PLAINS RESOURCES INC - 10-Q Quarterly Report

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-Q


þ		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2003


o		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.)

700 Milam Street, Suite 3100
Houston, Texas 77002
(Address of principal executive offices)
(Zip Code)

(832) 239-6000
(Registrant’s telephone number, including area code)

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

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

23.6 million shares of common stock, $0.10 par value, issued and outstanding at October 31, 2003.

TABLE OF CONTENTS


		CONSOLIDATED BALANCE SHEETS
		CONSOLIDATED STATEMENTS OF INCOME
		CONSOLIDATED STATEMENTS OF CASH FLOWS
		CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
		CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY
		NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
	ITEM 2. – Management’s Discussion and Analysis of Financial Condition and Results of Operations
	ITEM 3. – Quantitative and Qualitative Disclosures About Market Risks
	ITEM 4. – Controls and Procedures
PART II. OTHER INFORMATION
SIGNATURES
Exhibit Index
Employment Agreement - Stephen A. Thorington
Certification of CEO Pursuant to Section 302
Certification of CFO Pursuant to Section 302
Certification of CEO Pursuant to Section 906
Certification of CFO Pursuant to Section 906

PLAINS RESOURCES INC. AND SUBSIDIARIES
TABLE OF CONTENTS


	Page
PART I. FINANCIAL INFORMATION
ITEM 1. Financial Statements:
Consolidated Balance Sheets (Unaudited) September 30, 2003 and December 31, 2002		1
Consolidated Statements of Income (Unaudited) For the three months and nine months ended September 30, 2003 and 2002		2
Consolidated Statements of Cash Flows (Unaudited) For the nine months ended September 30, 2003 and 2002		3
Consolidated Statements of Comprehensive Income (Unaudited) For the nine months ended September 30, 2003 and 2002		4
Consolidated Statements of Changes in Stockholders’ Equity (Unaudited) For the nine months ended September 30, 2003		5
Notes to Consolidated Financial Statements (Unaudited)		6
ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		16
ITEM 3. Quantitative and Qualitative Disclosures About Market Risk		28
ITEM 4. Controls and Procedures		29
PART II. OTHER INFORMATION		30

(i)

PLAINS RESOURCES INC.
CONSOLIDATED BALANCE SHEETS (Unaudited)
(in thousands)


		September 30,			December 31,
		2003			2002

ASSETS
Current Assets
	Cash and cash equivalents	$	1,368		$	8,807
	Accounts receivable - Plains All American Pipeline, L.P.		2,993			—
	Other accounts receivable		41			1,589
	Inventory		1,699			2,305
	Other current assets		1,479			1,515

			7,580			14,216

Property and Equipment, at cost
	Oil and gas properties - full cost method Subject to amortization		352,963			349,517
	Other property and equipment		27			27

			352,990			349,544
	Less allowance for depreciation, depletion and amortization		(299,327	)		(299,214	)

			53,663			50,330

Ownership Interest in Plains All American Pipeline, L.P.			93,116			70,042

Other Assets
	Deferred income taxes		—			16,957
	Other		10,175			9,867

			10,175			26,824

		$	164,534		$	161,412

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
	Accounts payable and other current liabilities	$	5,522		$	6,309
	Taxes payable		2,283			1,878
	Current maturities of long-term debt		20,000			18,000

			27,805			26,187

Long-Term Bank Debt			35,000			27,000

Asset Retirement Obligation			2,016			—

Other Long-Term Liabilities			3,355			2,716

Deferred Income Taxes			2,379			—

Commitments and Contingencies (Note 9)

Stockholders’ Equity
	Series D cumulative convertible preferred stock		—			23,300
	Common stock		2,825			2,806
	Additional paid-in capital		276,458			273,162
	Retained earnings (deficit)		(94,646	)		(103,882	)
	Accumulated other comprehensive income		5,387			(2,862	)
	Treasury stock, at cost		(96,045	)		(87,015	)

			93,979			105,509

		$	164,534		$	161,412

See notes to consolidated financial statements.

PLAINS RESOURCES INC.
CONSOLIDATED STATEMENTS OF INCOME (Unaudited)
(In thousands, except per share data)


			Three Months Ended						Nine Months Ended
			September 30,						September 30,

			2003			2002			2003			2002

Revenues
	Oil sales to Plains All American Pipeline, L.P.		$	4,917		$	5,323		$	16,541		$	14,289
	Hedging			—			(172	)		(307	)		(423	)

				4,917			5,151			16,234			13,866

Costs and Expenses
	Production expenses			1,910			1,604			5,288			4,301
	Production and ad valorem taxes			251			146			888			374
	Oil transportation expenses			917			946			2,945			2,776
	General and administrative			1,476			1,312			4,883			4,687
	Depreciation, depletion and amortization			1,089			942			3,522			3,269
	Accretion of asset retirement obligation			58			—			171			—
	Other operating expenses			—			—			137			—

				5,701			4,950			17,834			15,407

Other Income (Expense)
	Equity in earnings of Plains All American Pipeline, L.P.			3,142			4,454			14,864			14,060
	Gain on Plains All American Pipeline, L.P. unit offering			9,119			14,512			15,227			14,512
	Gain (loss) on derivatives			(1,211	)		—			(2,958	)		—
	Loss on debt extinguishment			—			(10,319	)		—			(10,319	)
	Interest expense			(627	)		(2,324	)		(1,636	)		(5,801	)
	Interest and other income			21			236			127			263

				10,444			6,559			25,624			12,715

Income From Continuing Operations Before Income Taxes				9,660			6,760			24,024			11,174
	Income tax benefit (expense)
		Current		287			(836	)		(2,314	)		1,569
		Deferred		(4,122	)		(2,157	)		(8,398	)		(6,788	)

Income From Continuing Operations				5,825			3,767			13,312			5,955
	Income from discontinued operations, net of tax			—			7,418			—			21,500

Income before cumulative effect of accounting change				5,825			11,185			13,312			27,455
	Cumulative effect of accounting change, net of tax			—			—			933			—

Net Income				5,825			11,185			14,245			27,455
	Preferred dividends			—			(350	)		(603	)		(1,050	)

Income Available to Common Stockholders			$	5,825		$	10,835		$	13,642		$	26,405

Earnings Per Share (in dollars)
	Basic
		Income from continuing operations	$	0.25		$	0.14		$	0.54		$	0.21
		Discontinued operations		—			0.31			—			0.90
		Change in accounting policy		—			—			0.04			—

			$	0.25		$	0.45		$	0.58		$	1.11

	Diluted
		Income from continuing operations	$	0.24		$	0.14		$	0.53		$	0.20
		Discontinued operations		—			0.30			—			0.88
		Change in accounting policy		—			—			0.04			—

			$	0.24		$	0.44		$	0.57		$	1.08

Weighted average shares outstanding
		Basic		23,381			23,956			23,610			23,826
		Diluted		23,975			24,617			25,040			24,455

See notes to consolidated financial statements.

PLAINS RESOURCES INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
(in thousands)


			Nine Months Ended
			September 30,

			2003			2002

CASH FLOWS FROM OPERATING ACTIVITIES
Net income			$	14,245		$	27,455
Items not affecting cash flows from continuing operating activities
	Income from discontinued operations, net of tax			—			(21,500	)
		Depreciation, depletion and amortization		3,522			3,269
		Accretion of asset retirement obligation		171			—
		Equity in earnings of Plains All American Pipeline, L.P.		(14,864	)		(14,060	)
		Gain on Plains All American Pipeline, L.P. unit offering		(15,227	)		(14,512	)
		Distributions received from Plains All American Pipeline, L.P.		23,089			21,558
		Deferred income taxes		8,398			6,788
		Cumulative effect of adoption of SFAS 143, net of tax		(933	)		—
		Change in derivative fair value		1,275			—
		Noncash compensation expense		2,049			865
		Other noncash items		225			1,519
Change in assets and liabilities from operating activities				(3,335	)		(15,611	)

Net cash provided by (used in) continuing activities				18,615			(4,229	)
Net cash provided by (used in) discontinued activities				—			58,353

Net cash provided by (used in) operating activities				18,615			54,124

CASH FLOWS FROM INVESTING ACTIVITIES
Additions to oil and gas properties				(2,412	)		(5,641	)
Additions to other property and equipment				—			(64	)
General Partner Contribution to Plains All American Pipeline, L.P.				(1,491	)		(1,334	)

Net cash provided by (used in) continuing activities				(3,903	)		(7,039	)
Net cash provided by (used in) discontinued activities				—			(53,644	)

Net cash provided by (used in) investing activities				(3,903	)		(60,683	)

CASH FLOWS FROM FINANCING ACTIVITIES
Net change in credit facility				10,000			(11,500	)
Principal payments on long-term debt				—			(267,450	)
Proceeds from exercise of stock options				1,492			4,748
Retirement of Series D preferred stock				(23,300	)		—
Treasury stock purchases				(9,030	)		—
Costs incurred in connection with financing arrangements				(710	)		—
Preferred stock dividends				(603	)		(700	)
Other				—			(4	)

Net cash provided by (used in) continuing activities				(22,151	)		(274,906	)
Net cash provided by (used in) discontinued activities				—			281,472

Net cash provided by (used in) financing activities				(22,151	)		6,566

Net increase (decrease) in cash and cash equivalents				(7,439	)		7
Cash and cash equivalents, beginning of period				8,807			1,179

Cash and cash equivalents, end of period			$	1,368		$	1,186

See notes to consolidated financial statements

PLAINS RESOURCES INC.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited)
(in thousands)


				Three Months Ended					Nine Months Ended
				September 30,					September 30,

				2003		2002			2003			2002

Net Income				$	5,825	$	11,185		$	14,245		$	27,455

Other Comprehensive Income (Loss):
	From continuing operations:
		Commodity hedging contracts, net of tax:
			Change in fair value		—		(288	)		(956	)		(885	)
			Reclassification adjustment for settled contracts		161		—			946			(10	)
		Interest rate swap and other, net of tax			—		66			—			(9	)
		Equity in other comprehensive income changes of Plains All American Pipeline, L.P., net of tax			3,203		(1,388	)		8,259			616

					3,364		(1,610	)		8,249			(288	)
	From discontinued operations				—		(5,448	)		—			(30,487	)

					3,364		(7,058	)		8,249			(30,775	)

Comprehensive Income				$	9,189	$	4,127		$	22,494		$	(3,320	)

See notes to consolidated financial statements.

PLAINS RESOURCES INC.
CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY (Unaudited)
(in thousands)


		Nine Months Ended
		September 30, 2003

		Shares			Amount

Series D Cumulative Convertible Preferred Stock
	Balance, beginning of period		47		$	23,300
	Shares retired		(47	)		(23,300	)

	Balance, end of period		—			—

Common Stock
	Balance, beginning of period		28,048			2,806
	Common stock issued upon exercise of stock options and other		183			19

	Balance, end of period		28,231			2,825

Additional Paid-in Capital
	Balance, beginning of period					273,162
	Common stock issued upon exercise of stock options and other					3,296

	Balance, end of period					276,458

Retained Earnings (Deficit)
	Balance, beginning of period					(103,882	)
	Spin-off of Plains Exploration & Production Company					(4,406	)
	Net income					14,245
	Preferred stock dividends					(603	)

	Balance, end of period					(94,646	)

Accumulated Other Comprehensive Income
	Balance, beginning of period					(2,862	)
	Other comprehensive income					8,249

	Balance, end of period					5,387

Treasury Stock
	Balance, beginning of period		3,854			(87,015	)
	Purchase of treasury shares		820			(9,030	)

	Balance, end of period		4,674			(96,045	)

Total					$	93,979

See notes to consolidated financial statements.

PLAINS RESOURCES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Note 1 — Organization and Significant Accounting Policies

Organization

The consolidated financial statements of Plains Resources Inc. (“Plains”, “our”, or “we”) include the accounts of all wholly owned subsidiaries. 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. We are principally engaged in the “midstream” activities of marketing, gathering, transporting, terminalling, and storage of oil through our equity ownership in Plains All American Pipeline, L.P. (“PAA”), a publicly traded master limited partnership that is actively engaged in the midstream energy markets. All of PAA’s midstream activities are conducted in the United States and Canada. We also participate in the “upstream” activities of acquiring, exploiting, developing, exploring for and producing oil through our wholly owned subsidiary, Calumet Florida L.L.C., which has producing properties in the Sunniland Trend in south Florida.

These consolidated financial statements and related notes present our consolidated financial position as of September 30, 2003 and December 31, 2002, the results of our operations and our comprehensive income for the three months and nine months ended September 30, 2003 and 2002, our cash flows for the nine months ended September 30, 2003 and 2002, and the changes in our stockholders’ equity for the nine months ended September 30, 2003. The results for the nine months ended September 30, 2003, are not necessarily indicative of the final results to be expected for the full year. These financial statements have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission regarding interim financial reporting. Accordingly, they do not include all of the information and notes required by accounting principles generally accepted in the United States of America for complete financial statements and should be read in conjunction with the audited consolidated financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2002.

On December 18, 2002, we distributed 100 percent of the common shares of Plains Exploration & Production Company (“PXP”), our wholly owned subsidiary that owned oil and gas properties offshore and onshore California and in Illinois, to our stockholders (the “spin-off”). As a result of the spin-off, the historical results of the operations of PXP are reflected in our financial statements as “discontinued operations.” In connection with the spin-off we entered into certain agreements with PXP, see Note 8.

Accounting Policies

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

At January 1, 2003 the present value of our future Asset Retirement Obligation for oil and gas properties and equipment was $2.6 million. The cumulative effect of our adoption of SFAS No. 143 and the change in accounting principle resulted in an increase in income in 2003 of $0.9 million (reflecting a $2.8 million decrease in accumulated DD&A, partially offset by $1.3 million in accretion expense, and $0.6 million deferred income tax expense). We recorded a

liability of $2.6 million and an asset of $1.2 million in connection with the adoption of SFAS 143. Adopting SFAS No. 143 did not effect our cash flows.

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


	Nine Months Ended September 30,

	2003				2002

					Pro forma
Asset retirement obligation - beginning of period	$	2,556			$	2,344
Accretion expense		171				159
Asset retirement costs incurred		(173	)			—

Asset retirement obligation - end of period	$	2,554	(1	)	$	2,503

(1) $538 included in other current liabilities

On a pro forma basis the effect of the adoption of SFAS 143 on our income from continuing operations, our net income and our earnings per share for the three months and nine months ended September 30, 2002 is not material.

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


	September
	30,		December 31,
	2003		2002

Oil	$	1,114	$	1,482
Materials and supplies		585		823

	$	1,699	$	2,305

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


	September
	30,		December 31,
	2003		2002

Restricted cash	$	5,035	$	5,000
Debt issue costs, net		1,025		612
Receivable from PXP		3,202		3,202
Other		913		1,053

	$	10,175	$	9,867

Federal and State Income Taxes. To reflect differences between the amounts included in our financial statements at December 31, 2002 and the final 2002 tax returns filed by us and PXP, in the third quarter of 2003 we increased our deferred tax liability by $4.4 million and decreased our stockholders’ equity by such amount that is reflected as Spin-off of PXP in our statement of changes in stockholders’ equity.

Stock-Based Employee Compensation. Statement of Financial Accounting Standards No. 123 “Accounting for Stock-Based Compensation” (“SFAS 123”) established financial accounting and reporting standards for stock-based employee compensation. SFAS 123 defines a fair value based method of accounting for an employee stock option or similar equity instrument. SFAS 123 also allows an entity to continue to measure compensation cost for those instruments using the intrinsic value-based method of accounting prescribed by Accounting Principles Bulletin No. 25 “Accounting for Stock Issued to Employees” (“APB 25”). We have elected to follow APB 25 and related interpretations in accounting for our employee stock options. Under APB 25, if the exercise price of our employee stock options equals the market price of the underlying stock on the date of grant, no compensation expense is recognized in the financial statements. The compensation expense recorded under APB 25 for our restricted stock awards is the same as that determined under SFAS 123.

Set forth below is a summary of our net income and earnings per share as reported and pro forma as if the fair value based method of accounting defined in SFAS 123 had been applied (in thousands, except per share data).


		Three Months Ended						Nine Months Ended
		September 30,						September 30,

		2003			2002			2003			2002

Income available to common stockholders, as reported		$	5,825		$	10,835		$	13,642		$	26,405
Add: Stock-based employee compensation expense included in reported net income, net of related tax effects			464			133			1,161			446
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects			(2,090	)		(1,263	)		(3,567	)		(1,954	)

Pro forma net income		$	4,199		$	9,705		$	11,236		$	24,897

Earnings per share:
	Basic-as reported	$	0.25		$	0.45		$	0.58		$	1.11

	Basic-pro forma	$	0.18		$	0.41		$	0.48		$	1.04

	Diluted-as reported	$	0.24		$	0.44		$	0.57		$	1.08

	Diluted-pro forma	$	0.18		$	0.39		$	0.45		$	1.02

The fair value for the options was estimated at the date of grant using a Black-Scholes option pricing model with the following weighted average assumptions for grants in 2003: risk-free interest rate of 3.0%; a volatility factor of the expected market price of our common stock of 0.33; no expected dividends; and weighted average expected option life of 4.4 years. No options were granted during the nine months ended September 30, 2003. For purposes of pro forma disclosures, the estimated fair value of the options is amortized to expense over the options’ vesting period.

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

In May 2003, the FASB issued Statement No. 150 “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity.” (“SFAS 150”). SFAS 150 establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. SFAS 150 is generally effective for financial instruments entered into or modified after May 31, 2003, and otherwise is effective at the beginning of the first interim period beginning after June 15, 2003. The adoption of SFAS 150 had no effect on our financial statements.

periods, the primary beneficiary will be required to consolidate the VIE. In addition, more extensive disclosure requirements apply to the primary beneficiary, as well as other significant investors. We do not believe we participate in any arrangement that would be subject to the provisions of FIN 46.

Note 2 — Ownership Interest in Plains All American Pipeline, L.P.

In March 2003, PAA issued 2.6 million common units in a public equity offering. We recognized a gain of $6.1 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 that offering, we made a general partner capital contribution of approximately $0.6 million.

In September 2003, PAA issued 3.2 million common units in a public equity offering. We recognized a gain of $9.1 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 that offering, we made a general partner capital contribution of approximately $0.9 million.

At September 30, 2003, our aggregate 23% ownership in PAA 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) 17%, or approximately 7.9 million, of the common units (including approximately 1.3 million Class B common units).

PAA Financial Statement Information

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


	Three Months Ended September 30,				Nine Months Ended September 30,

	2003		2002		2003		2002

Revenues	$	3,053,677	$	2,344,089	$	9,044,774	$	5,874,759
Cost of sales and operations		3,003,017		2,299,823		8,881,257		5,750,398
Gross margin, excluding depreciation		50,660		44,266		163,517		124,361
Operating income		20,468		23,773		85,916		67,847
Net income		11,871		16,317		59,620		47,549


	September 30,		December 31,
	2003		2002

Current assets	$	564,228	$	602,935
Property and equipment, net		1,072,071		952,753
Other assets		173,843		110,887
Total assets		1,810,142		1,666,575
Current liabilities		629,531		637,249
Long-term debt		453,740		509,736
Other long-term liabilities		21,483		7,980
Partners’ capital		705,388		511,610
Total liabilities and partners’ capital		1,810,142		1,666,575

Note 3 — Discontinued Operations

The results of operations of PXP, which have been reclassified as discontinued operations for the three months and nine months ended September 30, 2002, are summarized as follows (in thousands):


	Three Months			Nine Months
	Ended			Ended
	September 30, 2002			September 30, 2002

Revenues	$	50,907		$	136,720
Costs and expenses		(32,135	)		(85,450	)

Income from operations		18,772			51,270
Other income (expense)		(6,631	)		(16,013	)

Income before income taxes		12,141			35,257
Income tax expense		(4,723	)		(13,757	)

Income from discontinued operations	$	7,418		$	21,500

Note 4 — Derivative Instruments and Hedging Activities

We have entered into various derivative instruments to reduce our exposure to fluctuations in the market price of oil. The derivative instruments consist primarily of oil swap and option contracts entered into with financial institutions. Derivative instruments are accounted for in accordance with SFAS No. 133 “Accounting for Derivative Instruments and Hedging Activities” as amended by SFAS 137, SFAS 138 and SFAS 149, 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. If the derivative qualifies for hedge accounting, the gain or loss on the derivative is deferred in Accumulated Other Comprehensive Income (“OCI”), a component of our stockholders’ equity, to the extent the hedge is effective. Gains and losses on oil hedging instruments related to OCI and adjustments to carrying amounts on hedged volumes are included in oil revenues in the period that the related volumes are delivered.

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. Gains and losses deferred in OCI related to cash flow hedges that become ineffective remain unchanged until the related product is delivered. If it is determined that it is probable that a hedged forecasted transaction will not occur, deferred gains or losses on the hedging instrument are recognized in earnings immediately.

In the first quarter of 2003, the NYMEX oil price and the price we received for our Florida oil production did not correlate closely enough for the hedges to qualify for hedge accounting. As a result, we were required to discontinue hedge accounting effective February 1, 2003 and reflect the mark-to-market value of the hedges in earnings prospectively from that date. In the first nine months of 2003, we recorded $3.0 million loss on derivatives that consisted of a $1.3 million loss for the decrease in the fair value of our derivatives and a $1.7 million loss on cash settlements of such derivatives. In addition a $0.3 million loss on cash settlements for January 2003 is reflected as a reduction of revenues. None of our current hedges qualify for hedge accounting.

At September 30, 2003, Accumulated OCI consisted of unrealized losses of $0.5 million ($0.3 million, net of tax) on our oil hedging instruments generated prior to the discontinuation of hedge accounting, unrealized losses of $0.5 million ($0.3 million, net of tax) related to pension liabilities and an unrealized gain of $10.8 million ($6.0 million, net of tax) related to our equity in the OCI gains of PAA. At September 30, 2003, the liability related to our open oil hedging instruments was included in current liabilities ($1.1 million), other long-term liabilities ($0.6 million), and deferred income taxes (a tax benefit of $0.2 million).

As of September 30, 2003, $0.5 million ($0.3 million, net of tax) of deferred net losses on our oil derivative instruments recorded in OCI are expected to be reclassified to earnings during the following twelve month period as the hedged volumes are produced and sold.

At September 30, 2003, we had the following open oil derivative positions:


		Barrels per Day

		2003		2004		2005		2006

Swaps
	Average price $26.10/bbl		1,500		—		—		—
	Average price $24.07/bbl		—		1,000		—		—
	Average price $24.30/bbl		—		—		500		—
	Average price $23.85/bbl		—		—		—		500

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

Note 5 — Long-Term Debt and Credit Facilities

Secured Term Loan Facility

In December 2002, we entered into a $45 million secured term loan facility with a group of banks. We used proceeds from the term loan and cash on hand to make a $40 million capital contribution and repay a $7.2 million note payable to PXP. In June 2003, the facility was restructured to allow us to borrow an additional $24 million that was used to repurchase the 46,600 outstanding shares of our Series D Cumulative Convertible Preferred Stock and pay accrued dividends and related expenses. At September 30, 2003, $55.0 million was outstanding under the secured term loan facility. The term loan is repayable in twelve quarterly installments of $5.0 million commencing in August 2003 with a final maturity of May 31, 2006. Amounts outstanding under the term loan bear an annual interest rate, at our election, equal either to the Base Rate (as defined in the agreement) plus 1.5%, or LIBOR plus 3%. The term loan requires that we maintain $5.0 million on deposit in a debt service reserve account with one of the lending banks. Our average borrowing rate for the nine months ended September 30, 2003 was 4.3% (4.1% at September 30, 2003).

To secure the term loan, we pledged 100% of the shares of stock of our subsidiaries and pledged 5.2 million of our PAA common units. To the extent that the outstanding principal under the term loan exceeds the balance in the debt service reserve account plus 50% of the fair market value of the pledged common units, we are required to repay the excess. The fair market value of the pledged units is determined based on the closing price of PAA common units as reported on the New York Stock Exchange.

The term loan contains covenants that limit our ability, as well as the ability of our subsidiaries, to incur additional debt, make investments, create liens, enter into leases, sell assets, change the nature of our business or operations, guarantee other indebtedness, enter into certain types of hedge agreements, enter into take-or-pay arrangements, merge or consolidate and enter into transactions with affiliates. In addition, if an event of default exists, the term loan prohibits us from paying dividends or repurchasing or redeeming shares of any class of capital stock. The term loan requires us to maintain a minimum consolidated tangible net worth (as defined) and a consolidated debt service coverage ratio (as defined in the agreement) of 1.0 to 1.0. At September 30, 2003, we were in compliance with the covenants contained in the term loan facility.

Note 6 — Earnings Per Share

The following is a reconciliation of the numerators and denominators of the basic and diluted earnings per share computations for income from continuing operations before the cumulative effect of accounting changes for the three months and nine months ended September 30, 2003 and 2002 (in thousands, except per share amounts):


		Three Months Ended September 30,										Nine Months Ended September 30,

		2003				2002						2003						2002

		Basic		Diluted		Basic			Diluted			Basic			Diluted			Basic			Diluted

Income from continuing operations		$	5,825	$	5,825	$	3,767		$	3,767		$	13,312		$	13,312		$	5,955		$	5,955
Preferred dividends			—		—		(350	)		(350	)		(603	)		(603	)		(1,050	)		(1,050	)

Income from continuing operations available to common stockholders			5,825		5,825		3,417			3,417			12,709			12,709			4,905			4,905
Income from discontinued operations, net of tax			—		—		7,418			7,418			—			—			21,500			21,500
Effect of accounting changes, net of tax			—		—		—			—			933			933			—			—

Income available to common stockholders		$	5,825	$	5,825	$	10,835		$	10,835		$	13,642		$	13,642		$	26,405		$	26,405

Weighted average number of shares of common stock outstanding			23,381		23,381		23,956			23,956			23,610			23,610			23,826			23,826
Effect of dilutive securities
	Convertible preferred stock		—		—		—			—			—			943			—			—
	Stock options and restricted stock		—		594		—			661			—			487			—			629

Weighted average common shares			23,381		23,975		23,956			24,617			23,610			25,040			23,826			24,455

Earnings per share
	Continuing operations	$	0.25	$	0.24	$	0.14		$	0.14		$	0.54		$	0.53		$	0.21		$	0.20
	Discontinued operations		—		—		0.31			0.30			—			—			0.90			0.88
	Effect of accounting changes		—		—		—						0.04			0.04			—			—

	Income available to common stockholders	$	0.25	$	0.24	$	0.45		$	0.44		$	0.58		$	0.57		$	1.11		$	1.08

In the nine months ended September 30, 2003 and the three months and nine months ended September 30, 2002, our cumulative convertible preferred stock was not included in the computation of diluted earnings per share because the effect was antidilutive.

Note 7 — Stockholders’ Equity

In June 2003, we paid $23.3 million to retire the 46,600 outstanding shares of our Series D Cumulative Convertible Preferred Stock, or Series D Preferred. The Series D Preferred was convertible into 1,671,416 shares of common stock at a price of $13.94 per share and paid an annual dividend of $30.00 per share.

Our Board of Directors has authorized the repurchase of up to eight million shares of our common stock. Through December 31, 2002, we had repurchased a total of 4.1 million shares at a total cost of approximately $91.3 million. In the first nine months of 2003, we have repurchased an additional 0.8 million shares at a total cost of $9.0 million.

Note 8 — Related Party Transactions

Governance of PAA

We, along with Sable Investments, L.P. (which is owned by Mr. Flores, our Chairman, and Mr. Raymond, our Chief Executive Officer and President), Kafu Holdings, L.P. (which is controlled by Kayne Anderson Capital Advisors, L.P. and Kayne Anderson Investment Management, Inc., of which Mr. Sinnott, one of our directors, is Senior Vice President), and E-Holdings III, L.P. (which is controlled by EnCap Investments L.L.C. and of which Mr. Phillips, one of our directors, is a managing director and principal) are parties to agreements governing Plains All American GP LLC, which is the general partner of Plains AAP, L.P., and Plains AAP, L.P., which is the general partner of PAA. These agreements govern the ongoing management and control of PAA.

In addition, Plains AAP, L.P., the general partner of PAA, is owned as follows:


Plains Resources	44.00	%
Sable Investments, L.P.	20.00	%
Kafu Holdings, L.P.	16.42	%
E-Holdings, L.P.	9.00	%
Others	10.58	%

	100.00	%

Also, each of we, Sable Investments, Kafu Holdings, and E-Holdings may appoint one member of the Plains All American GP LLC board of directors.

Value Assurance Agreements

We entered into value assurance agreements with Sable Investments, Kafu Holdings, E-Holdings and other parties with respect to the 5.2 million subordinated units they acquired from us in our June 2001 strategic restructuring. The value assurance agreements require us to pay to them 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.

Oil Marketing Agreement

PAA is the exclusive marketer/purchaser for all of our equity oil production. The marketing agreement provides that PAA will purchase for resale at market prices all of our equity oil production for which PAA charges a fee of $0.20 per barrel. For the nine months ended September 30, 2003 and 2002, sales of oil to PAA under the agreement totaled $19.5 million and $16.6 million, respectively, including the royalty share of production. For the nine months ended September 30, 2003 and 2002, PAA charged us $0.1 million in each period in marketing fees.

Agreements with PXP

Other

From time to time we charter private aircraft from Gulf Coast Aviation Inc. (“Gulf Coast”), which is not affiliated with us or our employees. On certain occasions, the aircraft that Gulf Coast charters is owned by our Chairman of the Board. In the nine months ended September 30, 2003 and 2002, we paid Gulf Coast $10,000 and $425,000, respectively, for aircraft chartering services provided by Gulf Coast using an aircraft owned by our Chairman. The charters were arranged through arms-length dealings with Gulf Coast and the rates were market based.

Note 9 — Commitments and Contingencies

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

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

Note 10 — Supplemental Disclosures of Cash Flow Information

Selected cash payments and noncash activities, including amounts attributable to discontinued operations, were as follows (in thousands):


		Three Months				Nine Months
		Ended September 30,				Ended September 30,

		2003		2002		2003		2002

Cash paid for interest		$	728	$	10,688	$	1,612	$	25,581

Cash paid for taxes		$	206	$	474	$	1,738	$	3,746

Noncash sources of investing and financing activities:
	Tax benefit from exercise of employee stock options	$	129	$	512	$	247	$	2,248

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

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

We are an independent energy company. We are principally engaged in the “midstream” activities of marketing, gathering, transporting, terminalling, and storage of oil through our equity ownership in Plains All American Pipeline, L.P., or PAA. PAA is a publicly traded master limited partnership actively engaged in the midstream energy markets. As of September 30, 2003, we owned 44% of the general partner of PAA and 12.4 million limited partner units of PAA, which represented approximately 23% aggregate ownership interest in PAA. We also participate in the “upstream” activities of acquiring, exploiting, developing, exploring for and producing oil through our wholly owned subsidiary, Calumet Florida L.L.C., which has producing properties in the Sunniland Trend in south Florida.

At September 30, 2003, the book value of our ownership interest in PAA represents 57% of our total assets, the book value of our Florida oil properties represents 33% of our total assets and our current assets and other assets (including $5.0 million of restricted cash) represent 10% of our total assets. As of December 31, 2002, the present value of our proved oil reserves was approximately $87.9 million. We own 6.6 million common units, 1.3 million Class B common units and 4.5 million subordinated units of PAA. The closing price of publicly traded PAA common units, as reported on the New York Stock Exchange, was $30.05 on September 30, 2003. The Class B common units and the subordinated units are not publicly traded but do receive cash distributions from PAA. PAA’s partnership agreement contains provisions which, upon the occurrence of certain future events, will result in the conversion of the subordinated units to common units. During the first nine months of 2003 we had oil sales of $16.5 million and distributions received from PAA attributable to our general and limited partner interests totaled $23.1 million. PAA’s financial performance directly impacts our financial performance and the market value performance of PAA’s limited partner interests directly impacts the value of our assets. As a result, we encourage you to review PAA’s SEC filings, including its Annual Report on Form 10-K for the year ended December 31, 2002 and it Quarterly Report on Form 10-Q for the quarter ended September 30, 2003, to review and assess, among other things, PAA’s financial performance and financial condition, PAA’s business, operations, and competition, and risk factors associated with PAA’s business.

Spin-off of Plains Exploration & Production Company

On December 18, 2002, we distributed 100 percent of the common shares of Plains Exploration & Production Company, or PXP, our wholly owned subsidiary that owned oil and gas properties offshore and onshore California and in Illinois, to our stockholders, the spin-off. As a result of the spin-off, the historical results of the operations of PXP are reflected in our financial statements as “discontinued operations”. Except where noted, discussions in this Form 10-Q with respect to oil and gas operations relate to our activities other than the discontinued operations.

General

Upstream Operations

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. 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. Historically, the markets for oil have been volatile and are likely to continue to be volatile in the future. The prices we receive for our oil 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, adjusted for cash flow hedges, 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 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 prices decline 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 lower revenues on the hedged volumes than we would receive in the absence of hedges. Gains and losses from hedging transactions are recognized as revenues when the associated production is sold. 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 and changes in value are reflected in earnings prospectively from the date the hedge becomes ineffective. Gains and losses deferred in other comprehensive income, or OCI, related to cash flow hedges that become ineffective remain unchanged until the related product is delivered.

In the first quarter of 2003, the NYMEX oil price and the price we received for our Florida oil production did not correlate closely enough for our hedges to qualify for hedge accounting. As a result, we were required to discontinue hedge accounting effective February 1, 2003 and reflect the mark-to-market value of the hedges in earnings prospectively from that date. None of our current hedges qualify for hedge accounting.

Our oil production expenses include salaries and benefits of personnel involved in production activities, electric costs, maintenance costs, and other costs necessary to operate our producing properties. Depletion of capitalized costs of producing oil and gas properties is provided using the units of production method based upon proved reserves. For the purposes of computing depletion, proved reserves are redetermined as of the end of each year and on an interim basis when deemed necessary. General and administrative expenses consist primarily of salaries and related benefits of administrative personnel, office rent, systems costs and other administrative costs.

Midstream Operations

We account for our ownership interest in PAA using the equity method of accounting. We record equity in earnings of PAA based on our aggregate ownership interest, as adjusted for general partner incentive distributions. Equity in earnings for our general partner interest is based on our 44% share of 2% of PAA’s net income plus the amount of the general partner incentive distribution. Equity in earnings for our limited partner units is based on our ownership percentage of limited partner units (23% at September 30, 2003) multiplied by 98% of PAA’s net income less the general partner incentive distribution. Increased earnings attributable to the general partner incentive distributions will be somewhat offset because of our ownership of limited partner units. Cash distributions received from PAA are not reflected in earnings, but reduce our ownership interest in PAA.

When PAA sells additional limited partner units and we do not purchase additional units, our ownership interest in PAA is reduced, creating an “implied sale” of a portion of our ownership interest. We have recognized gains from PAA equity issuances representing the difference between our carrying cost and the fair value of the interest deemed sold.

Results of Operations

The following table reflects the components of our oil revenues from continuing operations and sets forth our revenues and costs and expenses from continuing operations on a BOE basis:


		Three Months Ended						Nine Months Ended
		September 30,						September 30,

		2003			2002			2003			2002

Production (MBbls)			197			231			635			708
Sales (MBbls)			211			225			690			643
Sales price per bbl
	Average NYMEX price	$	30.21		$	28.25		$	30.94		$	25.45
	Differential		(6.90	)		(4.60	)		(6.97	)		(3.23	)

			23.31			23.65			23.97			22.22
	Hedging		—			(0.76	)		(0.43	)		(0.66	)

			23.31			22.89			23.54			21.56
	Derivative cash settlements		(2.70	)		—			(2.45	)		—

			20.61			22.89			21.09			21.56
Costs and expenses per bbl
	Production expenses		9.05			7.13			7.66			6.69
	Production and ad valorem taxes		1.19			0.65			1.29			0.58
	Oil transportation expenses		4.35			4.20			4.27			4.32
	DD&A (oil & gas properties)		4.68			3.76			4.74			3.83

In the first quarter of 2003, the NYMEX oil price and the price we receive for our Florida oil production did not correlate closely enough for our hedges to qualify for hedge accounting. As a result, we were required to discontinue hedge accounting effective February 1, 2003 and reflect the mark-to-market value of the derivatives in earnings prospectively from that date. The $2.1 million ($1.0 million, net of tax) net loss in OCI at January 31, 2003 ($0.5 million, $0.3 million net of tax at September 30, 2003) related to these hedges will be recognized in earnings as the related production is delivered. In 2003 the hedging amount relates only to oil sold in January 2003. None of our current derivatives qualify for hedge accounting. Derivative instruments that we enter into in the future may or may not qualify for hedge accounting.

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

Net income was $5.8 million for the third quarter of 2003 compared to income from continuing operations of $3.8 million for the third quarter of 2002. Including income from discontinued operations, net income was $11.2 million for the third quarter of 2002.

Oil revenues. Oil revenues, excluding the effect of hedging, decreased 8%, or $0.4 million, from $5.3 million for the third quarter of 2002 to $4.9 million for the third quarter of 2003. Our average sales price for oil excluding hedging decreased 1%, or $0.34, to $23.31 per Bbl for the third quarter of 2003 from $23.65 per Bbl for the third quarter of 2002. An increase in the NYMEX price to $30.21 per Bbl was more than offset by an increase in the average differential for location and quality from $4.60 per Bbl in 2002 to $6.90 in 2003. Including the effect of hedging, our average realized price for the 2002 period was $22.89 per barrel. After deducting our $2.70 per barrel loss on cash settlements of derivatives our average realized price for the 2003 period was $20.61 per barrel.

Reported sales volumes from our Florida properties were 211 MBbls in 2003 compared to 225 MBbls in 2002. In accordance with SEC Staff Accounting Bulletin 101 we reflect revenue from oil production in the period it is sold as opposed to when it is produced. Oil volumes decreased 15% on an “as produced” basis, with production volumes of 197 MBbls in 2003 compared to 231 MBbls in 2002. The location of our Florida properties and the timing of the barges that transport the oil to market cause reported sales volumes to differ from production volumes. Actual timing of sales volumes is difficult to predict. In addition, our Florida properties consist of a relatively low number of higher volume wells and downtime due to equipment failures and other operational issues can cause production from this area to be volatile.

Production expenses. Production expenses increased 19%, or $0.3 million, to $1.9 million ($9.05 per Bbl) for the third quarter of 2003 from $1.6 million ($7.13 per Bbl) for the third quarter of 2002. The increase is primarily attributable to increased fuel and electricity costs and repairs and maintenance.

Production and ad valorem taxes. Production and ad valorem taxes increased $0.1 million, to $0.3 million for the third quarter of 2003 from $0.2 million for the third quarter of 2002 primarily due to the expiration of severance tax exemptions for several wells in the third quarter of 2002. Unit production and ad valorem taxes for 2003 were $1.19 per Bbl compared to $0.65 per Bbl in 2002.

Oil transportation expenses. Oil transportation expenses was $0.9 million in the third quarter of 2003 and 2002. On a per Bbl basis, gathering and transportation expenses increased to $4.35 per Bbl in 2003 from $4.20 per Bbl in 2002 due to decreased sales volumes.

Depreciation, depletion and amortization. Depreciation, depletion and amortization, or DD&A expense, increased 22%, or $0.2 million, to $1.1 million for the third quarter of 2003 from $0.9 million for the third quarter of 2002. The increase is due to an increase in the per unit DD&A rate ($4.68 per Bbl in 2003 versus $3.76 per Bbl in 2002).

Accretion of asset retirement obligation. Accretion expense for the third quarter of 2003 was $0.1 million. Accretion expense represents the adjustment of our asset retirement obligation to its present value at the end of the period.

Equity in earnings of Plains All American Pipeline, L.P. Our equity in earnings of PAA decreased $1.4 million to $3.1 million for the third quarter of 2003 from $4.5 million for the third quarter of 2002. PAA reported net income of $11.9 million in the third quarter of 2003 compared to $16.3 million in the third quarter of 2002. Our equity in earnings of PAA was reduced by approximately $1.7 million as a result of a $7.4 million compensation accrual by PAA associated with its long term incentive plan and approximately $0.6 million pre-tax as a result of a $2.9 million noncash, derivative mark-to-market loss recognized by PAA. Our ownership interest in PAA averaged 24% in the third quarter of 2003 compared to 27% in the third quarter of 2002.

Gain on Plains All American Pipeline, L.P. unit offerings. In the third quarter of 2003 and 2002 we recognized noncash gains of $9.1 million and $14.5 million, respectively, related to PAA’s public equity offerings in these periods. The gains are recognized to reflect our proportionate share of the increase in the underlying net assets of PAA resulting from the equity offerings.

Gain (loss) on derivatives. As previously discussed, we were required to discontinue hedge accounting effective February 1, 2003. As a result, in the third quarter of 2003 we recorded a $1.2 million loss on derivatives that consisted of a $0.6 million loss reflecting the decrease in the fair value of our derivatives and a $0.6 million loss on cash settlements.

Loss on debt extinguishment. In 2002 we incurred a $10.3 million loss 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 approximately $1.2 million related to unamortized premiums on the 10.25% notes and unamortized issue costs on the 10.25% notes and our credit facility.

Interest expense. Interest expense decreased $1.7 million, to $0.6 million for the third quarter of 2003 from $2.3 million for the third quarter of 2002, primarily reflecting lower outstanding debt.

Income tax expense. Income tax expense increased $0.8 million to $3.8 million for the third quarter of 2003 from $3.0 million for the third quarter of 2002. The increase was primarily due to higher pre-tax income from continuing operations.

Our effective tax rate was 40% in the third quarter of 2003 compared to 44% in the third quarter of 2002. Our effective tax rate reflects the Canadian taxes attributable to our share of PAA’s earnings related to their Canadian operations. For U.S. federal income tax purposes, we utilize net operating loss carryforwards, or NOLs, to reduce our currently payable taxes. As a result, we receive a deduction rather than a credit for Canadian income taxes. Our effective rate for the third quarter of 2003 is lower than our nine months effective rate of 45% due to a downward revision of our estimated annual effective rate in the third quarter.

Income from discontinued operations. Income from discontinued operations of $7.4 million in the third quarter of 2002 reflects the net after tax earnings of PXP, which was spun off in the fourth quarter of 2002.

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

Net income was $14.2 million for the first nine months of 2003 compared to income from continuing operations of $6.0 million for the first nine months of 2002. Including income from discontinued operations net income was $27.5 million in the first nine months of 2002.

Oil revenues. Oil revenues, excluding the effect of hedging, increased 16%, or $2.3 million, from $14.2 million for the first nine months of 2002 to $16.5 million for the first nine months of 2003. The increase was due to increased sales volumes. Our average sales price for oil excluding hedging increased 8%, or $1.75, to $23.97 per Bbl in 2003 from $22.22 per Bbl in 2002. An increase in the NYMEX price to $30.94 per Bbl was partially offset by an increase in the average differential for location and quality from $3.23 per Bbl in 2002 to $6.97 in 2003. Including the effect of hedging our average realized price for 2002 was $21.56 per barrel and our 2003 average realized price was $23.54 per barrel. After deducting our $2.45 per barrel loss on cash settlements of derivatives our average realized price for the 2003 period was $21.09 per barrel.

We reported sales volumes from our Florida properties of 690 MBbls in 2003 compared to 643 MBbls in 2002. In accordance with SEC Staff Accounting Bulletin 101 we reflect revenue from oil production in the period it is sold as opposed to when it is produced. Oil volumes decreased 10% on an “as produced” basis, with production volumes of 635 MBbls in 2003 compared to 708 MBbls in 2002.

Production expenses. Production expenses increased 23%, or $1.0 million, to $5.3 million ($7.66 per Bbl) for the first nine months of 2003 from $4.3 million ($6.69 per Bbl) for the first nine months of 2002. The increase is primarily attributable to increased fuel and electricity costs and higher costs for maintenance and repairs.

Production and ad valorem taxes. Production and ad valorem taxes increased $0.5 million, to $0.9 million for the first nine months of 2003 from $0.4 million for the first nine months of 2002 primarily due to increased sales volumes and the expiration of severance tax exemptions for several wells in the third quarter of 2002. Unit production and ad valorem taxes for 2003 were $1.29 per Bbl compared to $0.58 per Bbl in 2002.

Oil transportation expenses. Oil transportation expenses increased 6%, or $0.2 million, from $2.8 million in the first nine months of 2002 to $3.0 million in the first nine months of 2003. On a per Bbl basis, oil transportation expenses decreased from $4.32 per Bbl in 2002 to $4.27 per Bbl in 2003.

Accretion of asset retirement obligation. Accretion expense for the first nine months of 2003 was $0.2 million. Accretion expense represents the adjustment of our asset retirement obligation to its present value at the end of the period.

Other operating expenses. Other operating expenses for 2003 include a $0.1 million loss on the disposition of materials and supplies inventory.

Equity in earnings of Plains All American Pipeline, L.P. Our equity in earnings of PAA increased $0.8 million to $14.9 million for the first nine months of 2003 from $14.1 million for the first nine months of 2002. PAA reported net income of $59.6 million in the first nine months of 2003 compared to $47.5 million in the first nine months of 2002. Our equity in earnings of PAA was reduced by approximately $1.7 million as a result of a $7.4 million compensation accrual by PAA associated with its long term incentive plan and approximately $0.7 million pre-tax as a result of a $2.9 million noncash, derivative mark-to-market loss recognized by PAA in the third quarter of 2003. Our ownership interest in PAA averaged 24% in 2003 compared to 28% in 2002. The reduction in ownership primarily reflects the effect of PAA’s public unit offerings.

Gain on Plains All American Pipeline, L.P. unit offerings. In the first nine months of 2003 and 2002 we recognized noncash gains of $15.2 million and $14.5 million, respectively, related to PAA’s public equity offerings in these periods. The gains are recognized to reflect our proportionate share of the increase in the underlying net assets of PAA resulting from the equity offerings.

Gain (loss) on derivatives. As previously discussed, we were required to discontinue hedge accounting effective February 1, 2003. As a result, in the first nine months of 2003 we recorded a $3.0 million loss on derivatives that consisted of a $1.3 million loss reflecting the decrease in the fair value of our derivatives and a $1.7 million loss on cash settlements.

Interest expense. Interest expense decreased $4.2 million, to $1.6 million for the first nine months of 2003 from $5.8 million for the first nine months of 2002, primarily reflecting lower outstanding debt.

Income tax expense. Income tax expense increased $5.5 million to $10.7 million for the first nine months of 2003 from $5.2 million for the first nine months of 2002. The increase was primarily due to higher pre-tax income from continuing operations as our effective tax rate was 45% in the first nine months of 2003 compared to 47% in the first nine months of 2002.

Our effective tax rate reflects the Canadian taxes attributable to our share of PAA’s earnings related to their Canadian operations. For U.S. federal income tax purposes, we utilize net operating loss carryforwards, or NOLs, to reduce our currently payable taxes. As a result, we receive a deduction rather than a credit for Canadian income taxes. Current income tax expense for the nine months of 2002 includes a benefit of approximately $2.9 million representing tax paid in 2001 that was refunded to us as the result of certain legislation that allowed us to offset 100% of alternative minimum taxable income with NOLs. Previously, we could only offset 90% of AMT income with NOLs. The current income tax 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.

Cumulative effect of accounting change. In the first quarter of 2003 we recognized a $0.9 million net of tax gain related to the adoption of Statement of Accounting Standards, or SFAS, No. 143, “Accounting for Asset Retirement Obligations”. See “Recent Accounting Pronouncements” for a discussion of the adoption of SFAS No. 143.

Income from discontinued operations. Income from discontinued operations of $21.5 million in the first nine months of 2002 reflects the net after tax earnings of PXP, which was spun off in the fourth quarter of 2002.

Liquidity and Capital Resources

General

At September 30, 2003, we had negative working capital of $20.2 million, primarily reflecting $20.0 million of current maturities of long-term debt. Cash generated from our upstream operations and PAA distributions are our primary sources of liquidity. We believe that we have sufficient liquid assets and cash from operations and PAA distributions to meet our short term and long-term normal recurring operating needs, debt service obligations, contingencies and anticipated capital expenditures.

If PAA could not, for any reason, make its minimum quarterly distribution payments on its limited partnership interests, this would impair our cash flows and our ability to meet our short and long-term cash needs. In addition, this would trigger our payment obligations under the value assurance agreements (see “— Related Party Transactions – Value Assurance Agreements”), which would compound the negative impact on our cash flows and our ability to meet our short and long-term cash needs. Thus, PAA’s financial and operational performance directly affects our financial and operational performance. We encourage you to review PAA’s SEC filings, including its Annual Report on Form 10-K for the year ended December 31, 2002 and its Quarterly Report on Form 10-Q for the quarter ended September 30, 2003.

PAA Cash Distributions

PAA’s partnership agreement requires that it distribute 100% of available cash within 45 days after the end of each quarter to unitholders of record and to its general partner. Available cash is generally defined as all cash and cash equivalents on hand at the end of each quarter less reserves established by PAA’s general partner for future requirements.

Distributions to holders of subordinated units are subject to the rights of holders of common units to receive the minimum quarterly distribution, or MQD, of $0.45 per unit ($1.80 per unit on an annual basis). Common units accrue arrearages with respect to distributions for any quarter during the subordination period and subordinated units do not accrue any arrearages. The subordination period will end if PAA meets certain financial tests for three consecutive four-quarter periods. If PAA meets certain financial requirements, 25% of the subordinated units will convert in the fourth quarter of 2003 and the remainder will convert in the first quarter of 2004.

Class B common units are initially pari passu with common units with respect to distributions, and are convertible into common units upon approval of a majority of the common unitholders. If we request that PAA call a meeting of common unitholders to consider approval of the conversion of Class B units into common units and the approval is not obtained within 120 days, each Class B common unitholder will be entitled to receive distributions, on a per unit basis, equal to 110% of the amount of distributions paid on a common unit, with such distribution right increasing to 115% if such approval is not secured within 90 days after the end of the 120-day period. Except for the vote to approve the conversion, Class B common units have the same voting rights as the common units.

PAA’s general partner is entitled to receive incentive distributions if the amount distributed with respect to any quarter exceeds levels specified in its partnership agreement. Generally the general partner is entitled, without duplication, to 15% of amounts PAA distributes in excess of $0.450 per unit, 25% of the amounts PAA distributes in excess of $0.495 per unit and 50% of amounts PAA distributes in excess of $0.675 per unit.

Based on PAA’s recently declared distribution of $0.55 per unit (an annual distribution rate of $2.20 per unit), which will be paid on November 14, 2003, we would receive an annual distribution from PAA of approximately $31.4 million, including $3.5 million for our 44% share of the general partner distributions (including $2.4 million for the general partner incentive distributions).

Cash distributions per unit on PAA’s outstanding common units, Class B common units and subordinated units and the portion of the distributions representing an excess over the MQD in 2003, 2002 and 2001 were as follows:


	Year

	2003				2002				2001

	Distribution		Excess over MQD		Distribution		Excess over MQD		Distribution		Excess over MQD

First Quarter	$	0.5375	$	0.0875	$	0.5250	$	0.0750	$	0.4750	$	0.0250
Second Quarter	$	0.5500	$	0.1000	$	0.5375	$	0.0875	$	0.5000	$	0.0500
Third Quarter	$	0.5500	$	0.1000	$	0.5375	$	0.0875	$	0.5125	$	0.0625
Fourth Quarter	$	0.5500	$	0.1000	$	0.5375	$	0.0875	$	0.5125	$	0.0625

PAA Subordinated Units

We currently hold approximately 45%, or 4.5 million, of the 10.0 million PAA subordinated units outstanding. The subordination period for these units will end if certain financial tests are met for three consecutive, non-overlapping four-quarter periods (the “testing period”). During the first quarter after the end of the subordination period, all of the subordinated units will convert into common units, and will participate pro rata with all other common units in future distributions. Early conversion of a portion of the subordinated units may occur if the testing period is satisfied before December 31, 2003. According to PAA’s SEC filings, PAA is now in the testing period and, in connection with the payment of the quarterly distribution in November 2003, 25% of the outstanding subordinated units will convert into common units and the remaining subordinated units would convert into common units in the first quarter of 2004. Based on PAA’s September 30, 2003 financial statements, upon the conversion of the subordinated units in the fourth quarter of 2003 we

estimate we would recognize a noncash pre-tax gain of $0 to $10 million. If PAA continues to meet the tests, we estimate we would recognize an additional noncash pre-tax gain of $0 to $25 million when the remaining subordinated units convert to common units in the first quarter of 2004. The actual amount of the gains will be determined based on PAA’s financial statements at the time the subordinated units convert. Such gains are similar to the gains that we have recognized in the past when PAA issues common equity and would be recognized because when the subordinated units are converted to common units they will have all the rights of the current common units, including the right to participate pro rata in future distributions.

Financing Activities

In December 2002, we entered into a $45 million secured term loan facility with a group of banks. We used proceeds from the term loan and cash on hand to make a $40 million capital contribution and repay a $7.2 million note payable to PXP. In June 2003, the facility was restructured to allow us to borrow an additional $24 million that was used to repurchase the 46,600 outstanding shares of our Series D Cumulative Convertible Preferred Stock and pay accrued dividends and related expenses. At September 30, 2003, $55.0 million was outstanding under the secured term loan facility. The term loan is repayable in twelve quarterly installments of $5.0 million each, commencing on August 31, 2003 with a final maturity of May 31, 2006. Amounts outstanding under the term loan bear an annual interest rate, at our election, equal to either the Base Rate (as defined in the agreement) plus 1.5%, or LIBOR plus 3%. The term loan requires that we maintain $5.0 million on deposit in a debt service reserve account with one of the lending banks. Our average borrowing rate for the first nine months of 2003 was 4.3% (4.1% at September 30, 2003).

To secure the term loan, we pledged 100% of the shares of stock of our subsidiaries and pledged 5.2 million of our PAA common units. To the extent the outstanding principal under the term loan exceeds the balance in the debt service reserve account plus 50% of the fair market value of the pledged common units, we are required to repay the excess. The fair market value of the pledged units is determined based on the closing price of PAA common units as reported on the New York Stock Exchange.

Cash Flows from Continuing Operations


		Nine Months Ended September 30,

		2003			2002

		(in millions)
Cash provided by (used in):
	Operating activities	$	18.6		$	(4.2	)
	Investing activities		(3.9	)		(7.0	)
	Financing activities		(22.1	)		(274.9	)

Operating Activities. Net cash provided by (used in) operating activities in the first nine months of 2003 totaled $18.6 million compared to $(4.2) million in the first nine months of 2003. The increase primarily reflects higher revenues in excess of operating costs from our oil and gas operations, higher distributions from PAA and lower interest expense.

Investing Activities. In the first nine months of 2003 net cash used in investing activities totaled $3.9 million compared to $7.0 million in the first nine months of 2002. Oil and gas capital expenditures were $2.4 million in the first nine months of 2003 compared to $5.6 million in the first nine months of 2002. In the first nine months of 2003 we made capital contributions to PAA of $1.5 million, compared to $1.3 million in the first nine months of 2002, to maintain our proportionate general partner share interest as a result of an equity offering by PAA.

Financing activities. Cash used in financing activities in the first nine months of 2003 included a net increase in long-term debt of $10.0 million, $1.5 million in proceeds from issuances of our common stock, expenditures of $9.0 million for the repurchase of 0.8 million shares of our common stock, $23.3 million to redeem our outstanding Series D preferred stock, $0.7 million for the payment of costs incurred in connection with our term loan and $0.6 million for the payment of preferred stock dividends. Cash used in financing activities in the first nine months of 2002 included a net increase in our credit facility of $11.5 million, $267.5 million in payments to retire long-term debt, $4.7 million in proceeds from issuances of our common stock and $0.7 million for the payment of preferred stock dividends.

Capital Expenditures

We have made and will continue to make capital expenditures with respect to our oil properties. In the first nine months of 2003 we made aggregate capital expenditures of $2.4 million for exploitation of our existing properties and expect such expenditures to total $3.5 to $4.0 million in 2003.

When PAA issues equity, the general partner is required to contribute cash to maintain its 2% general partner interest. In March and September 2003, PAA issued units in public equity offerings. We were required to make cash capital contributions to the general partner of PAA totalling $1.5 million for our 44% interest in the general partner. If PAA issues equity in the future, we will be required to make additional cash capital contributions.

We also have an active treasury share repurchase program. Our Board of Directors has authorized the repurchase of up to eight million shares of our common stock. Through December 31, 2001, we had repurchased a total of 4.1 million shares at a total cost of approximately $91.3 million. No shares were repurchased in 2002. We have resumed making purchases under the treasury share program and through September 30, 2003, we have repurchased an additional 0.8 million shares at a total cost of $9.0 million. We intend to make additional repurchases in 2003 and expect to fund the repurchases from cash flows.

Contractual Obligations

At September 30, 2003, the aggregate amounts of contractually obligated payment commitments for the next five years are as follows (in thousands):


	2003		2004		2005		2006		2007		Thereafter

Long-term debt	$	5,000	$	20,000	$	20,000	$	10,000	$	—	$	—
Operating leases		6		23		23		6		—		—

	$	5,006	$	20,023	$	20,023	$	10,006	$	—	$	—

Commitments and Contingencies

In connection with our June 2001 strategic restructuring, we entered into value assurance agreements with the purchasers of the subordinated units in the restructuring, under the terms of which we will pay the purchasers an amount per fiscal year, payable on a quarterly basis, equal to $1.85 per unit less the actual amount distributed during that year. The value assurance agreements will expire upon the earlier of (a) the conversion of all of the subordinated units to common units or (b) June 8, 2006. In the second quarter of 2003 PAA paid a quarterly distribution of $0.55 per unit ($2.20 annualized).

Also in connection with the June 2001 strategic restructuring, 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.

In connection with the reorganization and the spin-off we entered into certain agreements with PXP, including a master separation agreement; an intellectual property agreement; the Plains Exploration & Production transition services agreement; the Plains Resources transition services agreement; and a technical services agreement. 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 spin-off (and related reorganization), regardless of the time those liabilities arise, and to place sole financial responsibility for liabilities associated with our businesses with us and our subsidiaries. We agree to indemnify PXP and PXP agreed to indemnify us against liabilities arising from misstatements or omissions in the various offering documents for the exchange offer related to PXP’s 8.75% notes or the spin-off, if such information was prepared by us or PXP, as the case may be.

In the ordinary course of business, we are a claimant and/or defendant in various legal proceedings. In particular, we are a party to a lawsuit (as a result of Stocker Resources, Inc.’s merger into us) regarding an electric services contract with Commonwealth Energy Corporation. In this lawsuit, we are seeking a declaratory judgment that we are entitled to terminate the contract and that Commonwealth has no basis for proceeding against a related $1.5 million performance bond. In a countersuit against us, Commonwealth is seeking unspecified damages. The two cases have been consolidated and set for trial in December 2003. We intend to defend our rights vigorously in this matter. Under the spin-off agreements, PXP will indemnify us against this lawsuit. While the outcome of these lawsuits cannot be predicted with certainty and could have a material adverse effect on our financial position, we do not believe that the outcome of these legal proceedings, individually or in the aggregate, will have a material adverse effect on our financial condition, results of operations or cash flows.

PAA’s Commitments and Contingencies

For a discussion of PAA’s commitments and contingencies, we recommend you review PAA’s Annual Report on Form 10-K for the year ended December 31, 2002 and its Quarterly Report on Form 10-Q for the quarter ended September 30, 2003, and other applicable SEC filings by PAA.

Related Party Transactions

Governance of PAA

In addition, Plains AAP, L.P., the general partner of PAA, is owned as follows:


Plains Resources	44.00	%
Sable Investments, L.P.	20.00	%
Kafu Holdings, L.P.	16.42	%
E-Holdings, L.P.	9.00	%
Others	10.58	%

	100.00	%

Also, each of we, Sable Investments, Kafu Holdings, and E-Holdings may appoint one member of the Plains All American GP LLC board of directors.

Value Assurance Agreements

Our Relationship with PAA

We have ongoing relationships with PAA, including:

• a marketing agreement that provides that PAA will purchase all of our equity oil production at market prices for a fee of $.20 per barrel. In the first nine months of 2003, sales to PAA under the agreement totaled $19.5 million, including the royalty share of production and PAA charged us $0.1 million in marketing fees; and

• a separation agreement 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.

Spin-off Agreements

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).

Critical Accounting Policies and Factors That May Affect Future Results

Based on the accounting policies that we have in place, certain factors may impact our future financial results. The most significant of these factors relate to our commodity pricing and risk management activities, write-downs under full cost ceiling test rules and oil and gas reserves. These policies and their effect on certain of our accounting policies are discussed in our Annual Report on Form 10-K for the year ended December 31, 2002.

Write-downs under full cost ceiling test rules. Based on the book value of our proved oil and gas properties (including related deferred income taxes) and our estimated proved reserves as of September 30, 2003, we believe that we would have a write-down under the full cost ceiling test rules at a net realized price for our oil production of approximately $17.00 per barrel. Based on an estimated oil differential including oil transportation totaling $11.00 per barrel on September 30, 2003, we would have a write-down at a NYMEX crude oil index price of approximately $28.00 per barrel. The NYMEX crude oil price on September 30, 2003 was $29.20 per barrel.

PAA’s Critical Accounting Policies. For a discussion of PAA’s critical accounting policies, we recommend you review PAA’s Annual Report on Form 10-K for the year ended December 31, 2002 and Quarterly Report on Form 10-Q for the quarter ended September 30, 2003, and other applicable SEC filings by PAA.

Recent Accounting Pronouncements

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

In May 2003, the FASB issued Statement No. 150 “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity.” (SFAS 150). SFAS 150 establishes standards for how an issuer classified and measures certain financial instruments with characteristics of both liabilities and equity. SFAS 150 is generally effective for financial instruments entered into or modified after May 31, 2003, and otherwise is effective at the beginning of the first interim period beginning after June 15, 2003. The adoption of SFAS 150 had no effect on our financial statements.

In January 2003 FASB Interpretation 46, or FIN 46, “Consolidation of Variable Interest Entities was issued. FIN 46 identifies certain off-balance sheet arrangements that meet the definition of a variable interest entity (VIE). The primary beneficiary of a VIE is the party that is exposed to the majority of the risks and/or returns of the VIE. In future accounting periods, the primary beneficiary will be required to consolidate the VIE. In addition, more extensive disclosure requirements apply to the primary beneficiary, as well as other significant investors. We do not believe we participate in any arrangement that would be subject to the provisions of FIN 46.

Statement Regarding Forward-Looking Statements

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

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

•
the consequences of our and PXP’s officers and employees providing services to both us and PXP and not being required to spend any specified percentage or amount of time on our business;

•
risks, uncertainties and other factors that could have an impact on PAA which could in turn impact the value of our holdings in PAA (for a discussion of these risks, uncertainties and other factors, see PAA’s filings with the SEC);

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

• uncertainties inherent in the 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, industry 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 discussed 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. Except as required by applicable securities laws, we do not intend to update these forward-looking statements and information. See “Critical Accounting Policies and Factors That May Affect Future Results” in this report for additional discussions of risks and uncertainties.

ITEM 3. – Quantitative and Qualitative Disclosures About Market Risks

We are exposed to various market risks, including volatility in oil commodity prices and interest rates. 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.

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. The agreements provide for monthly cash settlement based on the differential between the agreement price and the actual NYMEX price. Derivative instruments are accounted for in accordance with SFAS No. 133 “Accounting for Derivative Instruments and Hedging Activities” as amended by SFAS 137, SFAS 138 and SFAS 149, 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.

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 at least 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 how the hedging instrument’s effectiveness will be assessed. 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. Gains and losses deferred in OCI related to cash flow hedges that become ineffective remain unchanged until the related product is delivered. If it is determined that it is probable that a hedged forecasted transaction will not occur, deferred gains or losses on the hedging instrument are recognized in earnings immediately.

Commodity Price Risk. At October 31, 2003, we had the following open oil derivative positions:


		Barrels per Day

		2003		2004		2005		2006

Swaps
	Average price $26.10/bbl		1,500		—		—		—
	Average price $25.01/bbl		—		1,500		—		—
	Average price $24.70/bbl		—		—		1,000		—
	Average price $24.43/bbl		—		—		—		1,000

Assuming our third quarter 2003 production volumes are held constant in subsequent periods, these positions represent approximately 70%, 70%, 47%, and 47% of oil production in 2003, 2004, 2005 and 2006, respectively. Location and quality differentials attributable to our properties are not included in the foregoing prices. Because of the quality and location of our oil production, these adjustments will reduce our net realized price per barrel.

Our management intends to continue to maintain derivative arrangements for a significant portion of our production. These contracts may expose us to the risk of financial loss in certain circumstances. Such arrangements provide us protection if oil prices decline below the prices at which the derivatives are set, but ceiling prices in our derivatives may cause us to receive less revenue on the specified volumes than we would receive in the absence of the derivatives. Such arrangements may or may not qualify for hedge accounting. The contract counterparties for our current derivative commodity contracts are all major financial institutions with Standard & Poor’s ratings of A or better.

Interest Rate Risk. Our debt instruments are sensitive to market fluctuations in interest rates. At September 30, 2003 we had $55.0 million outstanding under our term loan, repayable $5.0 million in 2003, $20.0 million in 2004, $20.0 million in 2005 and $10.0 million in 2006. Our term loan bears interest at a base rate (as defined) or LIBOR plus 3%. The carrying value of our term loan approximates fair value because interest rates are variable, based on prevailing market rates.

ITEM 4. – Controls and Procedures

Under the supervision and with the participation of our management, including our Chief Executive Officer (our principal executive officer) and our Chief Financial Officer (our principal financial officer), we evaluated the effectiveness of our disclosure controls and procedures (as defined under Rule 13a-14(c) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”)). Based on this evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that our disclosure controls and procedures as of September 30, 2003 are effective to ensure that information we are required to disclose in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.

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

PART II. OTHER INFORMATION

Item 1 – Legal Proceedings

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

We are a party to a lawsuit (as a result of Stocker Resources, Inc.’s merger into us) regarding an electric services contract with Commonwealth Energy Corporation. In this lawsuit, we are seeking a declaratory judgment that we are entitled to terminate the contract and that Commonwealth has no basis for proceeding against a related $1.5 million performance bond. In a countersuit against us, Commonwealth is seeking unspecified damages. The two cases have been consolidated and set for trial in December 2003. We intend to defend our rights vigorously in this matter. Under the spin-off agreements, PXP will indemnify us against this lawsuit.

Item 6 – Exhibits and Reports on Form 8-K

(a) Exhibits


	10.1		Employment Agreement, dated as of September 8, 2003, by and between Stephen A. Thorington and the Company.

	31.1		Certification of Chief Executive Officer, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

	31.2		Certification of Chief Financial Officer, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

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

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

(b) Reports on Form 8-K

A Current Report on Form 8-K was filed on August 12, 2003 with respect to (i) estimates of certain results for the three months ended September 30, 2003 and the year ended December 31, 2003; and (ii) the Company’s press release reporting second quarter 2003 earnings.

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

SIGNATURES

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


	PLAINS RESOURCES INC.

Date: November 13, 2003	By:	/s/ Stephen A. Thorington

		Stephen A. Thorington Executive Vice President and Chief Financial Officer (Principal Financial and Accounting Officer)

Exhibit Index


Exhibit Number		Description

10.1		Employment Agreement, dated as of September 8, 2003, by and between Stephen A. Thorington and the Company.

31.1		Certification of Chief Executive Officer, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2		Certification of Chief Financial Officer, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

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

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

	•		a marketing agreement that provides that PAA will purchase all of our equity oil production at market prices for a fee of $.20 per barrel. In the first nine months of 2003, sales to PAA under the agreement totaled $19.5 million, including the royalty share of production and PAA charged us $0.1 million in marketing fees; and

	•		a separation agreement 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.

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

	•		the consequences of our and PXP’s officers and employees providing services to both us and PXP and not being required to spend any specified percentage or amount of time on our business;

	•		risks, uncertainties and other factors that could have an impact on PAA which could in turn impact the value of our holdings in PAA (for a discussion of these risks, uncertainties and other factors, see PAA’s filings with the SEC);

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

	•		uncertainties inherent in the 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, industry or business conditions.