and all guarantees with respect to the 10.25% notes were terminated. Upon payment of the amount outstanding under the Plains credit facility, that agreement was terminated.

On October 25, 2002, PXP filed a registration statement on Form S-4 with the Securities and Exchange Commission, or SEC, to exchange all of the 8.75% notes issued in the private offering for a new series of 8.75% notes. The terms of the new series of 8.75% notes are substantially identical to the terms of the privately issued 8.75% notes except that the new series will be freely transferable and issue free of any covenants regarding exchange and registration rights.

For a complete discussion of these transactions and the terms and conditions of the 8.75% notes and the PXP credit facility, see “Liquidity and Capital Resources—Debt”.

Proposed Spin-off of PXP and Terminated Initial Public Offering

On May 22, 2002 we received a favorable private letter ruling from the Internal Revenue Service, or IRS, stating that, for United States federal income tax purposes, a distribution of the capital stock of PXP to our stockholders will generally be tax-free to both us and our stockholders. We call this proposed distribution the “spin-off.”

The spin-off will, among other things, generally divide our Midstream and Upstream assets into two separate entities, allowing us and PXP to focus corporate strategies and management teams for each business and simplify our corporate structure. For further discussion of the spin-off and the agreements related thereto, see “Spin-off”.

On June 21, 2002 PXP filed a registration statement on Form S-1 with the SEC for the initial public offering, or IPO, of PXP’s common stock. We terminated the IPO in October 2002, primarily due to market conditions. As a result, costs and expenses of $1.7 million incurred in connection with the IPO were charged to expense during the third quarter of 2002. We estimate that additional charges of $0.7 million to $0.8 million will occur during the fourth quarter of 2002.

Purchase of Additional Interest in Point Arguello Unit

In August 2002 we acquired an additional 26.3% working interest in the Point Arguello unit and the various partnerships owning the related transportation, processing and marketing infrastructure. The seller retained responsibility for certain abandonment costs, including: (1) removing, dismantling and disposing of the existing offshore platforms; (2) removing and disposing of all pipelines; and (3) removing, dismantling, disposing and remediating all existing onshore facilities. We assumed the seller’s share of the costs of plugging the wells and flushing the lines. As consideration for receiving the transferred properties and assuming the obligations described above, we received $2.4 million in cash for the sale and $3.0 million as our share of revenues less costs for the period from April 1 to July 30, 2002. This transaction doubled our working interest in the Point Arguello unit to 52.6%.

Results of Operations

The following tables reflect our oil and gas production and sales volumes, the components of our oil and gas revenues and set forth our revenues and costs and expenses on a BOE basis:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2002			2001			2002			2001
Production Volumes
Oil and liquids (MBbls)		2,551			2,354			7,141			6,798
Natural Gas (MMcf)		821			872			2,540			2,499
MBOE		2,688			2,499			7,564			7,215
Sales Volumes
Oil and liquids (MBbls)		2,545			2,362			7,076			6,825
Natural Gas (MMcf)		821			872			2,540			2,499
MBOE		2,682			2,507			7,499			7,242
Daily Average Sales Volumes
Oil and Liquids (Bbls)
Onshore California		16,917			16,435			16,775			15,703
Offshore California		5,838			3,954			4,241			3,755
Illinois		2,463			2,684			2,547			2,727
Florida		2,439			2,605			2,355			2,816

		27,657			25,678			25,918			25,001

Natural Gas (Mcf)
Onshore California		8,924			9,482			9,303			9,155

BOE		29,144			27,258			27,469			26,527

Unit Economics (in dollars)
Average Liquids Sales Price ($/Bbl)
Average NYMEX	$	28.25		$	26.78		$	25.45		$	27.81
Hedging revenue (cost)		(3.06	)		0.36			(1.20	)		(0.97	)
Differential		(4.54	)		(5.65	)		(4.37	)		(5.82	)

Net realized	$	20.65		$	21.49		$	19.88		$	21.02

Average Gas Sales Price ($/Mcf)	$	3.11		$	3.84		$	2.81		$	10.75
Average Sales Price per BOE	$	20.55		$	21.58		$	19.71		$	23.52
Average Production Costs per BOE		(8.76	)		(7.60	)		(8.20	)		(7.33	)

Gross Margin per BOE		11.79			13.98			11.51			16.19
G&A per BOE(1)		(1.47	)		(1.09	)		(1.61	)		(2.53	)

Gross Profit per BOE	$	10.32		$	12.89		$	9.90		$	13.66

DD&A per BOE (oil and gas properties)	$	3.10		$	2.64		$	3.10		$	2.64

(1)

Total general and administrative expense per BOE. G&A per BOE excluding noncash compensation expense,nonrecurring items associated with our June 2001 strategic reorganization and costs associated with our spinoff was $1.14 and $1.03 for the three months ended September 30, 2002 and 2001, respectively, and $1.30 and $1.29 for the nine months ended September 2002 and 2001, respectively.

Comparison of three months ended September 30, 2002 to three months ended September 30, 2001

Operating revenues

Our operating revenues increased 2%, or $0.9 million, to $55.1 million for the three months ended September 30, 2002 from $54.2 million for the three months ended September 30, 2001. The increase was primarily due to higher production volumes attributable to the additional interest we acquired in the Point Arguello Unit, which are included in sales volumes effective August 1, 2002. Higher volumes increased revenues by $4.1 million. Lower realized prices for oil and gas reduced revenues by $3.2 million.

Our daily oil sales volumes increased 8%, or 2.0 MBbls, to 27.7 MBbls per day for the three months ended September 30, 2002 from 25.7 MBbls for the three months ended September 30, 2001 primarily due to the additional interest we acquired in the Point Arguello Unit. Our daily gas sales volumes decreased 6%, or 0.6 MMcf, to 8.9 MMcf per day for the three months ended September 30, 2002 from 9.5 MMcf per day for the three months ended September 30, 2001.

Our average realized price for oil and natural gas liquids decreased 4%, or $0.84, to $20.65 per Bbl for the three months ended September 30, 2002 from $21.49 per Bbl for the three months ended September 30, 2001. The average NYMEX oil price increased 5%, or $1.47, to $28.25 per Bbl for the three months ended September 30, 2002 from $26.78 per Bbl for the three months ended September 30, 2001. Additionally, we experienced a 20%, or $1.11 per Bbl improvement in location and quality differentials. Offsetting these increases were hedging costs of $3.06 per Bbl for the three months ended September 30, 2002. Revenues for the third quarter of 2001 include hedging revenues of $0.36 per Bbl. The average realized price for gas decreased 19%, or $0.73, to $3.11 per Mcf for the three months ended September 30, 2002 from $3.84 per Mcf in 2001.

Production expenses

Our production expenses increased 23%, or $4.4 million, to $23.5 million for the three months ended September 30, 2002 from $19.1 million for the three months ended September 30, 2001. Approximately $2.0 million of the increase is attributable to the additional interest we acquired in the Point Arguello Unit. On a per unit basis, production expenses increased 15%, or $1.16, to $8.76 per BOE for the three months ended September 30, 2002 from $7.60 per BOE for the three months ended September 30, 2001, primarily due to increased electric costs for our onshore California operations as well as increased well maintenance and insurance expense.

General and administrative expense

Our general and administrative expense, or G&A expense, increased 44%, or $1.2 million, to $3.9 million for the three months ended September 30, 2002 from $2.7 million for the three months ended September 30, 2001. G&A expense for 2002 includes $0.6 million of nonrecurring costs primarily related to our proposed spin-off. Excluding nonrecurring items, G&A expense increased from $2.9 million in 2001 to $3.3 million in 2002.

Depreciation, depletion and amortization

Our depreciation, depletion and amortization, or DD&A expense increased 21%, or $1.5 million, to $8.7 million for the three months ended September 30, 2002 from $7.1 million for the three months ended September 30, 2001. Approximately $0.6 million of the increase was due to higher production volumes. The remaining increase was due to an increase in the oil and gas DD&A rate, to $3.10 per BOE for the three months ended September 30, 2002 from $2.64 per BOE for the three months ended September 30, 2001. The increase in 2002 is primarily due to the increase in costs subject to DD&A as a result of our 2001 capital program.

Equity in earnings of Plains All American Pipeline, L.P. (PAA)

Our equity in earnings of PAA decreased 14%, or $0.7 million, to $4.5 million for the three months ended September 30, 2002 from $5.2 million for the three months ended September 30, 2001. The decrease is primarily due to a lower ownership interest in PAA in the current quarter. We currently hold a 25% ownership interest compared to 33% in the third quarter of 2001. PAA reported earnings of $16.3 million for the three months ended September 30, 2002 compared to $15.2 million for the three months ended September 30, 2001.

Gain on PAA units

Our 2002 gain of $14.5 million was due to the increase in the book value of our equity in PAA to reflect our proportionate share of the increase in the underlying net assets of PAA resulting from PAA’s public equity offering during the quarter. Our 2001 gain of $0.9 million was from our sale of a 2% ownership interest in the general partner of PAA.

Loss on debt extinguishment

We incurred a $10.3 million loss for the three months ended September 30, 2002, primarily from the early retirement of $267.5 million of outstanding 10.25% notes. The expense included a call premium of 3.4167% on the outstanding principal amount of the 10.25% notes, or $9.1 million, and $1.2 million related to unamortized issue costs on the 10.25% notes and the Plains credit facility, net of unamortized premiums on the 10.25% notes.

Expenses of terminated public equity offering

In conjunction with the termination of our proposed public equity offering of PXP shares we expensed costs incurred as of September 30, 2002 of $1.7 million.

Interest expense

Our interest expense increased 16%, or $1.0 million, to $7.3 million for the three months ended September 30, 2002 from $6.3 million for the three months ended September 30, 2001. In 2002 we incurred additional interest expense of approximately $2.2 million, as we paid interest on both the 8.75% notes and the 10.25% notes for 30 days, offset partially by a reduced aggregate borrowing rate during the current period.

Income tax expense

Our income tax expense decreased $2.3 million to $7.7 million for the three months ended September 30, 2002 from $10.0 million for the three months ended September 30, 2001. The decrease was primarily due to decreases in pre-tax income, partially offset by an increase in our effective tax rate. Our effective tax rate was 40.9% for the three months ended September 30, 2002 as compared to 39.7% for the three months ended September 30, 2001.

Comparison of nine months ended September 30, 2002 to nine months ended September 30, 2001

Operating revenues

Our operating revenues decreased 13%, or $23.0 million, to $147.8 million for the nine months ended September 30, 2002 from $170.8 million for the nine months ended September 30, 2001. The decrease was primarily due to lower realized prices for oil and gas that reduced revenues by $26.1 million. Higher volumes increased revenues by $5.4 million.

Our daily oil sales volumes increased 4%, or 0.9 MBbls, to 25.9 MBbls per day for the nine months ended September 30, 2002 from 25.0 MBbls for the nine months ended September 30, 2001 primarily due to the additional interest we acquired in the Point Arguello Unit. Our daily gas sales volumes increased 2%, or 0.1 MMcf, to 9.3 MMcf per day for the nine months ended September 30, 2002 from 9.2 MMcf per day for the nine months ended September 30, 2001.

Our average realized price for oil and natural gas liquids decreased 5%, or $1.14, to $19.88 per Bbl for the nine months ended September 30, 2002 from $21.02 per Bbl for the nine months ended September 30, 2001. The average NYMEX oil price decreased 8%, or $2.36, to $25.45 per Bbl for the nine months ended September 30, 2002 from $27.81 per Bbl for the nine months ended September 30, 2001. An increase in our hedging cost per barrel, from $0.97 per barrel for the nine months ended September 30, 2001 to $1.20 per barrel for the same period in 2002 was partially offset by a 25%, or $1.45 per Bbl improvement in location and quality differentials over the same periods. The average realized price for gas decreased 74%, or $7.94, to $2.81 per Mcf for the nine months ended September 30, 2002 from $10.75 per Mcf in 2001. Gas prices were unusually high in 2001, particularly in California.

Production expenses

Our production expenses increased 16%, or $8.4 million, to $61.5 million for the nine months ended September 30, 2002 from $53.1 million for the nine months ended September 30, 2001. On a per unit basis, production expenses increased 12%, or $0.87 per BOE, to $8.20 per BOE for the nine months ended September 30, 2002 from $7.33 per BOE for the nine months ended September 30, 2001. Production expenses for 2001 were reduced by approximately $0.30 per BOE as a result of nonrecurring credits (primarily the sale of certain California emissions credits). Excluding these credits, production expenses increased 7% per BOE during the period, primarily due to higher electricity costs in California and our increased ownership percentage in the Point Arguello Unit.

General and administrative expense

G&A expense decreased 34%, or $6.3 million, to $12.0 million for the nine months ended September 30, 2002 from $18.3 million for the nine months ended September 30, 2001. G&A expense for 2002 includes $1.6 million of nonrecurring costs primarily related to our proposed spin-off and our 2001 strategic reorganization. G&A expense for 2001 includes $8.8 million of nonrecurring noncash compensation and other costs incurred in conjunction with our strategic reorganization that was completed in September 2001. Excluding nonrecurring items G&A expense increased $0.9 million, primarily reflecting noncash compensation costs related to stock options and grants.

Depreciation, depletion and amortization

DD&A increased 19%, or $4.0 million, to $24.5 million for the nine months ended September 30, 2002 from $20.5 million for the nine months ended September 30, 2001 primarily due to an increase in the oil and gas DD&A rate to $3.10 per BOE for the nine months ended September 30, 2002 from $2.64 per BOE for the nine months ended September 30, 2001. The increase was primarily due to the increase in costs subject to DD&A as a result of our 2001 capital program.

Equity in earnings of Plains All American Pipeline, L.P.

Our equity in earnings of PAA decreased 11%, or $1.7 million, to $14.1 million for the nine months ended September 30, 2002 from $15.8 million for the nine months ended September 30, 2001 primarily due to a lower ownership percentage. PAA reported earnings of $47.5 million for the nine months ended September 30, 2002 compared to $35.2 million for the nine months ended September 30, 2001.

Our ownership interest in PAA decreased from approximately 54% at January 1, 2001 to approximately 33% at June 30, 2001. Our ownership interest was approximately 30% at January 1, 2002 and decreased to approximately 25% in August 2002.

Gain on PAA units

Our 2002 gain of $14.5 million was due to the increase in the book value of our equity in PAA to reflect our proportionate share of the increase in the underlying net assets of PAA resulting from PAA’s August 2002 public equity offering. Our 2001 gains of $151.1 million related to the sale of a portion of our investment in PAA in connection with our 2001 strategic reorganization and PAA’s May and October 2001 equity offerings.

Loss on debt extinguishment

We incurred a $10.3 million loss for the nine months ended September 30, 2002, primarily from the early retirement of $267.5 million of outstanding 10.25% notes. The expense included a call premium of 3.4167% on the outstanding principal amount of the 10.25% notes, or $9.1 million, and $1.2 million related to unamortized issue costs of the 10.25% notes and the Plains credit facility, net of unamortized premiums on the 10.25% notes.

Expenses of terminated public equity offering

In conjunction with the termination of our proposed public equity offering of PXP shares we expensed costs incurred as of September 30, 2002 of $1.7 million.

Interest expense

Our interest expense increased to $20.2 million for the nine months ended September 30, 2002 from $20.1 million for the nine months ended September 30, 200. In 2002 we incurred additional interest expense of approximately $2.2 million, as we paid interest on both the 8.75% notes and the 10.25% notes for 30 days, offset by lower amounts owed on our revolving credit facility and lower interest rates.

Income tax expense

Our income tax expense decreased $70.5 million to $19.0 million for the nine months ended September 30, 2002 from $89.5 million for the nine months ended September 30, 2001. The decrease was primarily due to a decrease in pre-tax income, partially offset by an increase in our effective tax rate. Our effective tax rate was 40.9% for the nine months ended September 30, 2002 as compared to 39.7% for the nine months ended September 30, 2001. Current income tax expense for the first nine months of 2002 includes a benefit of approximately $2.9 million representing taxes paid in 2001 that have been refunded to us under terms of recent legislation. Such legislation allows us to offset 100% of alternative minimum taxable income with net operating loss carryforwards (“NOL’s”) for 2001 and 2002. Previously, we could only offset 90% of AMT income with NOL’s. The current income tax expense benefit is offset by a corresponding charge to deferred income tax expense. This change in the regulations did not change our overall effective tax rate and had no effect on net income.

Liquidity and Capital Resources

General

Cash generated from our upstream operations, PAA distributions and the PXP credit facility are our primary sources of liquidity. We believe that we have sufficient liquid assets, cash from operations and borrowing capacity under our credit facility to meet our short term normal recurring operating needs, debt service obligations, contingencies and anticipated capital expenditures. We also believe

that we have sufficient liquid assets, cash from operations and borrowing capacity under the PXP credit facility to meet our long term normal recurring operating needs, contingencies and anticipated capital expenditures.

At September 30, 2002 we had a working capital deficit of approximately $41.0 million. Approximately $24.5 million of the working capital deficit is attributable to the fair value of our hedges. 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 sale of physical production will be based on actual market prices and will generally offset any gains or losses on the hedge instruments.

We expect capital expenditures for the remainder of 2002 to be in the range of $14.0 million to $15.0 million, which will be funded by cash generated by operations and the PXP credit facility.

In the first nine months of 2002 we received cash distributions from PAA of $21.6 million, including $1.6 million for our 44% interest in the general partner. Based on the $0.5375 per unit distribution recently declared by PAA, the distribution we will receive in the fourth quarter of 2002 will be approximately $7.5 million, including $0.7 million for our 44% interest in the general partner.

Cash provided by operating activities for the first nine months of 2002 totaled $54.1 million, after a reduction of $9.1 million for debt extinguishment costs related to the retirement of the 10.25% notes. Cash used in investing activities of $60.7 million consisted of capital expenditures of $59.4 million and a $1.3 million investment in the general partner of PAA. Cash provided by financing activities of $6.6 million consisted of $79.2 million in net borrowings under our revolving credit facilities, $196.8 million in proceeds from the issuance of PXP’s 8¾% Senior Subordinated Notes due 2012, payments of $268.0 million for retirements of long-term debt, payments of $5.5 million in debt issuance costs, $4.8 million in proceeds from the exercise of stock options, and $0.7 million in preferred stock dividends paid. Cash remained unchanged during the period.

Debt

At June 30, 2002, long-term debt consisted of (i) $17.5 million outstanding under the Plains credit facility and (ii) $267.5 million principal amount of the 10.25% notes.

On July 3, 2002, PXP and Plains E&P Company (a wholly owned subsidiary of PXP that has no material assets and was formed for the sole purpose of being a corporate co-issuer of certain notes) issued $200.0 million of the 8.75% notes at an issue price of 98.376%. The 8.75% notes are PXP’s unsecured general obligations, are subordinated in right of payment to all of PXP’s existing and future senior indebtedness and are jointly and severally guaranteed on a full, unconditional basis by all of PXP’s existing and future domestic restricted subsidiaries. Also on July 3, PXP entered into the $300.0 million PXP credit facility that has a $225.0 million borrowing base.

notes were redeemed on August 3, 2002 and all guarantees with respect to the 10.25% notes were terminated. In connection with the redemption of the 10.25% notes and the termination of the Plains credit facility, in the third quarter of 2002 we recognized a $10.3 million charge to income for debt extinguishment costs.

repurchase. The indenture governing the 8.75% notes will permit the spin-off and the spin-off will not, in itself, constitute a change of control for purposes of the indenture.

PXP has been assigned a Ba3 senior implied rating and the 8.75% notes have been assigned a B2 rating by Moody’s Investor Service Inc. PXP has also been assigned a BB– corporate credit rating, on credit watch with negative implications, by Standard and Poor’s Ratings Group, all of which are below investment grade. As a result, at times PXP may have difficulty raising capital on favorable terms.

Investment in PAA

As of September 30, 2002, our aggregate ownership interest in PAA was approximately 25%, which was comprised of (1) a 44% interest in the general partner of PAA, (2) 45%, or approximately 4.5 million, of the subordinated units and (3) 20%, or approximately 7.9 million, of the common units, including approximately 1.3 million class B common units. Based on PAA’s current annual distribution rate of $2.15 per unit, we would receive an annual distribution from PAA of approximately $30.0 million.

Commitments and Contingencies

In exchange for the significant value we received for the PAA subordinated units (which are subordinated in right to distributions from PAA and are not publicly traded) we sold in June 2001 at a price relative to the then current market price of the publicly traded common units, we entered into a value assurance agreement with each of the purchasers of the subordinated units. In the event PAA’s annual distribution on its subordinated units is less than $1.85 per unit, the value assurance agreements require us to pay to the purchasers an amount per fiscal year, payable on a quarterly basis, equal to the difference between $1.85 per unit and the actual amount distributed during that period. The value assurance agreements will expire upon the earlier of the conversion of the subordinated units to common units, or June 8, 2006.

In connection with the June 2001 sale of a portion of our interest in PAA we entered into a separation agreement with PAA whereby, among other things, (1) we agreed to indemnify PAA, its general partner, and its subsidiaries against (a) any claims related to the upstream business, whenever arising, and (b) any claims related to federal or state securities laws or the regulations of any self-regulatory authority, or other similar claims, resulting from alleged acts or omissions by us, our subsidiaries, PAA, or PAA’s subsidiaries occurring on or before June 8, 2001, and (2) PAA agreed to indemnify us and our subsidiaries against any claims related to the midstream business, whenever arising.

At September 30, 2002, the aggregate amounts of contractually obligated payment commitments for the next five years are as follows (in thousands):

	2002		2003		2004		2005		2006		Thereafter
Long-term debt	$	—	$	511	$	511	$	90,700	$	—	$	196,803
Operating leases		150		606		595		573		143		—

	$	150	$	1,117	$	1,106	$	91,273	$	143	$	196,803

The long-term debt amounts consist principally of amounts due under the PXP credit facility and the PXP 8.75% notes.

Although we maintain an inspection program designed to prevent and, as applicable, to detect and address releases of crude oil into the environment from our upstream operations, we may experience such releases in the future, or discover releases that were previously unidentified. Damages and liabilities incurred due to any future environmental releases from our assets may substantially affect our business.

Spin-Off

We entered into the following spin-off agreements to enable us to generally separate our midstream and upstream assets into two separate entities and to spin-off our upstream assets, allowing us and PXP to focus corporate strategies and management teams for each business and simplify our corporate structure.

Master Separation Agreement

Overview. To effect the separation, we entered into a master separation agreement on July 3, 2002 with PXP. The master separation agreement provides for the separation of substantially all of our upstream assets and liabilities, other than our Florida operations. The master separation agreement provides for, among other things:

•

the separation;

•

an initial public offering;

•

the spin-off;

•

corporate governance provisions related to PXP;

•

cross-indemnification provisions;

•

allocation of fees related to these transactions between us and PXP;

•

other provisions governing our relationship with PXP, including mandatory dispute arbitration, sharing information, confidentiality and other covenants;

•

a noncompetition provision; and

•

us entering into the ancillary agreements discussed below with PXP.

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

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

Reorganization. The master separation agreement provides for an internal reorganization by us, including, before the spin-off, the merger of Stocker Resources, Inc. (PXP’s general partner before it converted from a limited partnership to a corporation) into us.

Spin-off. The master separation agreement provides for the spin-off distribution by us of PXP common stock held by us. We are not obligated to effect the spin-off. If we decide to effect the spin-off, each holder of our common stock on the record date would receive a pro rata share of the total shares of PXP common stock held by us.

Corporate governance. The master separation agreement contains several provisions regarding the corporate governance of PXP. First, as long as we own shares representing at least a majority of PXP voting power, we will have the right to designate for nomination by the PXP board of directors, or a nominating committee of the board, a majority of the members of the PXP board. If our beneficial ownership of PXP common stock is reduced to a level below 50% of PXP voting power but is at least 20% of PXP voting power, we will have the right to designate for nomination a number of directors proportionate to our voting power.

Indemnification. The master separation agreement provides for cross-indemnities intended to place sole financial responsibility on PXP for all liabilities associated with the current and historical businesses and operations PXP conducts after giving effect to the separation, regardless of the time those liabilities arise, and to place sole financial responsibility for liabilities associated with our other businesses with us and our other subsidiaries. The master separation agreement also contains indemnification provisions under which we and PXP each indemnify the other with respect to breaches by the indemnifying party of the master separation agreement or any of the ancillary agreements described below. PXP agrees to indemnify us and our other subsidiaries against liabilities arising from misstatements or omissions in the various offering documents for the exchange offer related to the PXP 8.75% notes or the spin-off, including related prospecti or in documents to be filed with the SEC in connection therewith, except for information regarding us provided by us for inclusion in such documents. We agree to indemnify PXP against liabilities arising from misstatements or omissions in the various offering documents for the exchange offer related to the PXP 8.75% notes or the spin-off,

including related prospecti or in documents to be filed with the SEC in connection therewith, if such information was provided by us.

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

Fees. PXP will bear all out-of-pocket costs of the transfers of assets and liabilities in connection with the separation, including costs for providing notices of the transfers, costs for transferring licenses, permits or franchises or for issuing new licenses, permits or franchises in PXP’s name, fees or costs for the assignment or transfer of any agreements or contracts, and any recording or other fees, taxes or charges incurred in connection with transferring real property.

Except as noted above or otherwise specifically addressed in the master separation agreement or an ancillary agreement, PXP shall bear the out-of-pocket costs associated with preparing and consummating the transactions contemplated by the master separation agreement, the ancillary agreements, the separation and the spin-off.

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

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

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

Ancillary agreements. The master separation agreement sets forth the related agreements that we have entered into with PXP, including:

•

employee matters agreement;

•

tax allocation agreement;

•

intellectual property agreement;

•

Plains Exploration & Production transition services agreement;

•

Plains Resources transition services agreement; and

•

technical services agreement.

Employee Matters Agreement

We entered into the employee matters agreement with PXP. The employee matters agreement does not address the treatment of James C. Flores, our Chairman and Chief Executive Officer, John T. Raymond, our President and Chief Operating Officer, and Timothy T. Stephens, our Executive Vice President of Administration and General Counsel, whom we call the executives, except with respect to the treatment of their existing options to acquire our common stock.

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

Stock options and restricted stock awards. Under the employee matters agreement, as a result of the spin-off, all outstanding options to acquire our common stock at the time of the spin-off would be “split” into (1) an equal number of options to acquire our common stock and (2) a number of stock appreciation rights, or SARs, with respect to PXP common stock equal to the number of original Plains Resources stock options.

The exercise price for the original Plains Resources stock options would also be “split” between the new Plains Resources stock options and the SARs based on the following relative amounts: the closing price (with dividend) of our common stock on the distribution date less the closing price (on a “when-issued” basis) of PXP common stock on the distribution date, both as reported on the NYSE, and such closing price of PXP common stock.

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

All recipients of PXP SARs and restricted stock awards would receive the benefit of prior service credit with us and would have the same amount of vesting as they had under their related Plains Resources stock options and restricted stock awards, and vesting terms would remain unchanged. Also, an employee’s or a director’s service with PXP would count towards the vesting of their “split” Plains Resources stock options and restricted stock awards even though the employee is no longer employed by us or the director no longer serves on our board of directors. Likewise, with respect to employees and directors who stay with us, their service with us will count towards the vesting of their SARs even though they are not employed by PXP or do not serve on PXP’s board of directors.

Unless a person is employed by or serves as a director for both PXP and us, termination of employment or service as a director for any reason at either company will count as termination for the same reason at the other company for purposes of vesting and termination of options, SARs, and restricted stock awards. If a person is employed by or serves as a director for both PXP and us, termination for any reason at one company will not count as termination at the other company.

Other plans. The employee matters agreement provides that (1) before the spin-off, PXP will establish a nonqualified deferred compensation plan for certain executive officers and, to the extent that any of the executives are participants in our deferred compensation plan, the related assets and

liabilities under our plan would be transferred to the PXP plan, (2) on or before the spin-off, we would transfer our 401(k) plan and welfare benefit plans to PXP and would form a duplicate 401(k) plan and duplicate welfare benefit plans, and (3) at the time of the spin-off, PXP will establish plans that mirror our fringe benefits and company policies.

Other. Under the employee matters agreement, we would retain liability for all incurred but not reported claims occurring before the spin-off, and PXP will be liable for all claims incurred on or after the spin-off related to its employees.

Tax Allocation Agreement

On July 3, 2002, we entered into the tax allocation agreement, which we and PXP amended and restated on October 2, 2002. This agreement provides that, until the spin-off, PXP will continue to be included in our consolidated federal income tax group, and PXP’s federal income tax liability will be included in our consolidated federal income tax liability. The amount of taxes that PXP will pay or receive with respect to our consolidated or combined returns in which PXP is included generally will be determined by multiplying PXP’s net taxable income included in our consolidated tax return by the highest marginal tax rate applicable to the income. We will not be required to pay PXP for the use of PXP’s tax attributes that come into existence before the spin-off until such time as PXP would otherwise be able to utilize such attributes.

Under the agreement, until the spin-off, we will:

•

continue to have all the rights of a parent of a consolidated group;

•

have sole and exclusive responsibility for the preparation and filing of consolidated federal and consolidated or combined state, local and foreign income tax returns (or amended returns) although PXP may be required to assist in certain circumstances; and

•

have the power, in our sole discretion, to contest or compromise any asserted tax adjustment or deficiency and to file, litigate or compromise any claim for refund relating to these returns; provided, that (1) with our consent, PXP may participate in any proceedings contesting any proposed adjustment related to its activities and (2) we will not accept or offer any settlement of issues related to PXP’s tax liabilities without PXP’s consent, which PXP will not unreasonably withhold.

If we decide not to contest a proposed adjustment relating to PXP activities, PXP may at its expense contest the adjustment, but it may not settle or compromise any issues related to our tax liabilities.

In general, the agreement provides that PXP will be included in our consolidated group for federal income tax purposes until the time of the spin-off. Each member of a consolidated group is jointly and severally liable for the federal income tax liability of each other member of the consolidated group. Accordingly, although this agreement allocates tax liabilities between us and PXP during the period in which PXP is included in our consolidated group, PXP could be liable if any federal tax liability is incurred, but not discharged, by any other member of our consolidated group. In addition, to the extent our net operating losses are used in the consolidated return to offset PXP taxable income from operations during the period January 1, 2002 through the spin-off, PXP will reimburse us for the reduction in PXP’s federal income tax liability resulting from the utilization of such net operating losses, but such reimbursement shall not exceed $3 million exclusive of any interest occurring under the agreement.

Under the terms of this agreement, PXP agrees to indemnify us if the spin-off is not tax-free to us as a result of various actions taken by PXP or with respect to PXP’s failure to take various actions.

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

PXP also agrees to be liable for transfer taxes associated with the transfer of assets and liabilities in connection with the separation and the spin-off.

Intellectual Property Agreement

On July 3, 2002 we entered into the intellectual property agreement, which provides that we will transfer to PXP ownership and all rights associated with certain trade names, trademarks, service marks and associated goodwill, including Arguello, Plains, Plains Energy, Plains E&P, Plains Exploration & Production, Plains Illinois, Plains Petroleum, Plains Resources, Plains Resources International, PLX, PMCT, Stocker Resources and the Plains logo. In addition, PXP will grant us a full license to use certain trade names including Plains Energy and Plains Resources, referred to as the Plains Marks, subject to certain limitations. These licenses are not transferable or assignable without PXP’s written consent, except that we may grant our subsidiaries sublicenses to use the Plains Marks.

We will not attempt to register a trade name or trademark that incorporates or is confusingly similar to the Plains Marks. Also, if we develop new trademarks using the name “Plains,” we must first obtain PXP’s written approval. PXP will own such new trademarks and they will be considered subject to the terms of this agreement.

The intellectual property agreement provides that we will conform the nature and quality of our products and services offered in connection with the Plains Marks to PXP’s reasonable design and quality standards. Further, we will use the Plains Marks only in connection with our business.

Plains Exploration & Production Transition Services Agreement

On July 3, 2002 we entered into the Plains Exploration & Production transition services agreement, which provides that we will provide PXP the following services, on an interim basis:

•

management services, including managing PXP’s operations, evaluating investment opportunities for PXP, overseeing PXP’s upstream activities, and staffing;

•

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

•

accounting services, including maintaining general ledgers, preparing financial statements and working with PXP’s auditors;

•

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

•

insurance services, including maintaining for the interim period the existing insurance that we provide for PXP;

•

employee benefits services, including administering and maintaining the employee benefit plans that cover PXP’s employees;

•

legal services, including typical and customary legal services; and

•

financial services, including helping PXP raise capital, preparing budgets and executing hedges.

We will charge PXP our costs of providing such services monthly but that charge may not exceed $30.0 million in the aggregate during the term of the agreement.

In addition, we and PXP may identify additional services that we will provide to PXP under this agreement in the future. The terms and costs of these additional services will be mutually agreed upon by us and PXP. We may allow one of our subsidiaries or a qualified third party to provide the services under this agreement, but we will be responsible for the performance of the services. To the extent that our personnel who traditionally have provided services contemplated by the transition services agreement have been or are transferred to a similar position with PXP, we will be relieved of our obligations to provide such services to PXP.

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

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

We will provide the services until the spin-off, unless we and PXP decide to terminate the agreement earlier. We and PXP may agree to extend this agreement to up to 180 days following the spin-off and thereafter for a period as mutually agreed.

Plains Resources Transition Services Agreement

On July 3, 2002 we entered into the Plains Resources transition services agreement, under which PXP will provide us the following services on an interim basis beginning on a date to be determined by both us and PXP upon our transfer of substantially all of our employees to PXP:

•

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

•

accounting services, including maintaining general ledgers, preparing financial statements and working with our auditors;

•

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

•

employee benefits services, including administering and maintaining the employee benefit plans that cover our employees;

•

legal services, including typical and customary legal services; and

•

financial services, including helping us raise capital, preparing budgets and executing hedges.

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

•

the Plains Resources transition services agreement will not become effective unless and until the spin-off occurs;

•

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

•

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

•

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

PXP will charge us on a monthly basis its costs of providing such services.

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

PXP will be obligated to provide the services with substantially the same degree of care as it employs for its own operations. PXP may change the manner in which it provides the services so long as it deems such change to be necessary or desirable for its own operations.

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

PXP will provide the services for 180 days, unless we and PXP decide to terminate the agreement earlier. We and PXP may agree to extend this agreement beyond the 180 day period if necessary or desirable.

Technical Services Agreement

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

We will reimburse PXP for its costs to provide these services.

We and PXP may agree to specific performance metrics that PXP must meet. Where no metrics are provided, PXP will (1) perform the services in accordance with the policies and procedures in effect before this agreement, (2) exercise the same care and skill as it exercises in performing similar

services for its own subsidiaries, and (3) in cases where there is common personnel, equipment or facilities for services provided to its subsidiaries and us, not favor us or its subsidiaries over the other. PXP may change the manner in which it provides the services so long as it is making similar changes to the services it is providing to its subsidiaries. PXP is not obligated to provide any service to the extent it is impracticable as a result of causes outside of its control.

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

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

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 “—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. The proved reserve information included in our December 31, 2001 10-K were 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 present value of future net cash flows 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 reserve base (approximately 94% at December 31, 2001) is comprised of oil properties that are sensitive to oil price volatility. Historically, we have experienced significant upward and downward revisions to our reserves 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 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.

Operating risks and insurance coverage. Our operations are subject to all of the risks normally incident to the the exploration for and the production of oil and gas, including well blowouts, cratering, explosions, spills of oil, gas or well fluids, fires, pollution and releases of toxic gas, each of which could result in damage to or destruction of oil and gas wells, production facilities or other property, or injury to persons. Our operations in California, including transportation of oil by pipelines within the city and county of Los Angeles, are especially susceptible to damage from earthquakes and involve increased risks of personal injury, property damage and marketing interruptions because of the population density of southern California. Although we maintain insurance coverage considered to be customary in the industry, we are not fully insured against all risks, either because insurance is not available or

because of high premium costs. We maintain coverage for earthquake damages in California but this coverage may not provide for the full effect of damages that could occur and we may be subject to additional liabilities. The occurrence of a significant event that is not fully insured against could have a material adverse effect on our financial position. Our insurance does not cover every potential risk associated with operating our pipelines, including the potential loss of significant revenues. Consistent with insurance coverage generally available to the industry, our insurance policies provide limited coverage for losses or liabilities relating to pollution, with broader coverage for sudden and accidental occurrences.

Environmental matters. As an owner or lessee and operator of oil and gas properties, we are subject to various federal, state, and local laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liabilities on us for the cost of pollution clean-up resulting from operations, subject us to liability for pollution damages, and require suspension or cessation of operations in affected areas. We maintain insurance coverage, which we believe is customary in the industry, although we are not fully insured against all environmental risks. We have established policies for continuing compliance with environmental laws and regulations and have made and will continue to make expenditures in our efforts to comply with these requirements, which we believe are necessary business costs in the oil and gas industry.

Although we obtained environmental studies on our properties in California and the Illinois Basin, and we believe that these properties have been operated in accordance with standard oil field practices, certain of the fields have been in operation for over 90 years, and current or future federal, state and local environmental laws and regulations may require substantial expenditures to remediate our properties or otherwise comply with these rules and regulations. While we do not believe that the cost of remediation and other compliance with current federal, state or local environmental laws and regulations will have a material adverse effect on our capital expenditures, results of operations or competitive position; there is no assurance that changes in or additions to these laws or regulations will not have such an impact.

Consistent with normal industry practices, substantially all of our oil and gas leases require that, upon termination of economic production, the working interest owners plug and abandon non-producing wellbores, remove tanks, production equipment and flow lines and restore the wellsite. Based on our year-end 2001 reserve report, the cost to perform these tasks is approximately $24.4 million, net of salvage value and other considerations. These estimated amortized costs are included in expenses through the unit-of-production method as a component of accumulated DD&A. Results from operations for 2001, 2000 and 1999 each include $0.5 million of expense associated with these estimated future costs.

We estimate our 2002 expenditures related to plugging, abandonment and remediation to be approximately $3.0 million. Due to the long-life of our onshore reserve base we do not expect our cash outlays on plugging, abandonment and remediation for these properties to increase significantly from this amount for the next several years. Based on our year-end 2001 reserve reports, we estimate our abandonment costs for the 52.6% interest we own in the offshore Point Arguello field to approximate $14.7 million. Timing of abandonment of this field depends of various factors, including oil prices and the success of our exploitation projects.

Recent Accounting Pronouncements

In June 2001 SFAS No. 143, “Accounting for Asset Retirement Obligations” was issued. SFAS No. 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-

lived asset. Subsequently, the asset retirement cost should be allocated to expense using a systematic and rational method. SFAS No. 143 is effective for fiscal years beginning after June 15, 2002. We are currently assessing the impact of SFAS No. 143 and at this time cannot reasonably estimate the effect of this statement on our consolidated financial position, results of operations or cash flows.

In July 2002 SFAS No. 146, “Accounting For Costs Associated with Exit or Disposal Activities” was issued. SFAS 146 is effective for exit or disposal activities initiated after December 31, 2002 and does not require previously issued financial statements to be restated. We will account for exit or disposal activities initiated after December 31, 2002 in accordance with the provisions of SFAS 146.

Quantitative and Qualitative Disclosures About Market Risks

We are exposed to various market risks, including volatility in oil and gas commodity prices and interest rates. Although we have routinely hedged a substantial portion of our oil production and intend to continue this practice, substantial future oil and gas price declines would adversely affect our overall results, and therefore our liquidity. Furthermore, low oil and gas prices could affect our ability to raise capital on favorable terms. Decreases in the prices of oil and gas have had, and could have in the future, an adverse effect on the carrying value of our proved reserves and our revenues, profitability and cash flow. To manage our exposure, we monitor current economic conditions and our expectations of future commodity prices and interest rates when making decisions with respect to risk management. We do not enter into derivative transactions for speculative trading purposes. Substantially all of our derivative contracts are exchanged or traded with major financial institutions and the risk of credit loss is considered remote.

In accordance with SFAS No. 133 “Accounting for Derivative Instruments and Hedging Activities”, as amended, or 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. To qualify for hedge accounting, the derivative must qualify either as a fair value hedge, cash flow hedge or foreign currency hedge. Currently, we use only cash flow hedges and the remaining discussion will relate exclusively to this type of derivative instrument. If the derivative qualifies for hedge accounting, the gain or loss on the derivative is deferred in accumulated Other Comprehensive Income, or OCI, a component of our stockholders’ equity, to the extent the hedge is effective.

The relationship between the hedging instrument and the hedged item must be highly effective in achieving the offset of changes in cash flows attributable to the hedged risk both at the inception of the contract and on an ongoing basis. Hedge accounting is discontinued prospectively when a hedge instrument becomes ineffective. No ineffectiveness was recognized in 2002 or 2001. Gains and losses deferred in OCI related to cash flow hedges for which hedge accounting has been discontinued remain unchanged until the related product has been delivered. If it is probable that a hedged forecasted transaction will not occur, deferred gains or losses on the hedging instrument are recognized in earnings immediately.

We formally document all relationships between hedging instruments and hedged items, as well as our risk management objectives and strategy for undertaking the hedge. Hedge effectiveness is measured on a quarterly basis. This process includes specific identification of the hedging instrument and the hedged item, the nature of the risk being hedged and the manner in which the hedging instrument’s effectiveness will be assessed. At the inception of the hedge and on an ongoing basis, we assess whether the derivatives used in hedging transactions are highly effective in offsetting changes in cash flows of hedged items. As of September 30, 2002 all open positions related to production from our oil and gas properties 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. Effective October 2001 we implemented Derivatives Implementation Group, Issue G20, “Cash Flow Hedges: Assessing and Measuring the Effectiveness of a Purchased Option Used in a Cash Flow Hedge”, or DIG Issue G20, which provides guidance for assessing the effectiveness on total changes in an option’s cash flows rather than only on changes in the option’s intrinsic value. Implementation of DIG Issue G20 has reduced earnings volatility since it allows us to include changes in the time value of purchased options and collars in the assessment of hedge effectiveness. Time value changes were previously recognized in current earnings since we excluded them from the assessment of hedge effectiveness. Oil and gas revenues for the three and nine months ended September 30, 2001 include a non-cash gain of $1.0 million and a non-cash loss of $4.4 million, respectively, related to the ineffective portion of the cash flow hedges representing the fair value change in the time value of options for the nine months before the implementation of DIG Issue G20.

We utilize various derivative instruments to hedge our exposure to price fluctuations on oil sales. The derivative instruments consist primarily of cash-settled oil option and swap contracts entered into with financial institutions. We do not currently have any gas hedges. We also use interest rate swaps to manage the interest rate exposure on our credit facility.

Commodity Price Risk. Our average realized price for crude oil is sensitive to changes in location and quality differential adjustments as set forth in our crude oil sales contracts. At September 30, 2002 we had basis risk swap contracts on our Illinois Basin production through September 30, 2003. The swaps fix the location differential portion of 2,600 barrels per day at $0.38, $0.43, $0.57, and $0.39 per barrel for the fourth quarter of 2002, and the first, second and third quarters of 2003, respectively.

At October 31, 2002 we had the following open crude oil hedge positions (barrels per day):

	4th Qtr 2002	2003	2004
Puts
Average price $20.00/bbl	2,000	—	—
Calls
Average price $35.17/bbl	9,000	—	—
Collars
Average floor price of $22.00/bbl
Average cap price of $27.04/bbl	—	2,000	—
Swaps
Average price $24.22/bbl	20,000	—	—
Average price $23.51/bbl	—	16,250	—
Average price $23.53/bbl	—	—	13,000

The agreements provide for monthly cash settlement 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 crude oil and natural gas sales revenues. Such contracts resulted in decreases in revenues of $8.5 million and $6.6 million in the first nine months of 2002 and 2001, respectively.

The fair value of outstanding derivative commodity instruments at September 30, 2002 was a negative $24.2 million, and a 10% decrease in the forward NYMEX price curve would result in a $30.5 million increase in such fair value. 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 quarters end. All hedge positions offset physical positions exposed to the cash market. Price risk sensitivities were calculated by assuming an across-the-board 10% decrease in price regardless of term or historical relationships between the contractual price of the instruments and the underlying commodity price. In the event of an actual 10% change in prompt month oil prices, the fair value of our derivative portfolio would typically change less than the amount indicated due to lower volatility in out-month prices.

The contract counterparties for our derivative commodity contracts are all major financial institutions with Standard & Poor’s ratings of A or better. Three of the financial institutions are participating lenders in the PXP revolving credit facility, with one counterparty holding contracts that represent approximately 32% of the fair value of all open positions as of September 30, 2002.

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 debt instruments are sensitive to market fluctuations in interest rates. Interest rate swaps are used 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. At September 30, 2002, we had an interest rate swap for an aggregate notional principal amount of $7.5 million, for which we would pay approximately $0.1 million if such arrangement were terminated as of such date. The swap expires in October 2004 and fixes the interest rate on $7.5 million of borrowing under the PXP credit facility at 3.9% plus the LIBOR margin set forth in the credit facility.

Forward-Looking Statements and Associated Risks

This report includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1934. We have based these forward-looking statements 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 or implied by these forward-looking statements. These factors include, among other things, those matters discussed under the caption “Risk Factors,” as well as the following:

•

the consequences of any potential change in the relationship between us and our subsidiary PXP, including our contemplated spin-off of PXP;

•

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

•

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

•

impact of oil and gas price fluctuations;

•

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 report 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 report. 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.

PART II. OTHER INFORMATION

Item 1—Legal Proceedings.

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 Chairman of the Board and 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 Chairman of the Board and 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.

Item 6—Exhibits and Reports on Form 8-K

A. Exhibits


10.1		Amended and Restated Employment Agreement, dated as of September 19, 2002, between Plains Resources Inc. and James C. Flores.

10.2		Amended and Restated Employment Agreement, dated as of September 19, 2002, between Plains Resources Inc. and John T. Raymond.

10.3		Employment Letter Agreement, dated as of August 20, 2002, between Plains Exploration & Production Company and Stephen A. Thorington.

10.4		Amendment No. 1 to Employee Matters Agreement, dated as of September 18, 2002, between Plains Resources Inc. and Plains Exploration & Production Company.

10.5		Amended and Restated Tax Allocation Agreement, dated as of October 2, 2002, between Plains Exploration & Production Company and Plains Resources Inc.

10.6		First Amendment to Plains Resources Inc. 2001 Stock Incentive Plan.

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 October 30, 2002 with respect to current estimates of certain results for the fourth quarter of 2002.

Items 2, 3 & 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 RESOURCES INC.

Date: November 12, 2002	By:	/s/ CYNTHIA A. FEEBACK
		Cynthia A. Feeback Senior Vice President—Accounting and Treasurer (Principal Accounting Officer)

CERTIFICATION

I, James C. Flores, Chief Executive Officer of Plains Resources Inc., certify that:

I have reviewed this quarterly report on Form 10-Q of Plains Resources Inc.;

Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report;

Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report;

The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

(a)

designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;

(b)

evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the “Evaluation Date”); and

(c)

presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):

(a)

all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and

(b)

any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

The registrant’s other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.


Date: November 12, 2002	By:	/S/ JAMES C. FLORES
		Name: James C. Flores Title: Chief Executive Officer

CERTIFICATION

I, Jere C. Overdyke, Jr., Chief Financial Officer of Plains Resources Inc., certify that:

I have reviewed this quarterly report on Form 10-Q of Plains Resources Inc.;

(a)

(b)

evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the “Evaluation Date”); and

(c)

presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

(a)

(b)

any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and


Date: November 12, 2002		By:		/S/ JERE C. OVERDYKE, JR. Name: Jere C. Overdyke, Jr. Title: Chief Financial Officer