Edgar Filing: VINTAGE PETROLEUM INC

FORM 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended September 30, 2004

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

For the transition period from to

Commission file number 1-10578

VINTAGE PETROLEUM, INC.

(Exact name of registrant as specified in charter)


Delaware		73-1182669
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

110 West Seventh Street Tulsa, Oklahoma		74119-1029
(Address of principal executive offices)		(Zip Code)

(918) 592-0101

(Registrant’s telephone number, including area code)

NOT APPLICABLE

(Former name, former address and former fiscal year, if changed since last report)

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 x No ¨

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

Yes x No ¨

Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date.


Class		Outstanding at October 29, 2004
Common Stock, $0.005 Par Value		65,749,693

VINTAGE PETROLEUM, INC.

FORM 10-Q

THREE MONTHS ENDED SEPTEMBER 30, 2004

TABLE OF CONTENTS


		Page

PART I.	FINANCIAL INFORMATION

Item 1.	Financial Statements

	Consolidated Balance Sheets as of September 30, 2004, and December 31, 2003	4

	Consolidated Statements of Operations for the Three Months and Nine Months Ended September 30, 2004 and 2003	6

	Consolidated Statement of Changes in Stockholders’ Equity and Comprehensive Income for the Nine Months Ended September 30, 2004	8

	Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2004 and 2003	9

	Notes to Unaudited Consolidated Financial Statements	10

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	26

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	43

Item 4.	Controls and Procedures	49

PART II.	OTHER INFORMATION

Item 1.	Legal Proceedings	51

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	51

Item 3.	Defaults Upon Senior Securities	51

Item 4.	Submission of Matters to a Vote of Security Holders	52

Item 5.	Other Information	52

Item 6.	Exhibits	52

	Signatures	53

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PART I

FINANCIAL INFORMATION

-3-

ITEM 1. FINANCIAL STATEMENTS

VINTAGE PETROLEUM, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In thousands, except shares

and per share amounts)

(Unaudited)

ASSETS


	September 30, 2004		December 31, 2003
CURRENT ASSETS:
Cash and cash equivalents	$	46,012	$	32,264
Accounts receivable -
Oil and gas sales		115,861		78,321
Joint operations		8,616		7,480
Deferred income taxes		21,513		—
Prepaids and other current assets		10,638		6,660
Assets of discontinued operations		253,387		224,321

Total current assets		456,027		349,046

PROPERTY, PLANT AND EQUIPMENT, at cost:
Oil and gas properties, successful efforts method		2,023,933		1,835,588
Oil and gas gathering systems and plants		23,890		23,344
Other		27,903		26,334

		2,075,726		1,885,266
Less accumulated depreciation, depletion and amortization		908,462		829,055

Total property, plant and equipment, net		1,167,264		1,056,211

DEFERRED INCOME TAXES		14,558		—

OTHER ASSETS, net		42,513		41,581

TOTAL ASSETS	$	1,680,362	$	1,446,838

See notes to unaudited consolidated financial statements.

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VINTAGE PETROLEUM, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Continued)

(In thousands, except shares

and per share amounts)

(Unaudited)

LIABILITIES AND STOCKHOLDERS’ EQUITY


	September 30, 2004		December 31, 2003
CURRENT LIABILITIES:
Revenue payable	$	37,541	$	22,641
Accounts payable - trade		53,578		48,548
Current income taxes payable		21,815		17,316
Derivative financial instruments payable		59,968		7,551
Other payables and accrued liabilities		88,796		54,852
Liabilities of discontinued operations		79,454		46,093

Total current liabilities		341,152		197,001

LONG-TERM DEBT		676,547		699,943

DEFERRED INCOME TAXES		85,214		54,311

LONG-TERM LIABILITY FOR ASSET RETIREMENT OBLIGATIONS		77,577		72,158

DERIVATIVE FINANCIAL INSTRUMENTS PAYABLE AND OTHER		16,338		939

COMMITMENTS AND CONTINGENCIES (Note 5)
STOCKHOLDERS’ EQUITY, per accompanying statement:
Preferred stock, $0.01 par, 5,000,000 shares authorized, zero shares issued and outstanding		—		—
Common stock, $0.005 par, 160,000,000 shares authorized, 66,181,811 and 64,720,975 shares issued and 65,657,693 and 64,281,199 outstanding, respectively		331		324
Capital in excess of par value		354,217		337,080
Retained earnings		96,974		22,844
Accumulated other comprehensive income		40,293		70,482

		491,815		430,730
Less treasury stock, at cost, 524,118 and 439,776 shares		4,319		3,117
Less unamortized cost of restricted stock awards		3,962		5,127

Total stockholders’ equity		483,534		422,486

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	1,680,362	$	1,446,838

See notes to unaudited consolidated financial statements.

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VINTAGE PETROLEUM, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share amounts)

(Unaudited)


	Three Months Ended September 30,						Nine Months Ended September 30,
	2004			2003			2004			2003
REVENUES:
Oil, condensate and NGL sales	$	136,382		$	105,269		$	367,320		$	323,806
Gas sales		49,158			25,282			127,284			86,545
Sulfur sales		234			440			949			1,305
Gas marketing		17,897			15,445			50,131			59,978

Total revenues		203,671			146,436			545,684			471,634

COSTS AND EXPENSES:
Production costs		34,335			33,266			105,379			91,329
Transportation and storage costs		3,318			1,761			7,500			5,120
Production and ad valorem taxes		5,732			3,997			16,557			12,756
Export taxes		12,778			7,409			25,691			25,814
Exploration costs		12,435			6,061			21,000			17,395
Gas marketing		16,857			14,798			47,409			58,093
General and administrative		12,806			11,848			41,723			34,667
Stock compensation		1,153			1,861			7,091			4,295
Depreciation, depletion and amortization		26,720			21,392			72,687			65,463
Impairment of proved oil and gas properties		—			—			3,915			—
Accretion		1,685			1,523			4,932			4,422
Other operating (income) expense		1,671			(701	)		(1,933	)		941

Total costs and expenses		129,490			103,215			351,951			320,295

OPERATING INCOME		74,181			43,221			193,733			151,339

OTHER (INCOME) EXPENSE:
Interest expense		12,625			17,818			39,321			54,328
Loss on early extinguishment of debt		—			—			9,903			1,426
(Gain) loss on disposition of assets		(17	)		—			(72	)		667
Foreign currency exchange (gain) loss		(285	)		(915	)		(1,112	)		6,653
Other non-operating expense		15,721			818			15,991			41

Net other expense		28,044			17,721			64,031			63,115

Income from continuing operations before income taxes and cumulative effect of change in accounting principle		46,137			25,500			129,702			88,224

INCOME TAX PROVISION (BENEFIT):
Current		15,701			5,128			44,114			39,609
Deferred		3,024			5,034			5,115			(2,057	)

Total income tax provision		18,725			10,162			49,229			37,552

Income from continuing operations before cumulative effect of change in accounting principle		27,412			15,338			80,473			50,672
INCOME (LOSS) FROM DISCONTINUED OPERATIONS, net of income tax provision (benefit) of $(184), $221, $130 and $25,480		(397	)		(3,583	)		3,086			(14,042	)

Income before cumulative effect of change in accounting principle		27,015			11,755			83,559			36,630
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE, net of income tax provision of $4,104		—			—			—			7,119

NET INCOME	$	27,015		$	11,755		$	83,559		$	43,749

See notes to unaudited consolidated financial statements.

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VINTAGE PETROLEUM, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Continued)

(In thousands, except per share amounts)

(Unaudited)


	Three Months Ended September 30,						Nine Months Ended September 30,
	2004			2003			2004		2003
BASIC INCOME (LOSS) PER SHARE:
Income from continuing operations before cumulative effect of change in accounting principle	$	0.42		$	0.24		$	1.24	$	0.79
Income (loss) from discontinued operations		(0.01	)		(0.06	)		0.05		(0.22	)

Income before cumulative effect of change in accounting principle		0.41			0.18			1.29		0.57
Cumulative effect of change in accounting principle		—			—			—		0.11

Net income	$	0.41		$	0.18		$	1.29	$	0.68

DILUTED INCOME (LOSS) PER SHARE:
Income from continuing operations before cumulative effect of change in accounting principle	$	0.42		$	0.24		$	1.23	$	0.79
Income (loss) from discontinued operations		(0.01	)		(0.06	)		0.05		(0.22	)

Income before cumulative effect of change in accounting principle		0.41			0.18			1.28		0.57
Cumulative effect of change in accounting principle		—			—			—		0.11

Net income	$	0.41		$	0.18		$	1.28	$	0.68

Weighted average common shares outstanding:
Basic		65,283			64,228			64,786		63,938

Diluted		66,043			64,767			65,521		64,292

See notes to unaudited consolidated financial statements.

-7-

VINTAGE PETROLEUM, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY

AND COMPREHENSIVE INCOME

FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2004

(In thousands, except treasury shares and per share amounts)

(Unaudited)


	Common Stock			Treasury Stock			Capital In Excess of Par Value			Unamortized Restricted Stock Awards			Retained Earnings			Accumulated Other Comprehensive Income			Total
	Shares	Amount		Treasury Stock			Capital In Excess of Par Value			Unamortized Restricted Stock Awards			Retained Earnings			Accumulated Other Comprehensive Income			Total
BALANCE AT DECEMBER 31, 2003	64,721	$	324	$	(3,117	)	$	337,080		$	(5,127	)	$	22,844		$	70,482		$	422,486
Comprehensive income:
Net income	—		—		—			—			—			83,559			—			83,559
Foreign currency translation adjustment	—		—		—			—			—			—			4,525			4,525
Change in value of derivatives, net of tax	—		—		—			—			—			—			(34,714	)		(34,714	)

Total comprehensive income																				53,370
Stock options granted	—		—		—			377			—			—			—			377
Exercise of stock options and resulting tax effects	1,225		6		—			11,212			—			—			—			11,218
Issuance of restricted stock	176		1		—			2,651			(2,652	)		—			—			—
Amortization of restricted stock awards	—		—		—			3,057			3,751			—			—			6,808
Forfeitures of restricted stock (11,845 shares)	—		—		—			(160	)		66			—			—			(94	)
Vesting of restricted stock rights	60		—		—			—			—			—			—			—
Purchase of treasury stock (72,497 shares)	—		—		(1,202	)		—			—			—			—			(1,202	)
Cash dividends declared ($0.145 per share)	—		—		—			—			—			(9,429	)		—			(9,429	)

BALANCE AT SEPTEMBER 30, 2004	66,182	$	331	$	(4,319	)	$	354,217		$	(3,962	)	$	96,974		$	40,293		$	483,534

See notes to unaudited consolidated financial statements.

-8-

VINTAGE PETROLEUM, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)


	Nine Months Ended September 30,
	2004			2003
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	83,559		$	43,749
Adjustments to reconcile net income to cash provided by operating activities -
(Income) loss from discontinued operations, net of tax		(3,086	)		14,042
Cumulative effect of change in accounting principle, net of tax		—			(7,119	)
Depreciation, depletion and amortization		72,687			65,463
Impairment of proved oil and gas properties		3,915			—
Accretion		4,932			4,422
Exploration costs		16,733			9,910
Provision (benefit) for deferred income taxes		5,115			(2,057	)
Foreign currency exchange (gain) loss		(1,112	)		6,653
(Gain) loss on dispositions of assets		(72	)		667
Loss on early extinguishment of debt		9,903			1,426
Stock compensation		7,091			4,295
Non-cash charges from hedging activities		15,361			691
Other non-cash items included in net income		424			1,953
Increase in receivables		(5,532	)		(2,100	)
Increase in payables and accrued liabilities		9,923			9,490
Other working capital changes		1,727			4,265

Cash provided by continuing operations		221,568			155,750
Cash provided by discontinued operations		34,646			16,406

Cash provided by operating activities		256,214			172,156

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures -
Oil and gas properties		(159,538	)		(100,041	)
Gathering systems and other		(2,132	)		(3,232	)
Proceeds from sale of oil and gas properties		67			29,980
Purchase of company, net of cash acquired		(26,757	)		—
Proceeds from sale of company, net of cash sold		—			116,107
Other		2,454			(4,153	)

Cash provided (used) by investing activities - continuing operations		(185,906	)		38,661
Cash provided (used) by investing activities - discontinued operations		(23,785	)		8,311

Cash provided (used) by investing activities		(209,691	)		46,972

CASH FLOWS FROM FINANCING ACTIVITIES:
Issuance of common stock		11,218			1,122
Purchase of treasury stock		(1,202	)		(3,013	)
Redemption of senior subordinated notes		(157,313	)		(50,750	)
Advances on revolving credit facility and other borrowings		370,100			115,400
Payments on revolving credit facility and other borrowings		(243,500	)		(151,017	)
Dividends paid		(9,042	)		(7,971	)
Other		(3,668	)		1

Cash used by financing activities		(33,407	)		(96,228	)

EFFECT OF EXCHANGE RATE CHANGES ON CASH		632			480

NET INCREASE IN CASH AND CASH EQUIVALENTS		13,748			123,380
CASH AND CASH EQUIVALENTS, beginning of period		32,264			8,128

CASH AND CASH EQUIVALENTS, end of period	$	46,012		$	131,508

See notes to unaudited consolidated financial statements.

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VINTAGE PETROLEUM, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2004 and 2003

1.	GENERAL

The accompanying financial statements are unaudited. The consolidated financial statements include the accounts of Vintage Petroleum, Inc. and its wholly- and majority-owned subsidiaries and its proportionately consolidated general partner and limited partner interests in various joint ventures and partnerships (collectively, the “Company”). Management believes that all material adjustments (consisting of only normal recurring adjustments) necessary for a fair presentation have been made. Certain 2003 amounts have been reclassified to conform with the 2004 presentation, including reclassifications required for presentation of the discontinued operations discussed in Note 8. These reclassifications had no effect on the Company’s net income or stockholders’ equity. All significant intercompany accounts and transactions have been eliminated in consolidation.

The preparation of financial statements in conformity with accounting principles generally accepted in the U.S. (“GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. These financial statements and notes should be read in conjunction with the 2003 audited financial statements and related notes included in the Company’s 2003 Annual Report on Form 10-K, Item 8. Financial Statements and Supplementary Data.

2.	SIGNIFICANT ACCOUNTING POLICIES

Oil and Gas Properties

Under the successful efforts method of accounting, the Company capitalizes all costs related to property acquisitions and successful exploratory wells, all development costs and the costs of support equipment and facilities. Certain costs of exploratory wells are capitalized pending determination that proved reserves have been found. Such determination may be dependent upon the results of planned additional wells and the cost of required capital expenditures to produce the reserves found. All costs related to unsuccessful exploratory wells are expensed when such wells are determined to be non-productive; other exploration costs, including geological and geophysical costs, are expensed as incurred. Delineation seismic costs incurred to select development locations within a productive oil and gas field are capitalized. The Company capitalized development seismic costs of $5.3 million and $1.5 million for the nine months ended September 30, 2004 and 2003, respectively. The Company recognizes gains or losses on the sale of properties on a field basis.

-10-

Unproved leasehold costs are capitalized and reviewed periodically for impairment. Individual unproved properties whose acquisition costs are significant are assessed on a property-by-property basis, considering factors such as future drilling and exploitation plans and lease terms. For unproved properties whose acquisition costs are not individually significant, the amount of those properties’ impairment is determined by amortizing the properties in groups on the basis of the Company’s experience in similar situations and other information such as the primary lease terms, the average holding period of unproved properties and the relative proportion of such properties on which proved reserves have been found in the past. Costs related to impaired prospects are charged to expense and included in “exploration costs” in the accompanying statements of operations. The Company recorded leasehold impairments of $2.5 million and $2.8 million for the nine months ended September 30, 2004 and 2003, respectively, and $1.1 million and $0.5 million for the three months ended September 30, 2004 and 2003, respectively, excluding the Company’s discontinued operations in Canada (see Note 8). Additional impairment expense could result if oil and gas prices decline in the future or if downward reserve revisions are recorded on nearby properties, as it may not be economic to develop some of these unproved properties. The Company’s Canadian leasehold impairments were $4.3 million and $30.2 million for the nine months ended September 30, 2004 and 2003, respectively, and $1.2 million and $1.3 million for the three months ended September 30, 2004 and 2003, respectively. Leasehold impairments in Canada for the first nine months of 2003 included an expense of $23.7 million to fully impair the Company’s undeveloped leaseholds in the Northwest Territories.

As of September 30, 2004, the Company had unproved oil and gas property costs of approximately $28.6 million, excluding Canada, consisting of undeveloped leasehold costs of $15.3 million and unevaluated exploratory drilling costs of $13.3 million. Approximately $13.1 million of the total unevaluated costs are associated with the Company’s drilling program in Yemen.

Costs of development dry holes and proved leaseholds are amortized on the unit-of-production method using proved reserves on a field basis. The depreciation of capitalized production equipment, drilling costs and asset retirement obligations is based on the unit-of-production method using proved developed reserves on a field basis.

In August 2001, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations (“SFAS 143”). The Company was required to adopt this new standard beginning January 1, 2003. Through December 31, 2002, the Company accrued an estimate of future abandonment costs of wells and related facilities through its depreciation calculation and included the cumulative accrual in accumulated depreciation in accordance with the provisions of Statement of Financial Accounting Standards No. 19, Financial Accounting and Reporting by Oil and Gas Producing Companies, and industry practice. SFAS 143 requires that the Company record the discounted fair value of the retirement obligation as a liability at the time a well is drilled or acquired. The asset retirement obligations consist primarily of costs associated with the plugging and abandonment of oil and gas wells, site reclamation and facilities dismantlement. However, future abandonment liabilities are also recorded for other assets such as pipelines, processing plants and compressors. A corresponding amount is capitalized as part of the related property’s carrying amount. The discounted capitalized asset retirement cost is amortized to expense through the depreciation calculation over the estimated useful life of the asset based on proved developed reserves. The liability accretes over time with a charge to accretion expense. At September 30, 2004 and December 31, 2003, there were no assets legally restricted for purposes of settling asset retirement obligations. Of the liability for asset retirement obligations balance at September 30, 2004, approximately $6.5 million is classified as current and is included in “other payables and accrued liabilities” in the accompanying balance sheet.

-11-

The Company adopted SFAS 143 effective January 1, 2003, and recorded an increase in property, plant and equipment of $50.3 million, a decrease in accumulated depreciation, depletion and amortization of $43.9 million, an increase in current asset retirement liabilities of $4.5 million, an increase in long-term asset retirement liabilities of $78.5 million, a $4.1 million increase in deferred income tax liabilities and a non-cash gain as a result of the cumulative effect of change in accounting principle, net of tax, of $7.1 million.

The Company recorded the following activity related to the asset retirement liability for the nine months ended September 30, 2004 (in thousands):


Liability for asset retirement obligations as of January 1, 2004	$	76,918
New obligations for wells drilled		471
New obligations for interests acquired		2,691
Costs incurred		(1,056	)
Accretion expense		4,932
Revisions in estimated cash flows		125

Liability for asset retirement obligations as of September 30, 2004	$	84,081

These amounts do not include the liability for asset retirement obligations that is associated with the Company’s Canadian operations, which was $18.0 million at January 1, 2004, and $18.9 million at September 30, 2004. These amounts are included in “liabilities of discontinued operations” in the accompanying balance sheets.

The Company reviews its proved oil and gas properties for impairment on a field basis. For each field, an impairment provision is recorded whenever events or circumstances indicate that the carrying value of those properties may not be recoverable from estimated future net revenues. The impairment provision is based on the excess of carrying value over fair value. Fair value is defined as the present value of the estimated future net revenues from production of total proved and risk-adjusted probable and possible oil and gas reserves over the economic life of the reserves, based on the Company’s expectations of future oil and gas prices and costs, consistent with price and cost assumptions used for acquisition evaluations. In the first quarter of 2004, the Company recorded an impairment of $3.9 million related to one proved oil and gas property in the U.S. The Company recorded no impairment provisions related to the proved oil and gas properties of its continuing operations during the second or third quarters of 2004 or the first nine months of 2003. In the first nine months of 2003, the Company recorded impairment provisions of $14.0 million related to its Canadian proved oil and gas properties. The Company recorded no impairments to its Canadian properties in the first nine months of 2004.

Statements of Cash Flows

During the nine months ended September 30, 2004 and 2003, the Company made cash payments for interest totaling approximately $27.5 million, and $40.0 million, respectively. The Company had no cash payments for U.S. income taxes in the first nine months of 2004. Cash payments for U.S. income taxes of $41.1 million were made during the first nine months of 2003. The Company made cash payments for income taxes of $48.2 million and $38.6 million in Argentina during the first nine months of 2004 and 2003, respectively. The Company made cash payments for income taxes of $1.2 million and $1.6 million in Canada during the first nine months of 2004 and 2003, respectively.

-12-

Hedging

The Company periodically uses hedges to reduce the impact of oil and natural gas price fluctuations. The Company accounts for its hedging activities under the provisions of Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities (as amended, “SFAS 133”). SFAS 133 establishes accounting and reporting standards requiring that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded in the balance sheet as either an asset or liability measured at its fair value. SFAS 133 requires that changes in the derivative’s fair value be recognized currently in earnings unless specific hedge accounting criteria are met. Special accounting for qualifying hedges allows a derivative’s gains and losses to offset related results on the hedged item in the statement of operations. Companies must formally document, designate and assess the effectiveness of transactions that receive hedge accounting treatment.

For derivative instruments that qualify as cash flow hedges, the effective portion of the gain or loss on a derivative instrument is reported as a component of other comprehensive income and reclassified into sales revenue in the same period or periods during which the hedged forecasted transaction affects earnings. The effective portion is determined by comparing the cumulative change in fair value of the derivative to the cumulative change in the present value of the expected cash flows of the item being hedged. To the extent the cumulative change in the derivative exceeds the cumulative change in the present value of expected cash flows, the excess is recognized currently in earnings. If the cumulative change in present value of the expected cash flows exceeds the change in fair value of the derivative, the difference is ignored. Changes in the fair value of derivative financial instruments that do not qualify for accounting treatment as hedges, if any, are recognized currently as “other non-operating (income) expense.” The cash flows from such agreements are included in operating activities in the consolidated statements of cash flows.

General and Administrative Expense

The Company receives fees for the operation of jointly-owned oil and gas properties and records such reimbursements as reductions of general and administrative expense. Such fees totaled approximately $2.3 million and $2.4 million for the first nine months of 2004 and 2003, respectively, and $0.9 million and $0.6 million for the third quarters of 2004 and 2003, respectively. These amounts exclude reimbursements related to the Company’s discontinued operations in Canada.

Income Per Share

Basic income per common share was computed by dividing net income by the weighted average number of shares outstanding during the period. Diluted income per common share for all periods presented was computed assuming the exercise of all dilutive options, as determined by applying the treasury stock method, and assuming the vesting of all restricted stock rights.

-13-

The following table reconciles the weighted average common shares outstanding used in the calculations of basic and diluted income per share (in thousands):


	Three Months Ended September 30,		Nine Months Ended September 30,
	2004	2003	2004	2003
Weighted average common shares outstanding - Basic	65,283	64,228	64,786	63,938
Dilutive effect of potential common shares issuable upon the exercise of outstanding stock options	538	374	553	212
Dilutive effect of potential common shares issuable upon the vesting of outstanding restricted stock rights	222	165	182	142

Weighted average common shares outstanding - Diluted	66,043	64,767	65,521	64,292

Certain options to purchase shares of the Company’s common stock have been excluded from the dilution calculations because the assumed exercise of these options was anti-dilutive. The anti-dilutive options will dilute basic earnings per share in the future, if exercised, and may impact diluted earnings per share in the future depending on the market price of the Company’s common stock. The following information relates to these options:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2004		2003		2004		2003
Options excluded from dilution calculations (in thousands)		55		819		654		836
Range of exercise prices	$	17.31 - $22.94	$	11.44 - $22.94	$	15.50 - $22.94	$	10.88 - $22.94
Weighted average exercise price	$	19.70	$	15.67	$	15.86	$	15.67

Stock Compensation

The Company has two fixed stock-based compensation plans which reserve shares of common stock for issuance to key employees and directors. Prior to 2003, the Company accounted for these plans under the recognition and measurement provisions of Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees, and related interpretations. Compensation for restricted stock awards is recorded over the vesting periods of the awards. No stock compensation expense related to stock options granted prior to 2003 has been recognized, as all options granted under these plans had an exercise price equal to the market value of the underlying common stock on the grant date.

-14-

Effective January 1, 2003, the Company adopted the fair value recognition provisions of Statement of Financial Accounting Standards No. 123, Accounting for Stock-Based Compensation (“SFAS 123”). The Company adopted these provisions prospectively and will apply them to all employee and director awards granted, modified, or settled after January 1, 2003. Stock option awards under the Company’s plans generally vest over three years, therefore, the cost related to stock compensation included in the determination of net income for the first nine months of 2004 and 2003 and for the third quarters of 2004 and 2003 is less than that which would have been recognized if the fair value based method had been applied to all awards since the original effective date of SFAS 123. The following table illustrates the effect on net income and income per share if the fair value based method had been applied to all outstanding and unvested awards in each period (in thousands, except per share amounts):


	Three Months Ended September 30,				Nine Months Ended September 30,
	2004		2003		2004		2003
Stock compensation expense - as reported	$	1,153	$	1,861	$	7,091	$	4,295
Stock compensation expense - pro forma		1,174		1,974		7,185		5,031
Net income - as reported		27,015		11,755		83,559		43,749
Net income - pro forma		27,002		11,684		83,499		43,246
Income per share - as reported:
Basic		0.41		0.18		1.29		0.68
Diluted		0.41		0.18		1.28		0.68
Income per share - pro forma:
Basic		0.41		0.18		1.29		0.68
Diluted		0.41		0.18		1.27		0.67

The fair value of each option grant is estimated on the date of grant using the Black-Scholes option-pricing model.

Comprehensive Income

Comprehensive income consists of the following (in thousands):


	Three Months Ended September 30,						Nine Months Ended September 30,
	2004			2003			2004			2003
Net income	$	27,015		$	11,755		$	83,559		$	43,749
Foreign currency translation adjustments		9,355			(1,733	)		4,525			73,965
Changes in value of derivatives, net of tax		(20,891	)		10,541			(34,714	)		7,732

Comprehensive income	$	15,479		$	20,563		$	53,370		$	125,446

The foreign currency translation adjustments shown above relate entirely to the translation of the financial statements of the Company’s Canadian subsidiary from its functional currency (the Canadian dollar) to the Company’s reporting currency (the U.S. dollar).

-15-

The changes in the value of derivatives, net of tax consist of the following (in thousands):


	Three Months Ended September 30,					Nine Months Ended September 30,
	2004			2003		2004			2003
Unrealized gain (loss) during the period	$	(31,939	)	$	13,384	$	(56,614	)	$	(1,320	)
Reclassification adjustment for losses included in net income		409			3,332		2,342			14,249

		(31,530	)		16,716		(54,272	)		12,929
Income tax provision (benefit)		(10,639	)		6,175		(19,558	)		5,197

Changes in value of derivatives, net of tax	$	(20,891	)	$	10,541	$	(34,714	)	$	7,732

The accumulated balance for each item in accumulated other comprehensive income is as follows (in thousands):


	September 30, 2004			December 31, 2003
Foreign currency translation adjustments	$	77,076		$	72,551
Changes in value of derivatives, net of tax		(36,783	)		(2,069	)

	$	40,293		$	70,482

Accumulated other comprehensive income related to the Company’s discontinued Canadian operations was $75.8 million, consisting of cumulative foreign currency translation adjustment gains of $77.1 million and accumulated losses from changes in the values of commodity hedges of $1.3 million, as of September 30, 2004. All of the existing Canadian commodity hedges will settle by November 30, 2004. In accordance with Statement of Financial Accounting Standards No. 52, Foreign Currency Translation, upon the sale of the Company’s investment in Canada, the cumulative foreign currency translation adjustment gains will be removed from accumulated other comprehensive income and will be reported as part of the gain on the sale of the investment for the period during which the sale occurs.

3.	LONG-TERM DEBT

Long-term debt at September 30, 2004, and December 31, 2003, consisted of the following (in thousands):


	September 30, 2004		December 31, 2003
Revolving credit facility	$	126,600	$	—
8 1/4% Senior Notes due 2012		350,000		350,000
Senior Subordinated Notes:
9 3/4% Notes due 2009		—		150,000
7 7/8% Notes due 2011, less unamortized discount		199,947		199,943

	$	676,547	$	699,943

-16-

During February 2004, the Company advanced funds under its revolving credit facility to redeem the entire principal balance of the 9 3/4% senior subordinated notes due 2009. As a result, the Company was required to expense certain associated deferred financing costs. This $2.6 million non-cash charge and a $7.3 million cash charge for the call premium resulted in a one-time charge of approximately $9.9 million ($6.0 million net of tax).

In May 2004, the Company’s revolving credit facility was amended. The Company’s borrowing base was raised to $325 million and the maturity of the revolving credit facility was extended to May 2, 2008.

The Company had $18.6 million and $7.4 million of accrued interest payable related to its long-term debt at September 30, 2004, and December 31, 2003, included in “other payables and accrued liabilities” in the accompanying balance sheets.

4.	CAPITAL STOCK

In March 2004, the Company entered into a separation agreement with a former executive under which the Company extended the period in which the former executive may exercise each outstanding vested stock option granted to him under the Company’s 1990 Stock Plan to the end of the term of such option. Pursuant to the terms of the restricted stock award agreements for the shares of restricted stock granted to the Company’s former executive under the Company’s 1990 Stock Plan, such shares vested in full as of the date of his termination of employment. As a result, the Company recorded non-cash stock compensation expense of approximately $2.2 million in the first quarter of 2004.

In 2003, certain senior executives were granted restricted shares under which the restricted shares would vest when the Company’s common stock price had closed at $15.00 per share or higher for 45 consecutive trading days. These restricted shares vested on July 28, 2004. The Company recorded all of the stock compensation expense related to these shares, approximately $1.1 million, in the second quarter of 2004.

The Company declared cash dividends of $0.145 and $0.13 per share for the nine months ended September 30, 2004 and 2003, respectively, and $0.05 and $0.045 per share for the three months ended September 30, 2004 and 2003, respectively.

5.	COMMITMENTS AND CONTINGENCIES

The Company had approximately $2.8 million in letters of credit outstanding at September 30, 2004. These letters of credit relate primarily to bonding requirements of various state regulatory agencies in the U.S. for oil and gas operations. The Company’s availability under its revolving credit facility is reduced by the outstanding letters of credit.

-17-

The Company has entered into certain firm gas transportation and compression agreements in Bolivia whereby the Company has committed to transport and compress certain volumes of gas at established government-regulated fees. While these fees are not fixed, they are government-regulated and therefore, the Company believes the risk of significant fluctuations is minimal. The Company entered into these arrangements to ensure its access to gas markets and currently expects to produce sufficient volumes to utilize all of the contracted transportation and compression capacity under these arrangements. The Company paid $1.7 million and $1.8 million under these agreements in the nine months ended September 30, 2004 and 2003, respectively, and paid $0.7 million and $0.6 million under these agreements in the three months ended September 30, 2004 and 2003, respectively. Based on the current fee level, these commitments total approximately $0.4 million for the remainder of 2004, $1.2 million in 2005, $1.3 million in 2006 and $0.3 million in each of the years 2007, 2008 and 2009.

The Company has future minimum long-term electric power purchase commitments in Argentina of $0.9 million for the remainder of 2004, $3.5 million in 2005, $3.5 million in 2006 and $4.9 million in 2007. The Company paid $1.9 million and $0.8 million under these agreements in the nine months and three months ended September 30, 2004, respectively. No amounts were paid under these agreements in 2003.

The Company has also entered into “deliver-or-pay” arrangements where it has committed to deliver certain volumes of gas to third parties in Bolivia and Argentina for a specified period of time. These volumes will be sold at market prices. If the required volumes are not delivered, the Company must pay for the undelivered volumes at the then-current market price. Similar to the firm transportation and compression agreements, the Company entered into these arrangements to ensure its access to gas markets and the Company currently expects to produce sufficient volumes to satisfy all of its deliver-or-pay obligations. The volumes contracted under the agreement in Bolivia are 2.8 Bcf for the remainder of 2004, 7.1 Bcf in 2005, 7.0 Bcf in 2006, 7.3 Bcf in 2007, 8.2 Bcf in 2008 and 8.3 Bcf in 2009. The volumes contracted under the agreement in Argentina are 2.5 Bcf for the remainder of 2004, 6.1 Bcf in 2005, 3.3 Bcf in 2006, 3.6 Bcf in 2007 and 4.0 Bcf in 2008. The Company made no payments under these agreements in the nine months and the three months ended September 30, 2004 and 2003.

On November 5, 2004, the Company received a letter from the Ministry of Economy of the Argentina Province of Santa Cruz requesting that royalty payments made since March 2002 be amended to eliminate the market impact of the Argentina export tax on sales to domestic refiners. The Company’s legal advisors are reviewing the letter and assessing whether a contingent liability exists.

In Canada, the Company has entered into certain firm gas gathering and processing agreements whereby it has committed to process certain volumes of gas at a monthly capital fee based on a sliding scale and to pay its proportionate share of the plant operating costs based on the Company’s share of the total volumes processed through the plant. The future volumes under these agreements total 2.3 MMcf per day in 2004 and 2.0 MMcf per day for the first six months of 2005.

6.	PRICE RISK MANAGEMENT

The Company periodically uses hedges to reduce the impact of oil and gas price fluctuations. The Company participated in hedges covering approximately 4.4 million barrels of oil and 3.1 million MMBtu of gas in the first nine months of 2004.

-18-

As of September 30, 2004, the Company had entered into oil price swap agreements for the fourth quarter of 2004 and for 2005, 2006 and 2007 covering a total of approximately 7.6 million barrels at a weighted average NYMEX reference price of $34.77 per barrel and gas price swap agreements for October 2004 and for 2005 covering approximately 4.3 million MMBtu at a weighted average NYMEX reference price of $6.15 per MMBtu. Additionally, at September 30, 2004, the Company had entered into a costless price collar arrangement for 5,000 MMBtu per day of its gas production for all of 2005. This costless price collar arrangement has a NYMEX floor reference price of $6.00 per MMBtu and a NYMEX cap reference price of $6.80 per MMBtu. At September 30, 2004, the Company had a derivative financial instrument payable of $73.9 million related to cash flow hedges in place on anticipated future oil and gas production. Approximately $1.4 million of this liability relates to the Company’s discontinued operations in Canada. The $72.5 million U.S. liability at September 30, 2004, consists of a current liability of $56.7 million and a long-term liability of $15.8 million.

Subsequent to September 30, 2004, the Company entered into three costless price collar arrangements for an additional 25,000 MMBtu per day of its gas production for all of 2005. All of these costless price collar arrangements have a NYMEX floor reference price of $6.00 per MMBtu. For 10,000 MMBtu per day, the NYMEX cap reference price is $8.02 per MMBtu; for 5,000 MMBtu per day, the NYMEX cap reference price is $8.73 per MMBtu; and for 10,000 MMBtu per day, the NYMEX cap reference price is $9.21 per MMBtu.

The Company has also entered into basis swap agreements for all of its gas production covered by the gas price swap agreements and price collar arrangements. These basis swaps establish a differential between the NYMEX reference price and the various delivery points at levels that are comparable to the historical differentials received by the Company.

In September 2004, the differential between NYMEX crude oil prices and West Coast U.S. crude oil postings widened. Although NYMEX crude oil prices increased during the month of September, West Coast crude oil postings decreased. This market fluctuation caused the Company to conclude that certain of its crude oil hedges related to its California production were no longer highly effective in achieving offsetting changes in the cash flows of the physical transactions. In accordance with SFAS 133, the Company discontinued hedge accounting for these contracts in September and recorded the $14.4 million change in the fair value of these contracts as a charge to “other non-operating expense.” The Company will continue to monitor the correlation between the changes in NYMEX crude oil prices and the changes in West Coast crude oil postings and may resume hedge accounting when such correlation indicates that the contracts will be highly effective in achieving offsetting changes in the cash flows of the physical transactions. Until such time that these contracts are redesignated as hedges, changes in the fair value of these contracts will be recognized currently as “other non-operating income or expense.” The fair value of these contracts at September 30, 2004, was a liability of $19.6 million. The Company continues to monitor oil and gas prices and may enter into additional oil and gas hedges or swaps in the future.

-19-

7.	INCOME TAXES

A reconciliation of the U.S. federal statutory income tax rate to the effective tax rate for continuing operations is as follows:


	Nine Months Ended September 30,
	2004		2003
U.S. federal statutory income tax rate	35.0	%	35.0	%
U.S. state income tax (net of federal tax benefit)	—		0.5
U.S. permanent differences	0.7		—
Foreign operations	2.3		7.1

	38.0	%	42.6	%

The impact of foreign operations is primarily the result of lower tax depreciation, depletion and amortization in Argentina due to the inability to utilize inflation accounting for tax purposes. Earnings of the Company’s foreign subsidiaries are subject to foreign income taxes. No U.S. deferred tax liability will be recognized related to the unremitted earnings of these foreign subsidiaries, as it is the Company’s intention, generally, to reinvest such earnings permanently. At December 31, 2003, income considered to be permanently reinvested in certain foreign subsidiaries totaled approximately $375 million. The Company has paid or accrued foreign income taxes of approximately $170 million related to this income which may be available as a credit against U.S. federal income taxes on such income, if distributed. It is not practicable to estimate the amount of additional tax that might be payable on this foreign income if distributed because the amount of foreign taxes eligible for credit against U.S. federal income taxes on any such distribution will be determined based on facts and circumstances at the time of any actual distribution.

On September 22, 2004, the Company entered into a definitive agreement to sell all of its interests in Canada through the sale of its subsidiary, Vintage Petroleum Canada, Inc. (“VPC”) for approximately C$350.0 million ($274.0 million) in cash, including estimated working capital and subject to certain adjustments. As part of the sale process, the Company changed its Canadian corporate structure, resulting in a capital loss for U.S. income tax reporting purposes of approximately $243.5 million. A portion of this capital loss can be carried back to prior years to offset previously reported capital gains and the Company expects to receive a current tax benefit of approximately $30.7 million from this carry back. This benefit will be recognized for financial statement purposes in the fourth quarter when the sale of VPC is closed and reflected as part of the financial gain on sale shown in discontinued operations. The balance of the U.S. capital loss of approximately $155.5 million may be carried forward for a period of up to five years and is available to offset future U.S. capital gains. Because there are no specific future capital gains foreseen by the Company at this time, a valuation allowance will be provided against this benefit for financial reporting purposes.

-20-

8.	DISCONTINUED OPERATIONS

On January 31, 2003, the Company completed the sale of its operations in Ecuador. The Company received $137.4 million in cash and recorded a gain of approximately $47.3 million ($9.5 million after income taxes).

As discussed above, on September 22, 2004, the Company entered into a definitive agreement to sell all of its interests in Canada through the sale of its subsidiary, Vintage Petroleum Canada, Inc., for approximately C$350.0 million ($274.0 million) in cash, including estimated working capital and subject to certain adjustments. The Company expects to record a significant gain on the sale for financial reporting purposes.

The Company received C$5.0 million (approximately $3.9 million) of the sales price upon signing the agreement. This amount is shown in “other payables and accrued liabilities” in the accompanying balance sheet at September 30, 2004. The Company received an additional C$5.0 million (approximately $4.0 million) of the sales price on October 7, 2004. The Company will receive the remaining portion of the sales price at closing, which is scheduled for November 30, 2004.

On September 24, 2004, the Company entered into a forward sale of C$340 million related to the proceeds the Company expects to receive at closing. The Company will receive $266.1 million and is accounting for this transaction as a cash flow hedge. As of September 30, 2004, the Company had a derivative financial instrument payable of $3.2 million related to this hedge recorded as a current liability on its balance sheet.

In accordance with the rules established by Statement of Financial Accounting Standards No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, the Company’s operations in Ecuador, along with the gain on the sale, and the Company’s operations in Canada are accounted for as discontinued operations in the accompanying consolidated financial statements.

Following is summarized financial information for the Company’s operations in Ecuador (in thousands):


	Nine Months Ended September 30, 2003
Revenues	$	3,083

Income from discontinued operations	$	1,812
Deferred income tax expense		459

Operating income from discontinued operations		1,353
Gain on sale of operations in Ecuador, net of $37,767 income tax expense		9,491

Income from discontinued operations, net of tax	$	10,844

-21-

Following is summarized financial information for the Company’s operations in Canada (in thousands):


	Three Months Ended September 30,						Nine Months Ended September 30,
	2004			2003			2004		2003
Revenues	$	24,240		$	26,454		$	74,986	$	92,177

Income (loss) from discontinued operations	$	(581	)	$	(3,362	)	$	3,216	$	(37,631	)
Provision (benefit) for income taxes		(184	)		221			130		(12,745	)

Income (loss) from discontinued operations, net of tax	$	(397	)	$	(3,583	)	$	3,086	$	(24,886	)


	September 30, 2004		December 31, 2003
Cash	$	32,960	$	22,616
Other current assets		54,187		21,274
Property, plant and equipment, net		164,637		177,683
Other assets		1,603		2,748

Assets of discontinued operations	$	253,387	$	224,321

Current liabilities	$	30,410	$	29,183
Deferred income taxes		30,692		—
Other liabilities		18,352		16,910

Liabilities of discontinued operations	$	79,454	$	46,093

9.	SEGMENT INFORMATION

The Company applies Statement of Financial Accounting Standards No. 131, Disclosures About Segments of an Enterprise and Related Information. The Company’s reportable business segments have been identified based on the differences in products or services provided. Revenues for the exploration and production segment are derived from the production and sale of oil and gas. The gas marketing segment generates revenue by earning fees through the marketing of Company-produced gas volumes and the purchase and resale of third party-produced gas volumes. The Company evaluates the performance of its operating segments based on operating income.

The Company previously reported its gathering and plant operations as a separate business segment. Due to changes in the Company’s internal organization, as of January 1, 2004, the gathering and plant operations are now considered to be a part of the Company’s U.S. exploration and production business segment. Information for 2003 has been reclassified to conform to this presentation.

-22-

Intersegment sales are priced in accordance with terms of existing contracts and current market conditions. Capital investments include expensed exploratory costs. Amounts below the “operating income” line on the statements of operations are not allocated to segments. General and administrative expense and stock compensation are included in the corporate segment, except for certain operating expenses related to oil and gas producing activities, which are allocated to each exploration and production segment.

Operations in the gas marketing segment are in the U.S. The Company operates in the oil and gas exploration and production industry in the U.S., Argentina, Bolivia, Yemen, Bulgaria and Italy. The financial information related to the Company’s discontinued operations in Canada and Ecuador has been excluded in all periods presented (see Note 8). Summarized financial information for the Company’s reportable segments for the nine month and three month periods ended September 30, 2004 and 2003, is shown in the following tables (in thousands):

-23-


	Exploration and Production
	U.S.		Argentina			Bolivia		Yemen			Other Foreign
Nine Months Ended 9/30/04
Revenues from external customers	$	240,749	$	237,171		$	11,558	$	6,075		$	—
Intersegment revenues		—		—			—		—			—
Depreciation, depletion and amortization expense		35,564		32,437			2,444		593			—
Operating income (loss)		99,566		128,092			5,545		2,584			(5,515	)
Total assets		527,817		632,359			112,662		44,416			1,748
Capital investments		85,824		100,895			—		14,693			4,553
Long-lived assets		477,525		559,694			88,981		35,945			—

	Gas Marketing		Corporate			Total
Nine Months Ended 9/30/04
Revenues from external customers	$	50,131	$	—		$	545,684
Intersegment revenues		2,001		—			2,001
Depreciation, depletion and amortization expense		—		1,649			72,687
Operating income (loss)		2,722		(39,261	)		193,733
Total assets		17,641		90,332			1,426,975
Capital investments		—		1,586			207,551
Long-lived assets		—		5,119			1,167,264

	Exploration and Production
	U.S.		Argentina			Bolivia		Yemen			Other Foreign
Nine Months Ended 9/30/03
Revenues from external customers	$	196,175	$	205,046		$	10,435	$	—		$	—
Intersegment revenues		—		—			—		—			—
Depreciation, depletion and amortization expense		29,099		32,032			2,059		—			—
Operating income (loss)		83,779		104,150			3,714		(4,425	)		(1,193	)
Total assets		467,482		531,857			120,999		22,474			361
Capital investments		56,166		37,778			1,523		10,379			1,284
Long-lived assets		437,163		481,952			92,316		21,851			179

	Gas Marketing		Corporate			Total
Nine Months Ended 9/30/03
Revenues from external customers	$	59,978	$	—		$	471,634
Intersegment revenues		824		—			824
Depreciation, depletion and amortization expense		—		2,273			65,463
Operating income (loss)		1,884		(36,570	)		151,339
Total assets		10,111		157,561			1,310,845
Capital investments		—		2,136			109,266
Long-lived assets		—		4,333			1,037,794

-24-


	Exploration and Production
	U.S.		Argentina			Bolivia		Yemen			Other Foreign
Three Months Ended 9/30/04
Revenues from external customers	$	86,245	$	90,353		$	4,831	$	4,345		$	—
Intersegment revenues		—		—			—		—			—
Depreciation, depletion and amortization expense		13,330		11,434			984		371			—
Operating income (loss)		34,254		47,728			2,651		1,827			(6,547	)
Total assets		527,817		632,359			112,662		44,416			1,748
Capital investments		33,761		58,333			—		7,554			537
Long-lived assets		477,525		559,694			88,981		35,945			—

	Gas Marketing		Corporate			Total
Three Months Ended 9/30/04
Revenues from external customers	$	17,897	$	—		$	203,671
Intersegment revenues		1,075		—			1,075
Depreciation, depletion and amortization expense		—		601			26,720
Operating income (loss)		1,039		(6,771	)		74,181
Total assets		17,641		90,332			1,426,975
Capital investments		—		537			100,722
Long-lived assets		—		5,119			1,167,264

	Exploration and Production
	U.S.		Argentina			Bolivia		Yemen			Other Foreign
Three Months Ended 9/30/03
Revenues from external customers	$	61,481	$	66,218		$	3,292	$	—		$	—
Intersegment revenues		—		—			—		—			—
Depreciation, depletion and amortization expense		8,892		11,153			629		—			—
Operating income (loss)		24,545		32,287			1,442		(1,990	)		(928	)
Total assets		467,482		531,857			120,999		22,474			361
Capital investments		21,816		18,157			104		2,089			831
Long-lived assets		437,163		481,952			92,316		21,851			179

	Gas Marketing		Corporate			Total
Three Months Ended 9/30/03
Revenues from external customers	$	15,445	$	—		$	146,436
Intersegment revenues		198		—			198
Depreciation, depletion and amortization expense		—		718			21,392
Operating income (loss)		646		(12,781	)		43,221
Total assets		10,111		157,561			1,310,845
Capital investments		—		967			43,964
Long-lived assets		—		4,333			1,037,794

-25-

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS

OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Overview

We are an independent energy company with operations primarily in the exploration and production and gas marketing segments of the oil and gas industry. We have operations or exploration activities in North America, South America, Yemen, Italy and Bulgaria. We are focused on the acquisition of oil and gas properties that contain the potential for increased value through exploitation and exploration. In addition, we are focused on continuing to build an inventory of exploration prospects in North America that may impact production in the near term as well as high-potential frontier prospects that may impact production in the longer term.

Since the beginning of 2002, we have been focused on managing our financial leverage, maintaining liquidity and positioning ourselves for long-term growth. As a result of acquisitions in Canada and Argentina in 2001, we ended 2001 with $1.0 billion of long-term debt. Since that time, we have improved our balance sheet and leverage position by reducing long-term debt by over $330 million. We funded this reduction in debt with proceeds from property sales, reducing our capital expenditures and cash provided by operating activities. Our continuing operations have $46 million of cash at September 30, 2004, primarily held by our international subsidiaries. In addition, as of September 30, 2004, we have unused availability under our revolving credit facility of $171 million (considering outstanding letters of credit of approximately $2.8 million).

To further improve our leverage position and to position ourselves for further growth, we have entered into a definitive agreement to sell all of our interests in Canada for approximately C$350.0 million ($274.0 million) in cash, including estimated working capital and subject to certain adjustments. The closing is scheduled for November 30, 2004. Upon closing, we plan to use a portion of the proceeds from this sale to reduce our outstanding debt under our revolving credit facility with a significant amount of additional cash remaining on hand. With the application of the anticipated proceeds and an expected book gain, our net debt-to-book capitalization ratio will be at a significantly lower level. The availability under our revolving credit facility, cash on hand and a strong capitalization structure gives us significant financial flexibility to fund our future growth.

Our focus for 2004 has been to return to profitability with production and reserve growth from a balance of acquisitions, exploitation and exploration. Due to strong product prices and positive results from recent capital spending, we increased our original 2004 non-acquisition oil and gas capital expenditure budget from $225 million to $250 million, which is 38 percent greater than our spending in 2003. We expect to have sufficient internally generated cash flows to fund our non-acquisition capital expenditures plus provide additional cash for debt reduction and future acquisitions. We have already reduced our expected interest costs for 2004 by advancing funds under our revolving credit facility to repay our 9 3/4% senior subordinated notes.

In September 2004, we acquired certain operated producing properties in the San Jorge basin of Argentina. We paid $30.7 million in cash, net of working capital adjustments, with cash on hand. In the event we successfully secure additional acquisitions of oil and gas properties, we will seek appropriate levels of oil and gas price risk management and equity capital in order to maintain or improve our capital structure.

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Net income increased significantly in the third quarter of 2004 and the first nine months of 2004 compared to the same periods in 2003. Operating income increased 72 percent from $43.2 million for the third quarter of 2003 to $74.2 million for the third quarter of 2004 and increased 28 percent from $151.3 million for the first nine months of 2003 to $193.7 million for the first nine months of 2004. Higher oil and gas prices, along with increases in production from continuing operations, increased total revenues by 39 percent from the third quarter of 2003 to the third quarter of 2004 and by 16 percent from the first nine months of 2003 to the first nine months of 2004. Operating costs and expenses also increased in the third quarter of 2004 and the first nine months of 2004 compared to the same periods in 2003 although not at the same pace as revenues. Operating income for the first nine months of 2004 also included a $6.0 million gain for the settlement of a certain contract claim we had against a third party. Non-operating expenses increased in the third quarter of 2004 and the first nine months of 2004 compared to the same periods in 2003 due to non-cash charges from hedging activities, partially offset by lower interest expense. Widening differentials between NYMEX crude oil prices and West Coast U.S. crude oil postings required us to discontinue hedge accounting on certain oil price swap contracts related to our California production. As a result, we recorded a $14.4 million non-cash charge in the third quarter of 2004. The decrease in interest expense for the first nine months of 2004 compared to the same period in 2003 was partially offset by higher losses on the early extinguishment of debt. Net income in the first nine months of 2004 and 2003 included income of $3.1 million and a loss of $14.0 million from discontinued operations, respectively. Also included in 2003 was a positive cumulative effect of a change in accounting principle of $7.1 million. Our cash provided by continuing operations for the first nine months of 2004 was $221.6 million, which was 42 percent higher than the same period in 2003.

Our future financial results depend on a number of factors, including, in particular, oil and gas prices, access to capital, domestic and foreign regulatory developments, and our ability to find or acquire oil and gas reserves and to control costs. Historically, commodity prices have been volatile and we expect them to remain volatile. Commodity prices are impacted by many factors that are outside of our control. Oil and gas prices are affected by changes in market demands, overall economic activity, political events, weather, inventory storage levels, basis differentials and other factors. As a result, we cannot accurately predict future oil and gas prices, and therefore, we cannot determine what effect increases or decreases will have on our capital programs, production volumes, future revenues or our ability to acquire oil and gas properties. In addition to production volumes and commodity prices, acquiring, finding and developing sufficient amounts of oil and gas reserves at economical costs are critical to our long-term success.

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Results of Operations

Our results of operations have been significantly affected by our success in acquiring oil and gas properties and our ability to maintain or increase production through our exploitation and exploration activities. Certain dispositions of producing oil and gas properties during 2003 affect the comparability of operating data for the periods presented in the tables below. Fluctuations in oil and gas prices have also significantly affected our results. The following table reflects our oil and gas production and our average oil and gas sales prices for the periods presented:


	Three Months Ended September 30,			Nine Months Ended September 30,
	2004		2003	2004		2003
Production:
Oil (MBbls) -
U.S.	1,555		1,584	4,600		4,753
Argentina ^(a)	2,578	^(d)	2,641	7,453	^(d)	7,705
Bolivia ^(b)	24		22	65		62
Yemen ^(c)	107		—	166		—
Continuing operations	4,264		4,247	12,284		12,520
Canada	214		274	664		945
Ecuador	—		—	—		114
Total	4,478		4,521	12,948		13,579
Gas (MMcf) -
U.S.	8,135		5,458	21,500		17,435
Argentina	2,306	^(d)	2,612	6,485	^(d)	7,203
Bolivia	2,466		1,438	6,014		4,491
Continuing operations	12,907		9,508	33,999		29,129
Canada	3,785		4,583	11,591		14,945
Total	16,692		14,091	45,590		44,074
MBOE from continuing operations	6,415		5,832	17,951		17,375
Total MBOE	7,260		6,870	20,546		20,925

^(a)	Production for Argentina for the three months ended September 30, 2004 and 2003, and for the nine months ended September 30, 2004 and 2003, before the impact of changes in inventories, was 2,528 MBbls, 2,571 MBbls, 7,458 MBbls and 7,626 MBbls, respectively.

^(b)	Production for Bolivia for the three months ended September 30, 2004 and 2003, and for the nine months ended September 30, 2004 and 2003, before the impact of changes in inventories, was 28 MBbls, 19 MBbls, 71 MBbls and 60 MBbls, respectively.

^(c)	Production for Yemen for the three months and nine months ended September 30, 2004, before the impact of changes in inventories, was 174 MBbls and 282 MBbls.

^(d)

Argentina production for the three months and nine months ended September 30, 2004, is estimated to have been reduced as the result of a labor strike and problems at a major oil loading facility by 162 MBbls of oil and 129 MMcf of gas, or 183 MBOE and 527 MBbls of oil and 429 MMcf of gas, or 598 MBOE, respectively.

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	Three Months Ended September 30,				Nine Months Ended September 30,
	2004		2003		2004		2003
Average Sales Price (including impact of hedges):
Oil (per Bbl) -
U.S.	$	27.52	$	25.14	$	27.53	$	25.38
Argentina		34.39		24.60		31.27		26.19
Bolivia		24.68		22.33		24.42		22.70
Yemen		40.56		—		36.49		—
Continuing operations		31.99		24.79		29.90		25.86
Canada		28.39		27.26		28.33		28.18
Ecuador		—		—		—		26.87
Total		31.82		24.94		29.82		26.03
Gas (per Mcf) -
U.S.	$	5.31	$	3.89	$	5.26	$	4.26
Argentina		0.74		0.48		0.64		0.45
Bolivia		1.72		1.95		1.66		2.01
Continuing operations		3.81		2.66		3.74		2.97
Canada		4.75		4.11		4.82		4.35
Total		4.02		3.13		4.02		3.44
Average Sales Price (excluding impact of hedges):
Oil (per Bbl) -
U.S.	$	38.85	$	27.85	$	35.34	$	28.32
Argentina		34.39		24.60		31.27		26.19
Bolivia		24.68		22.33		24.42		22.70
Yemen		40.56		—		36.49		—
Continuing operations		36.12		25.80		32.82		26.98
Canada		37.10		26.61		33.85		28.02
Ecuador		—		—		—		26.87
Total		36.17		25.85		32.88		27.05
Gas (per Mcf) -
U.S.	$	5.27	$	4.45	$	5.27	$	4.99
Argentina		0.74		0.48		0.64		0.45
Bolivia		1.72		1.95		1.66		2.01
Continuing operations		3.78		2.98		3.74		3.41
Canada		4.75		4.26		4.82		4.83
Total		4.00		3.40		4.02		3.89

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Oil Prices

Average U.S. and Canada oil prices that we receive generally fluctuate with changes in the NYMEX reference price for oil. Our oil production in Argentina is sold at West Texas Intermediate spot prices as quoted on the Platt’s Crude Oil Marketwire (approximately equal to the NYMEX reference price) less a specified differential. Our Yemen oil production is sold at Dated Brent prices as quoted on the Platt’s Crude Oil Marketwire less a specified differential. We experienced a 16 percent increase in our average oil price from continuing operations, including the impact of hedging activities (22 percent increase excluding hedging activities), during the first nine months of 2004 as compared to the same period of 2003. Our realized average oil price (before hedges) from continuing operations for the first nine months of 2004 was approximately 84 percent of the NYMEX reference price compared to 87 percent for the same period of 2003. We experienced a 29 percent increase in our average oil price from continuing operations, including the impact of hedging activities (40 percent increase excluding hedging activities), during the third quarter of 2004 as compared to the same period of 2003. Our realized average oil price (before hedges) from continuing operations for the third quarter of 2004 was approximately 82 percent of the NYMEX reference price compared to 85 percent for the same period of 2003.

It appears that the supply and demand for light sweet crude oils compared to the supply and demand for heavier, sour crude oils have caused the differentials to widen in recent months between NYMEX crude oil prices and our realized prices for our California and Argentina production. We expect that our realizations compared to NYMEX oil prices will be lower than historical levels until these market conditions improve.

In the first nine months of 2004, we exported approximately 44 percent of our Argentine oil production. Argentina oil exports are subject to an export tax. On May 11, 2004, the Argentina government increased this tax from 20 percent to 25 percent. This tax is applied on the sales value after the tax, thus, the net effect of the 20 and 25 percent rates is 16.7 and 20 percent, respectively. On August 6, 2004, the Argentine government further increased the export tax rates for oil exports. The export tax now escalates from the current 25 percent (20 percent effective rate) to a maximum rate of 45 percent (31 percent effective rate) of the realized value for exported barrels as West Texas Intermediate posted prices per barrel increase from less than $32.00 to $45.00 and above. The export tax is not deducted in the calculation of royalty payments and is limited by law to a maximum term through February 2007. We believe that this export tax has and will continue to have the effect of decreasing all future Argentine oil revenues (not only export revenues) by as much as the tax rate for the duration of the tax. The U.S. dollar equivalent value for domestic Argentine oil sales (paid in pesos) has generally moved toward parity with the U.S. dollar-denominated export values, net of the export tax. The adverse impact of this tax has been partially offset by the Argentine income tax savings related to deducting the impact of the export tax.

During the first nine months of 2004 and 2003, we participated in oil hedges covering 4.4 MMBbls and 3.5 MMBbls, respectively. The impact of these oil hedges on our average oil prices is reflected in the preceding tables.

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Gas Prices

Average U.S. gas prices we receive generally fluctuate with changes in spot market prices, which may vary significantly by region. A large portion of our Bolivian gas production is sold at average prices tied to a long-term contract under which the base price is adjusted for changes in specified fuel oil indexes. Our Argentine gas is sold under spot contracts of varying lengths which are paid in pesos. The denomination of Argentine gas sales in pesos has resulted in a decrease in sales revenue value when converted to U.S. dollars due to the devaluation of the peso and current market conditions. This value may improve over time as domestic Argentine gas drilling declines and market conditions improve. Our average gas price from continuing operations for the first nine months of 2004, including the impact of hedging activities, was 26 percent higher (10 percent higher excluding hedging activities) than the same period of 2003. Our average gas price from continuing operations for the third quarter of 2004, including the impact of hedging activities, was 43 percent higher (27 percent higher excluding hedging activities) than the same period of 2003. Our gas in Canada is generally sold at spot market prices as reflected by the AECO gas price index.

We participated in gas hedges covering approximately 3.1 million MMBtu and 15.0 million MMBtu during the first nine months of 2004, and 2003, respectively.

Future Period Hedges

The following table reflects the volume of our oil under price swap arrangements and the corresponding weighted average NYMEX reference prices by quarter:


Quarter Ending	Barrels	NYMEX Reference Price Per Barrel
December 31, 2004	1,264,500	$	30.20
March 31, 2005	1,170,000		37.39
June 30, 2005	1,183,000		36.07
September 30, 2005	1,196,000		35.13
December 31, 2005	1,196,000		34.44
March 31, 2006	360,000		36.63
June 30, 2006	364,000		36.01
September 30, 2006	368,000		35.52
December 31, 2006	368,000		35.11
March 31, 2007	126,000		31.42

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The following table reflects the volume of our gas under price swap arrangements and the corresponding weighted average NYMEX reference prices by quarter:


Quarter Ending	MMBtu	NYMEX Reference Price Per MMBtu
December 31, 2004	620,000	$	5.97
March 31, 2005	900,000		6.59
June 30, 2005	910,000		5.94
September 30, 2005	920,000		5.97
December 31, 2005	920,000		6.22

We also have costless price collar arrangements for 30,000 MMBtu per day of our U.S. gas production for all of 2005. The following table reflects the floor and cap NYMEX reference prices for these price collars:


2005 Daily Gas Production (MMBtu)	NYMEX Floor Reference Price Per MMBtu		NYMEX Cap Reference Price Per MMBtu
5,000	$	6.00	$	6.80
10,000		6.00		8.02
5,000		6.00		8.73
10,000		6.00		9.21

We also have entered into basis swap agreements for all of our gas production covered by the gas price swap agreements and price collar arrangements. These basis swaps establish a differential between the NYMEX reference price and the various delivery points at levels that are comparable to the historical differentials we have received.

The counterparties to our current hedging agreements are commercial or investment banks. We continue to monitor oil and gas prices and may enter into additional oil and gas hedges or swaps in the future.

Period to Period Comparison

The period to period comparison presented below is significantly impacted by dispositions during the periods. On January 31, 2003, we completed the sale of our operations in Ecuador. We received $137.4 million in cash, and recorded a gain of approximately $47.3 million ($9.5 million after income taxes). During September 2004, we entered into an agreement to sell all of our interests in Canada. The transaction is expected to close on November 30, 2004. In accordance with the rules established by Statement of Financial Accounting Standards No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, our operations in Ecuador, along with the gain on the sale, and our operations in Canada, are accounted for as discontinued operations in our consolidated financial statements. Accordingly, the revenues and operating expenses discussed below exclude the results related to our operations in Ecuador and Canada for all periods.

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Oil, condensate and NGL sales. Oil, condensate and NGL sales increased $43.5 million, 13 percent, to $367.3 million for the first nine months of 2004 from $323.8 million for the first nine months of 2003. A 16 percent increase in our average oil price more than offset a two percent decrease in oil production for the first nine months of 2004 compared to the same period in 2003.

Oil, condensate and NGL sales increased $31.1 million, 30 percent, to $136.4 million for the third quarter of 2004 from $105.3 million for the third quarter of 2003 as a result of a 29 percent increase in our average oil price from the third quarter of 2003 to the third quarter 2004. Oil production for the third quarter of 2004 was flat compared to the third quarter of 2003.

As a result of our successful exploration at our An Nagyah field in Yemen, oil production from our area of commercial development began making a contribution in the second quarter of 2004, averaging 1,891 barrels per day during the third quarter, before the impact of changes in inventories. Argentine oil production for the three months and nine months ended September 30, 2004, is estimated to have been reduced as a result of a labor strike and problems at a major oil loading facility by 162,000 barrels and 527,000 barrels, respectively. There were no similar disruptions in 2003.

Gas sales. Gas sales increased $40.8 million, 47 percent, to $127.3 million for the first nine months of 2004 from $86.5 million for the first nine months of 2003. The increase is the result of a 26 percent increase in our average gas price, along with a 17 percent increase in gas production for the first nine months of 2004 compared to the same period in 2003.

Gas sales increased $23.9 million, 94 percent, to $49.2 million for the third quarter of 2004 from $25.3 million for the third quarter of 2003. The increase resulted from a 36 percent increase in gas production and a 43 percent increase in our average gas price for the third quarter of 2004 compared to the same period in 2003.

Gas production in the U.S. has increased primarily as a result of exploitation successes. The increases are principally due to gas recompletion activities in south central Texas. Net aggregated production from these lower-risk projects has increased from 7,000 Mcf per day to 30,000 Mcf per day since September 2003. Bolivia gas production has also increased primarily as a result of Argentina’s increased demand for gas. Bolivia gas production averaged approximately 21,950 Mcf per day for the first nine months of 2004 and 26,800 Mcf per day for the third quarter of 2004 compared to approximately 16,450 Mcf per day for the first nine months of 2003 and 15,600 for the third quarter of 2003. These increases were slightly offset by the production decreases in Argentina related to the labor strike and major oil loading facility problems discussed above. We estimate that these problems reduced our Argentine gas production for the three months and nine months ended September 30, 2004, by 129,000 Mcf and 429,000 Mcf, respectively. There were no similar disruptions in 2003.

Gas marketing revenues and expenses. Revenues and expenses for gas marketing decreased from the first nine months of 2003 to the first nine months of 2004 primarily due to a reduction in third party volumes we market in the U.S. Revenues and expenses for gas marketing increased from the third quarter of 2003 to the third quarter of 2004 as declines in volumes were more than offset by significantly higher gas prices. As a result of higher gas prices, gas marketing margins were higher in the first nine months of 2004 and third quarter of 2004 compared to the same periods in 2003.

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Production costs. Production costs increased $14.1 million, 15 percent, to $105.4 million for the first nine months of 2004 from $91.3 million for the first nine months of 2003. On an equivalent barrel basis, production costs increased by 12 percent to $5.87 for the first nine months of 2004 from $5.26 for the first nine months of 2003. These increases are primarily due to costs incurred in the first quarter of 2004 to repair damage resulting from the October 2003 fires in California, increased workover activity, higher U.S. power costs and higher costs in Argentina as expressed in U.S. dollars resulting from the strengthening of the Argentine peso.

Production costs increased $1.0 million, three percent, to $34.3 million for the third quarter of 2004 from $33.3 million for the third quarter of 2003. These increases are primarily due to increased workover activity and higher U.S. power costs. On an equivalent barrel basis, production costs decreased by six percent to $5.35 for the third quarter of 2004 from $5.70 for the third quarter of 2003 as the increases in production more than offset the cost increases.

Transportation and storage costs. Transportation and storage costs increased $2.4 million, 46 percent, to $7.5 million for the first nine months of 2004 from $5.1 million for the first nine months of 2003. Transportation and storage costs increased $1.5 million, 88 percent, to $3.3 million for the third quarter of 2004 from $1.8 million for the third quarter of 2003. These increases are primarily the result of trucking costs associated with our new Yemen production area. We began incurring these costs in 2004 to deliver our product to a nearby processing facility. There was no equivalent charge in 2003. Our processing facility and pipeline is currently in the design and fabrication stage and completion of the 10,000 gross barrels per day facility is scheduled for the second quarter of 2005.

Production and ad valorem taxes. Production and ad valorem taxes increased $3.8 million, 30 percent, to $16.6 million for the first nine months of 2004 from $12.8 million for the first nine months of 2003 and increased $1.7 million, 43 percent, to $5.7 million for the third quarter of 2004 from $4.0 million for the third quarter of 2003. These increases are primarily the result of higher oil and gas prices and an increase in U.S. production on an equivalent barrel basis of seven percent from the first nine months of 2003 to the first nine months of 2004 and 17 percent from the third quarter of 2003 to the third quarter of 2004.

Export taxes. Export taxes in Argentina decreased $0.1 million, less than one percent, to $25.7 million for the first nine months of 2004 from $25.8 million for the first nine months of 2003. Export taxes increased $5.4 million, 72 percent, to $12.8 million for the third quarter of 2004 from $7.4 million for the third quarter of 2003. Our Argentine domestic sales volumes as a percent of our total sales volumes have increased in 2004 compared to the same period of 2003. However, higher oil prices and the increased export tax rates in 2004 offset the decreases in export volumes. The export tax rate increased from 20 percent to 25 percent in May 2004 and was further increased in August 2004. The average effective export tax rate for the third quarter of 2004 on our exported volumes was 22.3 percent.

Exploration costs. Exploration costs increased $3.6 million, 21 percent, to $21.0 million for the first nine months of 2004 from $17.4 million for the first nine months of 2003. Exploration costs for the first nine months of 2004 consisted of $4.3 million for seismic and other geological and geophysical costs, $14.3 million for unsuccessful exploratory drilling and $2.4 million for impairment of unproved leaseholds. During the first nine months of 2003, our exploration costs included $7.5 million for seismic and other geological and geophysical costs, $7.1 million for unsuccessful exploratory drilling and $2.8 million for impairment of unproved leaseholds.

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Exploration costs increased $6.3 million, 105 percent, to $12.4 million for the third quarter of 2004 from $6.1 million for the third quarter of 2003. Exploration costs for the third quarter of 2004 consisted of $1.4 million for seismic and other geological and geophysical costs, $9.9 million for unsuccessful exploratory drilling, primarily in the U.S., and $1.1 million for impairment of unproved leaseholds. During the third quarter of 2003, our exploration costs included $4.3 million for seismic and other geological and geophysical costs, $1.3 million for unsuccessful exploratory drilling and $0.5 million for impairment of unproved leaseholds.

General and administrative expenses. General and administrative expenses increased $7.0 million, 20 percent, to $41.7 million for the first nine months of 2004 from $34.7 million for the first nine months of 2003. In the first nine months of 2004, we recorded expenses related to the payment of unaccrued 2003 employee performance bonuses and severance benefits for a former executive. There were no corresponding amounts in the first nine months of 2003. We have accrued amounts for estimated 2004 employee performance bonuses in the first nine months of 2004 while none was accrued during the same period of 2003.

General and administrative expenses increased $1.0 million, eight percent, to $12.8 million for the third quarter of 2004 from $11.8 million for the third quarter of 2003 primarily due to the accrual of higher estimated employee bonuses in the third quarter of 2004 compared to the same period in 2003.

Stock compensation. Stock compensation increased $2.8 million, 65 percent, to $7.1 million in the first nine months of 2004 from $4.3 million in the first nine months of 2003. In March 2004, we entered into a separation agreement with a former executive under which we extended the period in which he may exercise his outstanding vested stock options to the end of the term of the options. Under the terms of the restricted stock award agreements with the former executive, all of the restricted shares granted to him under these agreements became fully vested as of his termination date. As a result of these events, we recorded additional non-cash stock compensation expense of approximately $1.8 million in the first nine months of 2004. In June 2004, we recorded stock compensation expense of $1.1 million related to the vesting of certain performance-based restricted stock grants. There were no comparable charges in the first nine months of 2003.

Stock compensation decreased $0.7 million, 38 percent, to $1.2 million for the third quarter of 2004 from $1.9 million for the third quarter of 2003 primarily due to lower restricted stock amortization.

Depreciation, depletion and amortization. Depreciation, depletion and amortization increased $7.2 million, 11 percent, to $72.7 million for the first nine months of 2004 from $65.5 million for the first nine months of 2003. Despite a decrease in our average oil and gas amortization rate per equivalent barrel produced from $4.02 for the first nine months of 2003 to $3.92 for the first nine months of 2004, a production increase of three percent on an equivalent barrel basis led to the increase in total depreciation, depletion and amortization.

Depreciation, depletion and amortization increased $5.3 million, 25 percent, to $26.7 million for the third quarter of 2004 from $21.4 million for the third quarter of 2003. Despite a decrease in our average oil and gas amortization rate per equivalent barrel produced from $5.69 for the third quarter of 2003 to $4.49 for the third quarter of 2004, a production increase of ten percent on an equivalent barrel basis led to the increase in total depreciation, depletion and amortization.

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Impairment of proved oil and gas properties. In the first nine months of 2004, we recorded impairment expense of $3.9 million related to one proved oil and gas property in the U.S. This impairment resulted from a revision of our estimate of that property’s proved oil and gas reserves based on its production level in early 2004. We recorded no impairments in the first nine months of 2003, the third quarter of 2004 or the third quarter of 2003.

Interest expense. Interest expense decreased $15.0 million, 28 percent, to $39.3 million for the first nine months of 2004 from $54.3 million for the first nine months of 2003 due to a 14 percent reduction in our average debt outstanding and a 14 percent decrease in our average interest rate from the first nine months of 2003 to the first nine months of 2004. Interest expense decreased $5.2 million, 29 percent, to $12.6 million for the third quarter of 2004 from $17.8 million for the third quarter of 2003 due to a 13 percent reduction in our average debt outstanding and a 16 percent decrease in our average interest rate from the third quarter of 2003 to the third quarter of 2004. During the first quarter of 2004, we advanced funds under our revolving credit facility to redeem the entire $150 million principal balance of our 9 3/4% senior subordinated notes due 2009. During the first quarter of 2003, we advanced funds under our revolving credit facility to redeem the remaining $50 million principal balance of our 9% senior subordinated notes due 2005. At September 30, 2004, our average interest rate on our then outstanding debt was 7.2 percent. The rate on our revolving credit facility based on September 30, 2004, outstanding borrowings was 3.2 percent.

Loss on early extinguishment of debt. In connection with the redemptions of our senior subordinated notes discussed above, we were required to pay call premiums on the notes and certain associated deferred financing costs and discounts related to the notes, resulting in losses on early extinguishment of debt of $9.9 million, $6.0 million after tax, in the first nine months of 2004 and $1.4 million, $0.9 million after tax, in the first nine months of 2003.

Foreign currency exchange (gain) loss. We recorded foreign currency exchange gains of $1.1 million in the first nine months of 2004 and foreign currency exchange losses of $6.7 million in the first nine months of 2003. These gains and losses are primarily related to our operations in Argentina. During the first nine months of 2004, the Argentine peso was relatively unchanged against the U.S. dollar, with an exchange rate of 2.98 pesos to one U.S. dollar at September 30, 2004, compared to a rate of 2.94 pesos to one U.S. dollar at December 31, 2003. The Argentine peso strengthened significantly against the U.S. dollar in the first nine months of 2003, with an exchange rate of 2.91 pesos to one U.S. dollar at September 30, 2003, compared to a rate of 3.38 pesos to one U.S. dollar at December 31, 2002. Foreign currency exchange gains and losses in other countries were not significant in either period. Foreign currency exchange gains were not significant in either the third quarter of 2004 or the third quarter of 2003.

Other non-operating expense. We recorded total non-cash charges of $15.4 million and $14.0 million related to our hedging activities in the nine months and three months ended September 30, 2004, respectively. These charges included $14.4 million related to certain hedges of our California production for the fourth quarter of 2004 and for 2005. In September 2004, the differential between NYMEX crude oil prices and West Coast U.S. crude oil postings widened. Although NYMEX crude oil prices increased during the month of September, West Coast crude oil postings decreased. This market fluctuation caused us to conclude that certain of our crude oil hedges related to our California production were no longer highly effective in achieving offsetting changes in the cash flows of the physical transactions. In accordance with SFAS 133, we discontinued hedge accounting for these contracts in September and recorded the $14.4 million change in the fair value of these contracts as a charge to “other non-operating expense.” Until such time that these contracts are redesignated as hedges, changes in the fair value of these contracts will be recognized currently as “other non-operating income or expense.” The fair value of these contracts at September 30, 2004, was a liability of $19.6 million. The non-cash charges related to hedging activities in the first six months of 2004 and the first nine months of 2003 were not significant.

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Cumulative effect of change in accounting principle. We implemented Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations (“SFAS 143”), effective January 1, 2003. Previously, we accrued an undiscounted estimate of future abandonment costs of wells and related facilities through our depreciation calculation. With the implementation of SFAS 143, we now record a discounted fair value of the future retirement obligation as a liability with a corresponding amount capitalized as part of the related property’s carrying amount. We amortize the discounted capitalized asset retirement cost to expense through our depreciation calculation over the estimated useful life of the asset. We accrete the liability over time with a charge to accretion expense. As a result of the implementation of SFAS 143, we recorded a cumulative effect of change in accounting principle of $7.1 million, net of taxes of $4.1 million, in the first quarter of 2003.

Cash Flows

Our primary sources of cash during the first nine months of 2004 were funds generated from operations and borrowings under our revolving credit facility. The cash was primarily used to fund capital expenditures and acquisitions of producing properties, redeem higher-rate debt and pay dividends, with the remainder increasing our cash position by $13.7 million. See below for additional discussion of our cash flows from operating activities.


	Nine Months Ended September 30,						Change
	2004			2003			Change
Cash provided (used) by (in thousands):
Operating activities - continuing operations	$	221,568		$	155,750		$	65,818
Operating activities - discontinued operations		34,646			16,406			18,240
Investing activities - continuing operations		(185,906	)		38,661			(224,567	)
Investing activities - discontinued operations		(23,785	)		8,311			(32,096	)
Financing activities		(33,407	)		(96,228	)		62,821

Cash provided by continuing operations increased 42 percent to $221.6 million in the first nine months of 2004 compared to $155.8 million in the first nine months of 2003. Increases in production from continuing operations and higher product prices for the first nine months of 2004 compared to the same period in 2003 led to the increase. Higher revenues more than offset higher production costs and general and administrative expenses. Cash used by changes in working capital decreased by 41 percent for the first nine months of 2004 compared to the first nine months of 2003. See “Results of Operations” and “Period to Period Comparison” for further discussion.

Investing activities in the first nine months of 2004 included capital spending of $161.7 million on a cash basis, or 73 percent of cash provided by operating activities. This compares to capital spending in the first nine months of 2003 of $103.3 million, or 66 percent of cash provided by operating activities. Cash used by investing activities in the first nine months of 2004 also includes $26.8 million for the purchase of a company in Argentina, net of the cash acquired. Cash provided by investing activities in the first nine months of 2003 includes $146.1 million for proceeds from the sales of our operations in Ecuador and certain properties in the U.S.

Cash used by financing activities in the first nine months of 2004 and 2003 reflects the results of our debt reduction program. In the first quarter of 2004, we redeemed the entire $150 million principal balance of our 9 3/4% senior subordinated notes due 2009 and in the first quarter of 2003 we redeemed the remaining $50 million principal balance of our 9% senior subordinated notes due 2005. Both of these redemptions were funded by borrowings under our revolving credit facility.

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Capital Expenditures

During the first nine months of 2004, our total capital expenditures were $206.0 million, excluding our discontinued operations in Canada. In the U.S., our capital expenditures totaled $85.8 million, including $1.7 million for acquisitions. Exploitation activities accounted for $61.4 million of the U.S. capital expenditures with exploration activities contributing $22.7 million. Our capital expenditures outside the U.S. totaled $120.2 million. This amount consists of an Argentine acquisition of $36.9 million (including deferred tax gross up), exploitation activities of $64.0 million in Argentina and $12.4 million in Yemen plus exploration activities of $6.9 million, primarily in Yemen and Italy.

As of September 30, 2004, we had unproved oil and gas property costs of approximately $28.6 million, excluding Canada, consisting of undeveloped leasehold costs of $15.3 million and unevaluated exploratory drilling costs of $13.3 million. Approximately $13.1 million of the total unproved costs are associated with our drilling program in Yemen. Future exploration expense and earnings may be impacted to the extent our future exploration activities are unsuccessful in discovering commercial oil and gas reserves in sufficient quantities to recover our costs.

The timing of most of our capital expenditures is discretionary with no material long-term capital expenditure commitments. Consequently, we have a significant degree of flexibility to adjust the level of such expenditures as circumstances warrant. We use internally-generated cash flows to fund capital expenditures other than significant acquisitions. We recently increased our capital expenditure budget for 2004 by 11 percent to $250 million, exclusive of acquisitions. We do not have a specific acquisition budget since the timing and size of acquisitions are difficult to forecast.

In September 2004, we acquired 100 percent of an Argentine company whose principal asset is an operated producing concession which covers approximately 54,000 acres in the north flank of the San Jorge basin of Argentina. We paid $30.7 million in cash, net of working capital and subject to adjustments, with cash on hand. We estimate that the current net production attributable to the producing Bella Vista Oeste concession is 1,900 barrels of oil and natural gas liquids per day from approximately 50 active producing wells. We believe that the properties contain significant workover, drilling and waterflood potential which we plan to pursue along with the implementation of operational efficiencies.

In Yemen, we have received approval from the government to expand our planned drilling activity. As a result of our Yemen drilling success to date, we have increased our capital spending for drilling. The added capital is being spent principally to accelerate the drilling program at our An Nagyah field to raise productive capacity of the field toward the 10,000 barrels of oil per day gross capacity of the central processing facility, which is scheduled for completion in the second quarter 2005.

We are actively pursuing additional acquisitions of oil and gas properties. In addition to internally-generated cash flow and advances under our revolving credit facility, we may seek additional sources of capital to fund any future significant acquisitions (see “Capital Resources and Liquidity”); however, no assurance can be given that sufficient funds will be available to fund our desired acquisitions.

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Capital Resources and Liquidity

Cash on hand, internally generated cash flow and the borrowing capacity under our revolving credit facility are our major sources of liquidity. We also have the ability to adjust our level of capital expenditures. We may use other sources of capital, including the issuance of additional debt securities or equity securities, to fund any major acquisitions we might secure in the future and to maintain our financial flexibility.

In the past, we have accessed the public markets to finance significant acquisitions and provide liquidity for our future activities. Since 1990, we have completed five public equity offerings, two public debt offerings and three Rule 144A private debt offerings, which have provided us with aggregate net proceeds of approximately $1.2 billion.

In February 2004, we redeemed the entire $150 million principal balance of our 9 3/4% senior subordinated notes due 2009 with cash provided by advances under our revolving credit facility. As a result, we were required to expense certain associated deferred financing costs. The $2.6 million non-cash charge and a $7.3 million cash charge for the call premium resulted in a one-time charge of approximately $9.9 million ($6.0 million net of tax).

In March 2003, we advanced funds under our revolving credit facility to redeem the $50 million remainder of our 9% senior subordinated notes due 2005. As a result, we were required to expense certain associated deferred financing costs and discounts. This $0.7 million non-cash charge and a $0.7 million cash charge for the call premium resulted in a one-time charge of approximately $1.4 million ($0.9 million net of tax).

Our revolving credit facility consists of a senior secured credit facility maturing in May 2008 with availability governed by a borrowing base determination. Our availability under the revolving credit facility is reduced by our outstanding letters of credit. The borrowing base (currently $325 million) is based on the banks’ evaluation of our oil and gas reserves. The amount available to be borrowed under the revolving credit facility is limited to the lesser of the borrowing base or the facility size, which is currently set at $300 million. The next borrowing base redetermination will be in November 2004. The exact impact of the expected sale of our Canada properties on our borrowing base is not known at this time; however, we do not expect any significant change due to the significant increase in commodity prices since the last redetermination. As of September 30, 2004, we had unused availability under our revolving credit facility of $170.6 million (considering outstanding letters of credit of approximately $2.8 million).

Our internally generated cash flows, results of operations and financing for our operations are dependent on oil and gas prices. Realized oil and gas prices for the first nine months of 2004 were 16 percent and 26 percent higher, respectively, compared to the same period in 2003. These prices have historically fluctuated widely in response to changing market forces. For the first nine months of 2004, approximately 68 percent of our production from continuing operations was oil. We believe that our cash flows and unused availability under our revolving credit facility are sufficient to fund our planned capital expenditures for the foreseeable future. To the extent oil and gas prices decline, our earnings and cash flows from operations may be adversely impacted. Prolonged periods of low oil and gas prices could cause us to not be in compliance with maintenance covenants under our revolving credit facility and could negatively affect our credit statistics and coverage ratios and thereby affect our liquidity.

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Consistent with our stated goal of maintaining financial flexibility and optimizing our portfolio of assets, we announced plans in early 2002 to reduce debt by $200 million through a combination of asset sales and cash flows in excess of planned capital expenditures. Our interest in Ecuador was sold in January 2003 for $137.4 million in cash. The closing of the sale of our interest in Ecuador, along with the sales of certain U.S. Mid-Continent gas properties and certain non-strategic oil and gas assets in Saskatchewan and West Central Alberta, Canada later in 2003 for a total of $57.9 million, allowed us to exceed our $200 million debt reduction goal. Our debt, less cash on hand, at September 30, 2004, was $630.5 million, compared to approximately $1.0 billion at December 31, 2001.

Contractual Obligations

Our contractual obligations have not changed significantly since December 31, 2003, except for the matters discussed below.

During the first quarter of 2004, we advanced funds under our revolving credit facility to redeem the entire $150 million principal balance of our 9 3/4% senior subordinated notes due 2009. During the second quarter of 2004, the maturity of our revolving credit facility was extended to May 2008.

In Argentina, the Company, and other producers in the region, have entered into certain agreements with the Province of Santa Cruz to make payments that will improve employment rates, social development and education resources. The Company estimates that its commitment under these agreements will be 0.3 million pesos ($0.1 million) for the fourth quarter of 2004, 2.3 million pesos ($0.8 million) for 2005, 2.0 million pesos ($0.7 million) for 2006 and 1.7 million pesos ($0.6 million) for 2007.

Inflation

As a result of devaluation of the Argentine peso, 2002 peso inflation was approximately 41 percent in Argentina. However, during 2003, the Argentine inflation rate slowed to 3.7 percent for the year and was 4.8 percent during the first nine months of 2004. In recent years, inflation outside of Argentina has not had a significant impact on our operations or financial condition and is not currently expected to have a significant impact on future periods.

Income Taxes

We incurred a current provision for income taxes from continuing operations of approximately $44.1 million and $39.6 million for the first nine months of 2004 and 2003, respectively. The total provision for U.S. income taxes is based on the federal corporate statutory income tax rate plus an estimated average rate for state income taxes. Earnings of our foreign subsidiaries are subject to foreign income taxes. No U.S. deferred tax liability will be recognized related to the unremitted earnings of these foreign subsidiaries, as it is our intention, generally, to reinvest such earnings permanently. At December 31, 2003, income considered to be permanently reinvested in certain foreign subsidiaries totaled approximately $375 million. We have paid or accrued foreign income taxes of approximately $170 million related to this income which may be available as a credit against U.S. federal income taxes on such income, if distributed. It is not practicable to estimate the amount of additional tax that might be payable on this foreign income if distributed because the amount of foreign taxes eligible for credit against U.S. federal income taxes on any such distribution will be determined based on facts and circumstances at the time of any actual distribution.

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A reconciliation of the U.S. federal statutory income tax rate to the effective tax rate for continuing operations is as follows:


	Nine Months Ended September 30,
	2004		2003
U.S. federal statutory income tax rate	35.0	%	35.0	%
U.S. state income tax (net of federal tax benefit)	—		0.5
U.S. permanent differences	0.7		—
Foreign operations	2.3		7.1

	38.0	%	42.6	%

The impact of foreign operations is primarily the result of lower tax depreciation, depletion and amortization in Argentina due to the inability to utilize inflation accounting for tax purposes.

On September 22, 2004, we entered into a definitive agreement to sell all of our interests in Canada through the sale of our subsidiary, Vintage Petroleum Canada, Inc. for approximately C$350.0 million ($274.0 million) in cash, including estimated working capital and subject to certain adjustments. As part of the sale process, we changed our Canadian corporate structure, resulting in a capital loss for U.S. income tax reporting purposes of approximately $243.5 million. A portion of this capital loss can be carried back to prior years to offset previously reported capital gains and we expect to receive a current tax benefit of approximately $30.7 million from this carry back. This benefit will be recognized for financial statement purposes in the fourth quarter when the sale of VPC is closed and reflected as part of the financial gain on sale shown in discontinued operations. The balance of the U.S. capital loss of approximately $155.5 million may be carried forward for a period of up to five years and is available to offset future U.S. capital gains. Because there are no specific future capital gains foreseen by us at this time, a valuation allowance will be provided against this benefit for financial reporting purposes.

Critical Accounting Policies and Estimates

Our critical accounting policies are discussed in our 2003 Annual Report on Form 10-K (the “2003 Form 10-K”), “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.” There have been no material changes in our critical accounting policies from those reported in the 2003 Form 10-K.

Foreign Operations

For information on our foreign operations, see “Item 3. Quantitative and Qualitative Disclosures About Market Risk—Foreign Currency and Operations Risk” included elsewhere in this Form 10-Q.

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Forward-Looking Statements

This Form 10-Q includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, included in this Form 10-Q which address activities, events or developments which we expect, believe or anticipate will or may occur in the future are forward-looking statements. The words “believes,” “intends,” “expects,” “anticipates,” “projects,” “estimates,” “predicts” and similar expressions are also intended to identify forward-looking statements.

These forward-looking statements include, among others, such things as:

•

amounts and nature of future capital expenditures;

•

oil and gas prices and demand;

•

operating costs;

•

estimates of proved oil and gas reserves;

•

business strategy;

•

production of oil and gas reserves;

•

expansion and growth of our business and operations; and

•

events or developments in foreign countries, including estimates of oil export levels.

These statements are based on certain assumptions and analyses we made in light of our experience and our perception of historical trends, current conditions and expected future developments as well as other factors we believe are appropriate in the circumstances. However, whether actual results and developments will conform with our expectations and predictions is subject to a number of risks and uncertainties which could cause actual results to differ materially from our expectations, including:

•

risk factors discussed in our 2003 Form 10-K, and listed from time to time in our filings with the Securities and Exchange Commission;

•

oil and gas prices;

•

exploitation and exploration successes;

•

actions taken and to be taken by the foreign governments as a result of economic conditions;

•

continued availability of capital and financing;

•

changes in foreign exchange rates and inflation rates;

•

general economic, market or business conditions;

•

acquisitions and other business opportunities (or lack thereof) that may be presented to and pursued by us;

•

changes in laws or regulations; and

•

other factors, most of which are beyond our control.

Consequently, all of the forward-looking statements made in this Form 10-Q are qualified by these cautionary statements and there can be no assurance that the actual results or developments anticipated by us will be realized or, even if substantially realized, that they will have the expected consequences to or effects on us or our business or operations. We assume no obligation to update publicly any such forward-looking statements, whether as a result of new information, future events or otherwise.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Our operations are exposed to market risks primarily as a result of changes in commodity prices, interest rates and foreign currency exchange rates. We do not use derivative financial instruments for speculative or trading purposes.

Commodity Price Risk

We produce, purchase and sell crude oil, natural gas, condensate, natural gas liquids and sulfur. As a result, our financial results can be significantly impacted as these commodity prices fluctuate widely in response to changing market forces. Relatively modest changes in either oil or gas prices significantly impact our results of operations and cash flows. However, the impact of changes in the market prices for oil and gas on our average realized prices may be reduced from time to time based on the level of our hedging activities. Based on oil production from continuing operations for the first nine months of 2004, a change in the average oil price we realize, before hedges, of $1.00 per Bbl would result in a change in net income and revenues less production and export taxes on an annual basis of approximately $9.3 million and $14.6 million, respectively. A 10 cent per Mcf change in the average gas price we realize, before hedges, would result in a change in net income and revenues less production taxes on an annual basis of approximately $2.8 million and $4.4 million, respectively, based on gas production for the first nine months of 2004.

We have previously engaged in oil and gas hedging activities and we intend to continue to consider various hedging arrangements to realize commodity prices which we consider favorable. As of September 30, 2004, we have entered into oil price swap agreements for the fourth quarter of 2004 and for 2005, 2006 and 2007 covering a total of approximately 7.6 million barrels at a weighted average NYMEX reference price of $34.77 per barrel. We have also entered into gas price swap agreements for the remainder of 2004 and for 2005 covering a total of approximately 4.3 million MMBtu at a weighted average NYMEX reference price of $6.15 per MMBtu. Additionally, we have entered into basis swap agreements for all of our gas production covered by the gas swap agreements. These basis swaps establish a differential between the NYMEX reference price and the various delivery points at levels that are comparable to the historical differentials we received. At September 30, 2004, we would have paid approximately $74.2 million to terminate our swap agreements then in place. We also have costless price collar arrangements for 11.0 million MMBtu of our U.S. gas production for all of 2005 at a floor of $6.00 per MMBtu and a weighted average ceiling price of $8.16 per MMBtu. The counterparties to our hedging agreements are commercial or investment banks.

Interest Rate Risk

Our interest rate risk exposure results primarily from short-term rates, mainly LIBOR-based, on borrowings from our commercial banks. To reduce the impact of fluctuations in interest rates, we have historically maintained a portion of our total debt portfolio in fixed-rate debt. At September 30, 2004, 81 percent of our debt was at fixed rates, down from 100 percent at fixed rates at December 31, 2003. In the past, we have not entered into financial instruments such as interest rate swaps or interest rate lock agreements. However, we may consider these instruments to manage the portfolio mix between fixed and floating-rate debt and to mitigate the impact of changes in interest rates based on our assessment of future interest rates, volatility of the yield curve and our ability to access the capital markets in a timely manner. At September 30, 2004, a change in the average interest rate of 100 basis points would have impacted our net income and cash flow by $0.8 million.

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The following table provides information about our long-term debt principal payments and weighted-average interest rates by expected maturity dates:


	2004	2005	2006	2007	2008			There-after			Total			Fair Value at 9/30/04
Long-Term Debt:
Fixed rate (in thousands)	—	—	—	—		—		$	549,948		$	549,948		$	598,375
Average interest rate	—	—	—	—		—			8.1	%		8.1	%
Variable rate (in thousands)	—	—	—	—	$	126,600			—		$	126,600		$	126,600
Average interest rate	—	—	—	—			^(a)		—			^(a	⁾

^(a)	LIBOR plus an increment based on the level of outstanding senior debt to the borrowing base, up to a maximum increment of 2.0 percent. Current increment above LIBOR at September 30, 2004, was 1.5 percent.

Foreign Currency and Operations Risk

International investments represent, and are expected to continue to represent, a significant portion of our total assets. We currently have international operations in Canada, Argentina, Bolivia, Yemen, Italy and Bulgaria, although we have entered into an agreement to sell our operations in Canada. For the first nine months of 2004, our operations in Argentina accounted for approximately 43 percent of our revenues and 44 percent of our total assets. During the first nine months of 2004, none of our other continuing operations outside the U.S. accounted for more than 10 percent of our revenues or total assets. We continue to identify and evaluate international opportunities, but we currently have no binding agreements or commitments to make any material international investment. As a result of such significant foreign operations, our financial results could be affected by factors such as changes in foreign currency exchange rates, weak economic conditions or changes in the political climate in these foreign countries.

On September 24, 2004, we entered into a forward sale of C$340 million related to the proceeds that we expect to receive at the closing of the sale of our Canadian operations. We will receive $266.1 million and we are accounting for this transaction as a cash flow hedge. Other than this hedge, we have historically not used derivatives or other financial instruments to hedge the risk associated with the movement in foreign currencies. However, we evaluate currency fluctuations and we will consider the use of derivative financial instruments or employment of other investment alternatives if we believe cash flows or investment returns so warrant.

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Our international operations may be adversely affected by political and economic instability, changes in the legal and regulatory environment and other factors. For example:

•

local political and economic developments, as well as labor unrest, could restrict or increase the cost of our foreign operations;

•

exchange controls and currency fluctuations could result in financial losses;

•

royalty and tax increases and retroactive royalty and tax claims could increase costs of our foreign operations;

•

expropriation of our property could result in loss of revenue, property and equipment;

•

civil uprisings, riots, terrorist attacks and wars could make it impractical to continue operations, adversely affect both budgets and schedules and expose us to losses;

•

import and export regulations and other foreign laws or policies could result in loss of revenues;

•

repatriation levels for export revenues could restrict the availability of cash to fund operations outside a particular foreign country; and

•

laws and policies of the U.S. affecting foreign trade, taxation and investment could restrict our ability to fund foreign operations or may make foreign operations more costly.

We do not currently maintain political risk insurance. However, we will consider obtaining such coverage in the future if we deem conditions so warrant.

Argentina. As a result of more than three years of economic instability and substantial withdrawals from the banking system, in early December 2001, the Argentine government, under President Fernando de la Rua, instituted restrictions that prohibit certain foreign money transfers without Central Bank approval and limit cash withdrawals from bank accounts to personal transactions in small amounts, with certain limited exceptions.

In late December 2001, as a result of political riots and upheaval in response to the banking restrictions, Fernando de la Rua was removed as president and his successor, Adolfo Rodriguez Saa, immediately announced default on Argentina’s $140 billion sovereign debt.

In early January 2002, congress conferred power to Eduardo Duhalde, who enacted temporary measures intended to achieve economic stability and avoid default on multilateral debts. On January 6, 2002, the Argentine government abolished its convertibility law that required an exchange rate of one peso to one U.S. dollar. The exchange rate as of September 30, 2004, was 2.98 pesos to one U.S. dollar. The devaluation of the peso has reduced our gas revenues and peso-denominated costs. Our oil revenues remain valued on a U.S. dollar basis.

Monetary assets and liabilities denominated in pesos at September 30, 2004, were as follows (in thousands):


	Peso Balance		U.S. Dollar Equivalent
Current assets	7,876		$	2,639
Current liabilities	(122,975	)		(41,212	)
Non-current liabilities	(73,664	)		(24,686	)

Net monetary liabilities	(188,763	)	$	(63,259	)

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On February 13, 2002, the Argentine government announced a 20 percent tax on oil exports, effective March 1, 2002. On May 11, 2004, the Argentine government increased the tax to 25 percent. The tax is limited by law to a maximum term through February 2007. The tax is applied on the sales value after the tax, thus the net effect of the 20 and 25 percent rates is 16.7 and 20 percent, respectively. On August 6, 2004, the Argentine government further increased the export tax rates for oil exports. The export tax now escalates from the current 25 percent (20 percent effective rate) to a maximum rate of 45 percent (31 percent effective rate) of the realized value for exported barrels as West Texas Intermediate posted prices per barrel increase from less than $32.00 to $45.00 and above.

During 2003, we exported approximately 60 percent of our Argentine oil production and in the first nine months of 2004, we exported approximately 44 percent of our Argentine oil production. We believe that the export tax has and will continue to have the effect of decreasing all future Argentine oil revenues (not only export revenues) by as much as the tax rate for the duration of the tax. The U.S. dollar equivalent value for domestic Argentine oil sales (now paid in pesos) has generally moved toward parity with the U.S. dollar-denominated export values, net of the export tax. The adverse impact of this tax has been partially offset by the Argentine income tax savings related to deducting the impact of the export tax. The export tax is not deducted in the calculation of royalty payments. We are required by law to repatriate to Argentina 30 percent of the export sales proceeds received in the U.S. This requirement places no significant limitations on us based upon our current cash flow assumptions.

On November 5, 2004, we received a letter from the Ministry of Economy of the Argentina Province of Santa Cruz requesting that royalty payments made since March 2002 be amended to eliminate the market impact of the Argentina export tax on sales to domestic refiners. Our legal advisors are reviewing the letter and assessing whether a contingent liability exists.

After a year of negotiations, on January 24, 2003, the International Monetary Fund (the “IMF”) executed a transitional $6.8 billion, eight-month stand-by credit arrangement to provide financial stability through the presidential elections. After a successful transition of government, and as a result of restoring a measure of economic stability and growth during 2002, in September 2003, the IMF approved a $13.5 billion stand-by credit arrangement, to be disbursed in stages over a three-year period, to succeed the transitional arrangement that expired on August 31, 2003. The economic program to which the Argentine government and the IMF agreed is based on a fiscal framework to meet growth, employment, and social objectives, while providing a basis for normalizing relations with creditors and ensuring debt sustainability, a strategy to assure strengthening of the banking system and facilitating an increase in bank lending, and further institutional and tax reforms to facilitate corporate debt restructuring and fundamentally improving the investment climate. On January 28, 2004, the IMF completed and approved its first review of Argentina’s performance under the three-year program. On March 22, 2004, the second review and disbursement of the next $3.1 billion tranche was approved. A third review is pending and is expected to be completed during the fourth quarter of 2004. Also during the fourth quarter of 2004, the Argentine government is expected to announce a debt swap offer to external creditors.

On January 2, 2003, at the Argentine government’s request, crude oil producers and refiners agreed to limit amounts payable for domestic sales occurring during the first quarter of 2003 to a maximum $28.50 per Bbl. The producers and refiners further agreed that the difference between the actual price and the maximum price would be payable once actual prices fell below the maximum. The debt payable under the agreement accrued interest at eight percent. The total debt will be collected by invoicing future deliveries at $28.50 per Bbl after actual prices fall below the maximum price. Additionally, the agreement allowed for renegotiation if the West Texas Intermediate reference price exceeded $35.00 per Bbl for ten consecutive days, which occurred on February 24, 2003.

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On February 25, 2003, the agreement between the producers and the refiners was modified to limit the amount payable from refiners to producers for deliveries occurring between February 26, 2003, and March 31, 2003. While the $28.50 per Bbl payable maximum was maintained, under the modified terms, refiners have no obligation to pay producers for sales values that exceed $36.00 per Bbl. Furthermore, interest for debts established during this period was reduced to seven percent. This agreement was extended under these terms several times during 2003 and finally through February 29, 2004. On March 19, 2004, the agreement was further extended to April 30, 2004, and the parties agreed to reduce interest rates for all outstanding debts under the agreement to LIBOR for March and April 2004, and to the higher of LIBOR plus two percent or seven percent thereafter. The agreement was not extended past April 2004.

We sold approximately 1.4 MMBbls of our net Argentine oil production (approximately 14 percent) under this agreement during 2003. We sold approximately 0.6 MBbls of additional net oil production under the agreement during 2004. We have not recorded revenue nor have we recorded an account receivable for any amounts above the $28.50 per Bbl maximum which have not been received. Repayments collected from refiners will be recorded as revenues when received.

Bolivia. Since replacing former President Gonzalo Sanchez de Lozada, who was forced to resign during October 2003, current President Carlos Mesa has been forced on several occasions to make changes to his cabinet team due to continued political pressure from rival political parties and associated social unrest. After a transportation strike and demonstrations by university students and government pensioners that were held in April 2004, labor unions began threatening to escalate unrest by announcing general strikes during May 2004. On July 18, 2004, voters approved President Mesa’s public referendum on several proposed changes in Bolivia’s Hydrocarbon Law, including the export of Bolivian gas. As a result of the referendum, on July 30, 2004, President Mesa presented his proposed Hydrocarbons Law reform bill to the Bolivian congress for consideration. Members of congress and rival political parties have proposed changes to President Mesa’s reform bill. When congressional debate concludes, we expect the Hydrocarbons Law to be reformed and expect the reform to allow increased state control over hydrocarbons commercialization and to enact a new taxation regime.

In March 2004, the Bolivian government enacted a new tax on all banking transactions, except for payments made to the Bolivian government. The tax is effective for two years beginning July 1, 2004, and will be 0.3 percent for the first year and 0.25 percent the second year. We do not expect this tax to have a significant impact on future periods.

In 1987, the Boliviano replaced the peso and became Bolivia’s legal currency. The exchange rate is set daily by the government’s exchange house, “The Bolsin,” which is under the supervision of the Bolivian Central Bank. Foreign exchange transactions are not subject to any controls. The exchange rate at September 30, 2004, was 8.00 Bolivianos to one U.S. dollar. Since our gas revenues are received in U.S. dollars, we believe that any currency risk associated with our Bolivian operations would not have a material impact on our financial position or results of operations.

In response to protests concerning high oil prices, during August 2004 the Bolivian government issued Decree 27691, which limited the amounts that condensate producers could invoice Bolivian refiners to a maximum price of $27.11 per barrel. The decree also established a floor price of $24.53 per barrel.

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Bolivian gas markets have historically been limited to exports to Brazil via the Bolivia-to-Brazil gas pipeline and to those internal gas sales necessary to meet Bolivian industrial and consumer demand. We are working to increase sales in both of these areas and we currently have capacity to deliver gas volumes in excess of our contracted volumes. The current daily productive capacity of our properties in Bolivia is approximately 46 MMcf of gas, gross and 29 MMcf of gas, net. During the past several years, Bolivian gas reserve growth has exceeded the demand growth in Bolivia’s existing markets. Therefore, we believe substantial competition for gas markets will continue at least until new market areas are established. On April 21, 2004, the Argentine and Bolivian governments agreed to a gas supply arrangement for 141 MMcf per day of gas to Argentina for a six-month period beginning in May 2004, and in July 2004, the government signed a letter of intent to increase those exports by 88.3 MMcf per day. As a result, our Bolivian sales volumes have increased in the third quarter of 2004. However, it is unclear if these increased sales volumes will continue in future periods. On October 14, the Argentine and Bolivian governments signed a letter of intent for Bolivia to export up to 706.3 MMcf per day, which is estimated to commence during 2006. This additional quantity is subject to the successful conclusion of the Hydrocarbon Law reform. With the June 2004 approval from the Bolivian public in the referendum on the matter of gas exports, we believe that new projects, such as exports to Mexico and the U.S., as well as additional exports to Argentina, will become feasible in the future.

Yemen. Yemen has been classified as a low-income developing country by the World Bank. Trade and other external economic links have been limited, with the exception of the oil sector, which accounts for more than 25 percent of Yemen’s gross domestic product. The production sharing agreements under which private investors operate are clear and unambiguous, resulting in most of the country’s foreign investment being concentrated in the oil sector. The government has relaxed the broader regulatory environment to encourage additional foreign investments. However, obstacles such as an insufficient infrastructure continue to exist. Necessary economic reforms began during 1995 and were supported by both the IMF and the World Bank. The reforms were targeted to enable a more market-based and private sector driven economy and more integration into world markets, all within the context of broad financial and macro-economic stability. These reforms continue to influence Yemen’s economic policies today.

Yemen has taken significant steps to stabilize its political environment since the end of its civil war in 1994. The government is dominated by northern Yemen, located in the capital city of Sana’a and headed by President Ali Abdullah Saleh, who is a member of the General People’s Congress. The General People’s Congress has held power since the mid-1990’s and regime change is considered to be unlikely. Civil society is relatively weak and tribal structures remain powerful. Concerns about terrorism, kidnappings and extortion are ongoing security risks. Further, concerns about continued implementations of economic reform measures as well as increased government control are ongoing business risks. We have evaluated the risk of operating in Yemen and we believe that the current risks are manageable.

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ITEM 4. CONTROLS AND PROCEDURES

In connection with the preparation of our financial reports for the three months and nine months ended September 30, 2004, we made an error in the accounting for certain derivative financial instruments. Certain of our open crude oil hedge agreements had lost effectiveness and we failed to stop using hedge accounting for those contracts effective September 1, 2004. Our internal review of these calculations did not detect this error prior to our initial earnings press release on November 3, 2004. This error was noted by our Independent Registered Public Accounting Firm in the performance of its review of our quarterly report after our initial earnings release. As a result, all required adjustments to correct this error have been made to the financial statements included in this Form 10-Q and we publicly corrected our previous earnings disclosure on November 9, 2004. The adjustment required was a material adjustment to our financial statements. The failure of our internal review to detect this error represents a material weakness in our internal controls. We believe that the identified material weakness has now been remediated by a change in our hedge computation and analysis schedules and the implementation of improved review procedures, which will be performed prior to any public release of financial information in the future. However, we and our Independent Registered Public Accounting Firm are required to perform tests of the remediation and there may not be sufficient time prior to our year end for the performance of sufficient testing. As a result, we and our Independent Registered Public Accounting Firm may not be able to conclude that our internal controls are effective as of December 31, 2004, in the reports required to be included in our Annual Report for the year ending December 31, 2004, under Section 404 of the Sarbanes-Oxley Act.

We carried out an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) of the Securities Exchange Act of 1934, as amended) as of September 30, 2004. Based upon that evaluation, except for the material weakness identified above for which the proper adjustments have been reflected in the accompanying financial statements, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures are effective to ensure that information required to be disclosed by us in our periodic filings under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms. Other than for the change in controls discussed above to remediate the identified material weakness in our internal controls, during the period covered by this Form 10-Q, there were no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Our management, including the Chief Executive Officer and Chief Financial Officer, does not expect that our disclosure controls and procedures or our internal controls will prevent all error and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. The inherent limitations in all control systems include the realities that judgments in decision making can be faulty and that breakdowns can occur because of simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the control. Because of the inherent limitations in a cost effective control system, misstatements due to error or fraud may occur and not be detected.

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PART II

OTHER INFORMATION

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Item 1.

Legal Proceedings

For information regarding legal proceedings, see our Form 10-K for the year ended December 31, 2003.

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds

The following table provides information about purchases by us during the quarter ended September 30, 2004, of equity securities that are registered by us pursuant to Section 12 of the Securities Exchange Act of 1934, as amended.

ISSUER PURCHASES OF EQUITY SECURITIES


Period	(a) Total Number of Shares Purchased⁽¹⁾	(b) Average Price Paid per Share⁽²⁾		(c) Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	(d) Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plans or Programs
July 1, 2004 - July 31, 2004	63,059	$	17.02	—	—
August 1, 2004 - August 31, 2004	—		—	—	—
September 1, 2004 - September 30, 2004	—		—	—	—

Total	63,059	$	17.02	—	—

⁽¹⁾	In connection with the maturity of certain indebtedness, an officer transferred 63,059 shares of common stock owned by him securing this indebtedness to us in full satisfaction of this indebtedness.

⁽²⁾	The price paid per common share represents the average of the high and low prices per share of our common stock, as reported in the New York Stock Exchange composite transactions, on the day that the stock was transferred to us.

Item 3.

Defaults Upon Senior Securities

Not applicable

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Item 4.

Submission of Matters to a Vote of Security Holders

Not applicable

Item 5.

Other Information

Not applicable

Item 6.

Exhibits

The following documents are included as exhibits to this Form 10-Q. Those exhibits below incorporated by reference herein are indicated as such by the information supplied in the parenthetical thereafter. If no parenthetical appears after an exhibit, such exhibit is filed or furnished herewith.



2.1		Stock Purchase Agreement dated September 22, 2004, among Midnight Oil & Gas Ltd. as Purchaser and Vintage Petroleum Canada Investments ULC, Vintage Canada Oil & Gas ULC, and Vintage Petroleum South America Holdings, Inc. as Sellers.

2.2		Stock Purchase Amending and Assignment Agreement dated October 20, 2004, among Midnight Oil & Gas Ltd. as Assignor, Vintage Petroleum Canada Investments ULC, Vintage Canada Oil & Gas ULC, and Vintage Petroleum South American Holdings, Inc. as Sellers and Daylight Acquisition Corp. as Assignee.

31.1		Certification of Chief Executive Officer pursuant to Rule 13a-14(a) and Section 302 of the Sarbanes-Oxley Act of 2002.

31.2		Certification of Chief Financial Officer pursuant to Rule 13a-14(a) and Section 302 of the Sarbanes-Oxley Act of 2002.

32.1		Certification of Chief Executive Officer pursuant to Rule 13a-14(b) and Section 906 of the Sarbanes-Oxley Act of 2002.

32.2		Certification of Chief Financial Officer pursuant to Rule 13a-14(b) and Section 906 of the Sarbanes-Oxley Act of 2002.

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Signatures

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


				VINTAGE PETROLEUM, INC.
				(Registrant)

DATE: November 9, 2004

				/s/ Michael F. Meimerstorf
				Michael F. Meimerstorf
				Vice President and Controller
				(Principal Accounting Officer)

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Exhibit Index


Exhibit Number		Description

2.1		Stock Purchase Agreement dated September 22, 2004, among Midnight Oil & Gas Ltd. as Purchaser and Vintage Petroleum Canada Investments ULC, Vintage Canada Oil & Gas ULC, and Vintage Petroleum South America Holdings, Inc. as Sellers.

2.2		Stock Purchase Amending and Assignment Agreement dated October 20, 2004, among Midnight Oil & Gas Ltd. as Assignor, Vintage Petroleum Canada Investments ULC, Vintage Canada Oil & Gas ULC, and Vintage Petroleum South American Holdings, Inc. as Sellers and Daylight Acquisition Corp. as Assignee.

31.1		Certification of Chief Executive Officer pursuant to Rule 13a-14(a) and Section 302 of the Sarbanes-Oxley Act of 2002.

31.2		Certification of Chief Financial Officer pursuant to Rule 13a-14(a) and Section 302 of the Sarbanes-Oxley Act of 2002.

32.1		Certification of Chief Executive Officer pursuant to Rule 13a-14(b) and Section 906 of the Sarbanes-Oxley Act of 2002.

32.2		Certification of Chief Financial Officer pursuant to Rule 13a-14(b) and Section 906 of the Sarbanes-Oxley Act of 2002.