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 March 31, 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 April 30, 2004
Common Stock, $0.005 Par Value		64,679,458

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VINTAGE PETROLEUM, INC.

FORM 10-Q

THREE MONTHS ENDED MARCH 31, 2004

TABLE OF CONTENTS


		Page
PART I.	FINANCIAL INFORMATION

Item 1.	Financial Statements

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

	Consolidated Statements of Operations for the Three Months Ended March 31, 2004 and 2003	6

	Consolidated Statement of Changes in Stockholders’ Equity and Comprehensive Income for the Three Months Ended March 31, 2004	8

	Consolidated Statements of Cash Flows for the Three Months Ended March 31, 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	21

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	34

Item 4.	Controls and Procedures	39

PART II.	OTHER INFORMATION

Item 1.	Legal Proceedings	41

Item 2.	Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Securities	41

Item 3.	Defaults Upon Senior Securities	41

Item 4.	Submission of Matters to a Vote of Security Holders	41

Item 5.	Other Information	42

Item 6.	Exhibits and Reports on Form 8-K	42

	Signatures	43

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PART I

FINANCIAL INFORMATION

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ITEM 1. FINANCIAL STATEMENTS

VINTAGE PETROLEUM, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In thousands, except shares

and per share amounts)

(Unaudited)

ASSETS


	March 31, 2004		December 31, 2003
CURRENT ASSETS:
Cash and cash equivalents	$	67,887	$	54,880
Accounts receivable-
Oil and gas sales		91,978		89,674
Joint operations		9,497		9,359
Prepaids and other current assets		20,883		14,702

Total current assets		190,245		168,615

PROPERTY, PLANT AND EQUIPMENT, at cost:
Oil and gas properties, successful efforts method		2,758,478		2,717,193
Oil and gas gathering systems and plants		23,461		23,344
Other		29,586		29,072

		2,811,525		2,769,609
Less accumulated depreciation, depletion and amortization		1,564,035		1,535,715

Total property, plant and equipment, net		1,247,490		1,233,894

OTHER ASSETS, net		43,462		44,329

TOTAL ASSETS	$	1,481,197	$	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


	March 31, 2004		December 31, 2003
CURRENT LIABILITIES:
Revenue payable	$	31,178	$	26,654
Accounts payable - trade		53,818		55,601
Current income taxes payable		28,734		19,933
Derivative financial instruments payable		23,386		7,876
Other payables and accrued liabilities		81,563		70,028

Total current liabilities		218,679		180,092

LONG-TERM DEBT		687,844		699,943

DEFERRED INCOME TAXES		49,659		54,302

LONG-TERM LIABILITY FOR ASSET RETIREMENT OBLIGATIONS		91,298		89,076

OTHER LONG-TERM LIABILITIES		1,150		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, 65,007,064 and 64,720,975 shares issued and 64,558,458 and 64,281,199 outstanding, respectively		325		324
Capital in excess of par value		341,831		337,080
Retained earnings		39,071		22,844
Accumulated other comprehensive income		58,177		70,482

		439,404		430,730
Less treasury stock, at cost, 448,606 and 439,776 shares		3,167		3,117
Less unamortized cost of restricted stock awards		3,670		5,127

Total stockholders’ equity		432,567		422,486

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	1,481,197	$	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 March 31,
	2004			2003
REVENUES:
Oil, condensate and NGL sales	$	119,964		$	126,215
Gas sales		53,485			59,443
Sulfur sales		558			506
Gas marketing		22,256			32,920

Total revenues		196,263			219,084

COSTS AND EXPENSES:
Production costs		45,723			37,284
Transportation and storage costs		1,949			1,971
Production and ad valorem taxes		5,696			4,733
Export taxes		6,206			10,222
Exploration costs		4,360			14,078
Gas marketing		21,555			32,037
General and administrative		16,904			13,454
Stock compensation		3,762			952
Depreciation, depletion and amortization		32,255			37,294
Impairment of proved oil and gas properties		3,915			—
Accretion		1,969			1,747
Other operating (income) expense		(4,896	)		1,176

Total costs and expenses		139,398			154,948

OPERATING INCOME		56,865			64,136

OTHER (INCOME) EXPENSE:
Interest expense		14,021			18,541
Loss on early extinguishment of debt		9,903			1,426
(Gain) loss on disposition of assets		(59	)		650
Foreign currency exchange loss		1,122			3,637
Other non-operating (income) expense		(627	)		221

Net other expense		24,360			24,475

Income from continuing operations before income taxes and cumulative effect of change in accounting principle		32,505			39,661

INCOME TAX PROVISION:
Current		12,648			14,463
Deferred		722			2,480

Total income tax provision		13,370			16,943

Income from continuing operations before cumulative effect of change in accounting principle		19,135			22,718
INCOME FROM DISCONTINUED OPERATIONS, net of income tax provision of $38,226		—			10,844

Income before cumulative effect of change in accounting principle		19,135			33,562
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE, net of income tax provision of $4,104		—			7,119

NET INCOME	$	19,135		$	40,681

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 March 31,
	2004		2003
BASIC INCOME PER SHARE:
Income from continuing operations before cumulative effect of change in accounting principle	$	0.30	$	0.36
Income from discontinued operations		—		0.17

Income before cumulative effect of change in accounting principle		0.30		0.53
Cumulative effect of change in accounting principle		—		0.11

Net income	$	0.30	$	0.64

DILUTED INCOME PER SHARE:
Income from continuing operations before cumulative effect of change in accounting principle	$	0.29	$	0.35
Income from discontinued operations		—		0.17

Income before cumulative effect of change in accounting principle		0.29		0.52
Cumulative effect of change in accounting principle		—		0.11

Net income	$	0.29	$	0.63

Weighted average common shares outstanding:
Basic		64,332		63,590

Diluted		64,980		64,811

See notes to unaudited consolidated financial statements.

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VINTAGE PETROLEUM, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY

AND COMPREHENSIVE INCOME

FOR THE THREE MONTHS ENDED MARCH 31, 2004

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

(Unaudited)


	Common Stock			Treasury Stock			Capital In Excess of Par Value			Un - amortized Restricted Stock Awards			Retained Earnings			Accumulated Other Comprehensive Income			Total
	Shares	Amount		Treasury Stock			Capital In Excess of Par Value			Un - amortized 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	—		—		—			—			—			19,135			—			19,135
Foreign currency translation adjustment	—		—		—			—			—			—			(1,978	)		(1,978	)
Change in value of derivatives, net of tax	—		—		—			—			—			—			(10,327	)		(10,327	)

Total comprehensive income																				6,830
Stock options granted	—		—		—			354			—			—			—			354
Exercise of stock options and resulting tax effects	266		1		—			2,445			—			—			—			2,446
Issuance of restricted stock	18		—		—			250			(250	)		—			—			—
Amortization of restricted stock awards	—		—		—			1,729			1,738			—			—			3,467
Forfeitures of restricted stock (4,830 shares)	—		—		—			(27	)		(31	)		—			—			(58	)
Vesting of restricted stock rights	2		—		—			—			—			—			—			—
Purchase of treasury stock (4,000 shares)	—		—		(50	)		—			—			—			—			(50	)
Cash dividends declared ($0.045 per share)	—		—		—			—			—			(2,908	)		—			(2,908	)

BALANCE AT MARCH 31, 2004	65,007	$	325	$	(3,167	)	$	341,831		$	(3,670	)	$	39,071		$	58,177		$	432,567

See notes to unaudited consolidated financial statements.

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VINTAGE PETROLEUM, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)


	Three Months Ended March 31,
	2004			2003
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	19,135		$	40,681
Adjustments to reconcile net income to cash provided by operating activities -
Income from discontinued operations, net of tax		—			(10,844	)
Cumulative effect of change in accounting principle, net of tax		—			(7,119	)
Depreciation, depletion and amortization		32,255			37,294
Impairment of proved oil and gas properties		3,915			—
Accretion		1,969			1,747
Exploration costs		2,569			11,818
Provision for deferred income taxes		722			2,480
Foreign currency exchange loss		1,122			3,637
(Gain) loss on dispositions of assets		(59	)		650
Loss on early extinguishment of debt		9,903			1,426
Stock compensation		3,762			936
Other non-cash items included in net income		(91	)		59
Increase in receivables		(3,036	)		(11,322	)
Increase in payables and accrued liabilities		18,310			8,337
Other working capital changes		(6,026	)		3,113

Cash provided by continuing operations		84,450			82,893
Cash used by discontinued operations		—			(2,045	)

Cash provided by operating activities		84,450			80,848

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures -
Oil and gas properties		(52,116	)		(45,392	)
Gathering systems and other		(674	)		(981	)
Proceeds from sale of oil and gas properties		74			29,460
Proceeds from sale of company, net of cash sold		—			116,107
Other		(1,587	)		(1,454	)

Cash provided (used) by investing activities - continuing operations		(54,303	)		97,740
Cash provided by investing activities - discontinued operations		—			10,309

Cash provided (used) by investing activities		(54,303	)		108,049

CASH FLOWS FROM FINANCING ACTIVITIES:
Issuance of common stock		2,446			131
Purchase of treasury stock		(50	)		—
Redemption of 9 3/4% Senior Subordinated Notes due 2009		(157,313	)		—
Redemption of 9% Senior Subordinated Notes due 2005		—			(50,750	)
Advances on revolving credit facility and other borrowings		201,900			93,800
Payments on revolving credit facility and other borrowings		(64,000	)		(128,762	)
Dividends paid		(2,893	)		(2,534	)
Other		3,385			—

Cash used by financing activities		(16,525	)		(88,115	)

EFFECT OF EXCHANGE RATE CHANGES ON CASH		(615	)		921

NET INCREASE IN CASH AND CASH EQUIVALENTS		13,007			101,703
CASH AND CASH EQUIVALENTS, beginning of period		54,880			9,259

CASH AND CASH EQUIVALENTS, end of period	$	67,887		$	110,962

See notes to unaudited consolidated financial statements.

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VINTAGE PETROLEUM, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

March 31, 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. 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 United States (“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. Capitalized development seismic costs for the three months ended March 31, 2004 and 2003, were $3.8 million and $1.2 million, respectively. The Company recognizes gains or losses on the sale of properties on a field basis.

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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 $1.3 million and $2.1 million for the three months ended March 31, 2004 and 2003, respectively. 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.

As of March 31, 2004, the Company had unproved oil and gas property costs of approximately $57.0 million, consisting of undeveloped leasehold costs of $38.6 million, including $28.3 million in Canada, and unevaluated exploratory drilling costs of $18.4 million. Approximately $11.9 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 (“FASB”) 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. The new standard 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 December 31, 2003 and March 31, 2004, there were no assets legally restricted for purposes of settling asset retirement obligations. Of the liability for asset retirement obligations balance at March 31, 2004, approximately $6.6 million is classified as current and is included in “other payables and accrued liabilities” in the accompanying balance sheet.

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The Company adopted SFAS 143 effective January 1, 2003, and recorded an increase in property, plant and equipment of approximately $50.3 million, a decrease in accumulated depreciation, depletion and amortization of approximately $43.9 million, an increase in current asset retirement liabilities of approximately $4.5 million, an increase in long-term asset retirement liabilities of approximately $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 approximately $7.1 million.

The Company recorded the following activity related to the asset retirement liability for the three months ended March 31, 2004 (in thousands):


Liability for asset retirement obligations as of January 1, 2004	$	94,886
New obligations for wells drilled		112
New obligations for interests acquired		1,535
Costs incurred		(238	)
Accretion expense		1,969
Changes in foreign currency exchange rates		(201	)
Revisions in estimated cash flows		(130	)

Liability for asset retirement obligations as of March 31, 2004	$	97,933

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 United States. The Company recorded no impairment provisions related to its proved oil and gas properties during the first quarter of 2003.

Other Payables and Accrued Liabilities

As of March 31, 2004, “Other payables and accrued liabilities” included $14.3 million of accrued production costs and $12.3 million of accrued oil and gas capital expenditures.

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.

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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.

Statements of Cash Flows

During the three months ended March 31, 2004 and 2003, the Company made cash payments for interest totaling approximately $2.4 million, and $5.2 million, respectively. The Company had no cash payments for U.S. income taxes in the first three months of 2004. Cash payments for U.S. income taxes of $5.4 million were made during the first three months of 2003. The Company made cash payments of $9.0 million and $3.7 million, primarily in Argentina, during the first three months of 2004 and 2003, respectively, for foreign income taxes.

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 the first three months of 2004 and 2003 was computed assuming the exercise of all dilutive options, as determined by applying the treasury stock method. For the three months ended March 31, 2004 and 2003, the Company had outstanding stock options for 723,900 and 1,125,400 additional shares of the Company’s common stock, respectively, with an average exercise price of $15.82 and $14.93, respectively, which were 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.

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 $0.8 million and $1.2 million for the first quarter of 2004 and 2003, respectively.

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.

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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 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 March 31,
	2004		2003
Stock compensation expense - as reported	$	3,762	$	936
Stock compensation expense - pro forma		3,801		1,589
Net income - as reported		19,135		40,681
Net income - pro forma		19,111		40,232
Income per share - as reported:
Basic		0.30		0.64
Diluted		0.29		0.63
Income per share - pro forma:
Basic		0.30		0.63
Diluted		0.29		0.62

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 March 31,
	2004			2003
Net income	$	19,135		$	40,681
Foreign currency translation adjustments		(1,978	)		33,384
Changes in value of derivatives, net of tax		(10,327	)		(4,015	)

Comprehensive income	$	6,830		$	70,050

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).

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


	Three Months Ended March 31,
	2004			2003
Unrealized loss during the period	$	(16,902	)	$	(13,099	)
Reclassification adjustment for losses included in net income		362			6,295

		(16,540	)		(6,804	)
Income tax benefit		(6,213	)		(2,789	)

Changes in value of derivatives, net of tax	$	(10,327	)	$	(4,015	)

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


	March 31, 2004			December 31, 2003
Foreign currency translation adjustments	$	70,572		$	72,551
Changes in value of derivatives, net of tax		(12,395	)		(2,069	)

	$	58,177		$	70,482

3.	LONG-TERM DEBT

Long-term debt at March 31, 2004, and December 31, 2003, consisted of the following:


(In thousands)	March 31, 2004		December 31, 2003
Revolving credit facility	$	137,900	$	—
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		199,944		199,943

	$	687,844	$	699,943

During February 2004, the Company advanced funds under the 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).

The Company had $18.7 million and $7.4 million of accrued interest payable related to its long-term debt at March 31, 2004, and December 31, 2003, respectively, included in “other payables and accrued liabilities” in the accompanying balance sheets.

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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.

The Company declared cash dividends of $0.045 and $0.04 per share for the three months ended March 31, 2004 and 2003, respectively.

5.	COMMITMENTS AND CONTINGENCIES

The Company had approximately $0.9 million in letters of credit outstanding at March 31, 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.

The Company has entered into certain firm gas transportation and compression agreements in Canada and 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 $1.1 million and $1.3 million under these agreements in the three months ended March 31, 2004 and 2003, respectively. Based on the current fee level, these commitments total approximately $2.0 million for the remainder of 2004, $1.8 million in 2005, $1.6 million in 2006, $0.4 million in 2007 and $0.3 million in each of the years 2008 and 2009.

The Company has future minimum long-term electric power purchase commitments in Argentina of $2.7 million in 2004, $3.5 million in 2005, $3.5 million in 2006 and $4.9 million in 2007. The Company paid $0.4 million under these agreements in the first three months of 2004. No amounts were paid under these agreements in 2003.

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 Company paid $0.1 million under these agreements in each of the first quarters of 2004 and 2003. 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.

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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 8.2 Bcf for the remainder of 2004, 6.0 Bcf in 2005, 5.8 Bcf in 2006, 6.0 Bcf in 2007, 6.9 Bcf in 2008 and 6.9 Bcf in 2009. The volumes contracted under the agreement in Argentina are 7.5 Bcf for the remainder of 2004, 6.1 Bcf in 2005, 3.3 Bcf in 2006, 3.6 Bcf in 2007 and 3.9 Bcf in 2008. The Company made no payments under these agreements in the three months ended March 31, 2004 and 2003.

6.	PRICE RISK MANAGEMENT

The Company periodically uses hedges to reduce the impact of oil and natural gas price fluctuations. The Company participated in oil hedges covering approximately 1.4 million barrels in the first three months of 2004.

As of March 31, 2004, the Company has entered into various oil price swap agreements for various periods of the remainder of 2004 and 2005 covering approximately 5.3 million barrels at a weighted average NYMEX reference price of $28.50 per barrel and gas price swap agreements for various periods of the remainder of 2004 covering approximately 3.7 million MMBtu at a weighted average NYMEX reference price of $5.92 per MMBtu. Additionally, the Company has entered into basis swap agreements for all of its 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 received by the Company. At March 31, 2004, the Company had a derivative financial instrument payable of $23.4 million related to cash flow hedges in place on anticipated 2004 and 2005 production. The Company did not discontinue any hedges in the first quarter of 2004 as a result of the probability that the original forecasted transaction would not occur. The Company continues to monitor oil and gas prices and may enter into additional oil and gas hedges or swaps in the future.

7.	INCOME TAXES

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


	Three Months Ended March 31,
	2004		2003
U.S. federal statutory income tax rate	35.0	%	35.0	%
U.S. state income tax (net of federal tax benefit)	(0.7	)	0.5
U.S. permanent differences	(0.9	)	7.8
Foreign operations	7.7		(0.6	)

	41.1	%	42.7	%

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The impact of foreign operations in 2004 and 2003 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. The Company recorded additional U.S. income taxes of $37.8 million in the first quarter of 2003 related to the repatriation of previously untaxed foreign earnings as a result of the sale of all of its interest in Ecuador in January 2003. 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.

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).

In accordance with the rules established by SFAS 144, the Company’s operations in Ecuador, along with the gain on the sale, 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):


	Three Months Ended March 31, 2003
Revenues	$	3,083

Income from discontinued operations	$	1,812
Deferred 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

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.

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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 United States exploration and production business segment. Information for 2003 has been reclassified to conform to this presentation.

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 United States. The Company operates in the oil and gas exploration and production industry in the United States, Canada, Argentina, Bolivia, Yemen and Italy. The financial information related to the Company’s discontinued operations in Ecuador has been excluded in all periods presented (see Note 8). Summarized financial information for the Company’s reportable segments for the three month periods ended March 31, 2004 and 2003, is shown in the following tables (in thousands):

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	Exploration and Production
	U.S.			Canada		Argentina			Bolivia		Yemen
Three Months Ended 3/31/04
Revenues from external customers	$	73,881		$	25,035	$	71,675		$	3,415	$	—
Intersegment revenues		—			—		—			—		—
Depreciation, depletion and amortization expense		10,664			8,084		12,104			715		—
Operating income (loss)		28,128			2,783		37,685			1,519		(264	)
Total assets		487,515			191,471		549,509			112,644		26,502
Capital investments		21,997			8,006		21,311			—		2,567
Long-lived assets		451,966			171,271		500,305			90,721		25,929

	Other Foreign Explor. & Production			Gas Marketing		Corporate			Total
Three Months Ended 3/31/04
Revenues from external customers	$	—		$	22,257	$	—		$	196,263
Intersegment revenues		—			381		—			381
Depreciation, depletion and amortization expense		—			—		688			32,255
Operating income (loss)		(183	)		701		(13,504	)		56,865
Total assets		1,352			14,423		97,781			1,481,197
Capital investments		328			—		674			54,883
Long-lived assets		992			—		6,306			1,247,490

	Exploration and Production
	U.S.			Canada		Argentina			Bolivia		Yemen
Three Months Ended 3/31/03
Revenues from external customers	$	70,737		$	38,592	$	73,727		$	3,108	$	—
Intersegment revenues		—			—		—			—		—
Depreciation, depletion and amortization expense		9,960			15,334		10,298			649		—
Operating income (loss)		30,667			7,358		39,423			1,270		(1,844	)
Total assets		457,675			621,419		520,722			121,047		19,488
Capital investments		21,054			11,496		7,062			257		5,199
Long-lived assets		428,018			587,522		472,455			93,561		19,253

	Other Foreign Explor. & Production			Gas Marketing		Corporate			Total
Three Months Ended 3/31/03
Revenues from external customers	$	—		$	32,920	$	—		$	219,084
Intersegment revenues		—			328		—			328
Depreciation, depletion and amortization expense		—			—		1,053			37,294
Operating income (loss)		(5	)		883		(13,616	)		64,136
Total assets		354			19,683		141,486			1,901,874
Capital investments		146			—		77			45,291
Long-lived assets		228			—		5,339			1,606,376

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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 the 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 $300 million. We funded this reduction in debt with proceeds from property sales, reducing our capital expenditures and cash provided by operating activities. We have $67.9 million of cash at March 31, 2004. In addition, as of March 31, 2004, we have unused availability under our revolving credit facility of $161.2 million (considering outstanding letters of credit of approximately $0.9 million).

Our cash provided by continuing operations for the first quarter of 2004 was $84.5 million, which was two percent higher than the same period in 2003. Production in the first quarter of 2004 declined seven percent versus the first quarter of 2003 on a BOE basis and we incurred higher production costs related to the repair of damage resulting from October 2003 fires in California. These decreases in cash provided by continuing operations were offset by an increase in cash provided by changes in working capital. The production decline is the result of the property sales, natural production declines, impacted by reduced capital expenditure programs in Canada, and the adverse impact of a labor strike by contract oil field workers in Argentina in March 2004.

In addition to strong cash provided by operating activities, we reported net income of $19.1 million in the first quarter of 2004. Net income for the first quarter of 2004 was lower than our net income of $40.7 million in the first quarter of 2003. However, net income in the first quarter of 2003 included income from discontinued operations of $10.8 million and a positive cumulative effect of a change in accounting principle of $7.1 million. Net income from the first quarter of 2004 included charges for the early extinguishment of debt of $6.0 million after tax related to the retirement of the entire $150 million principal balance of our 9 3/4% senior subordinated notes and $2.4 million after tax for the impairment of a certain producing oil and gas property in the United States. Partially offsetting these charges was a $6.0 million gain after tax for the settlement of a certain contract claim we had against a third party.

Our focus for 2004 has been to return to profitability with production and reserve growth from a balance of acquisitions, exploitation and exploration. We have increased our non-acquisition oil and gas capital expenditure budget to $225 million, which is 24 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. In the event we successfully secure 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. 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.

-21-

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.

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 March 31,
	2004	2003
Production:
Oil (MBbls) -
U.S.	1,513	1,556
Canada	235	374
Argentina ^{(a) (d)}	2,441	2,526
Bolivia ^(b)	20	19
Yemen ^(c)	—	—
Continuing operations	4,209	4,475
Ecuador	—	114
Total	4,209	4,589
Gas (MMcf) -
U.S.	6,240	6,017
Canada	3,938	5,876
Argentina ^(d)	2,032	2,030
Bolivia	1,719	1,418
Total	13,929	15,341
MBOE from continuing operations	6,531	7,032
Total MBOE	6,531	7,146

^(a)	Production for Argentina for the three months ended March 31, 2004 and 2003, before the impact of changes in inventories, was 2,475 MBbls and 2,529 MBbls, respectively.

^(b)	Production for Bolivia for the three months ended March 31, 2004 and 2003, before the impact of changes in inventories, were both 21 MBbls.

^(c)	Production for Yemen for the three months ended March 31, 2004, before the impact of changes in inventories, was one MBbl.

^(d)	Argentina production for the first quarter of 2004 is estimated to have been reduced by 165 MBbls of oil and 135 MMcf of gas, or 188 MBOE, as the result of a labor strike late in the first quarter.

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	Three Months Ended March 31,
	2004		2003
Average Sales Price (including impact of hedges):

Oil (per Bbl) -
U.S.	$	27.94	$	26.56
Canada		27.84		30.88
Argentina		28.95		28.86
Bolivia		23.86		22.48
Continuing operations		28.50		28.20
Ecuador		—		26.87
Total		28.50		28.17

Gas (per Mcf) -
U.S.	$	4.99	$	4.83
Canada		4.68		4.58
Argentina		0.49		0.41
Bolivia		1.70		1.89
Total		3.84		3.88
Average Sales Price (excluding impact of hedges):

Oil (per Bbl) -
U.S.	$	32.51	$	31.50
Canada		30.78		31.14
Argentina		28.95		28.86
Bolivia		23.86		22.48
Continuing operations		30.31		29.94
Ecuador		—		26.87
Total		30.31		29.87

Gas (per Mcf) -
U.S.	$	4.99	$	5.77
Canada		4.68		5.33
Argentina		0.49		0.41
Bolivia		1.70		1.89
Total		3.84		4.54

-23-

Oil Prices

Average U.S. and Canada oil prices 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. We experienced a one percent increase in our average oil price, including the impact of hedging activities (one percent increase excluding hedging activities), during the first three months of 2004 as compared to the same period of 2003. Our realized average oil price for the first three months of 2004 (before hedges) was approximately 86 percent of the NYMEX reference price compared to 88 percent for the same period of 2003.

We currently export approximately 45 percent of our Argentine oil production. Argentina oil exports are subject to a 20 percent tax. This tax is applied on the sales value after the tax, thus, the net effect is 16.7 percent. 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 will 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 net cost savings from the devaluation of the peso on peso-denominated costs and is further reduced by the Argentine income tax savings related to deducting the impact of the export tax.

We participated in oil hedges covering 1.4 MMBbls and 1.2 MMBbls in the first quarters of 2004 and 2003, respectively. The impact of these oil hedges on our average oil prices is reflected in the preceding tables.

Gas Prices

Average U.S. gas prices we receive generally fluctuate with changes in spot market prices, which may vary significantly by region. Our gas in Canada is generally sold at spot market prices as reflected by the AECO gas price index. Most 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 total average gas price for the first three months of 2004, including the impact of hedging activities, was one percent lower (15 percent lower excluding hedging activities) than the same period of 2003.

We participated in gas hedges covering approximately 5.0 million MMBtu during the first three months of 2003. We did not participate in any gas hedges in the first three months of 2004.

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Future Period Hedges

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 March 31, 2004, we have entered into various oil price swap agreements for various periods of the remainder of 2004 and 2005 covering approximately 5.3 million barrels at a weighted average NYMEX reference price of $28.50 per barrel and gas price swap agreements for various periods of the remainder of 2004 covering approximately 3.7 million MMBtu at a weighted average NYMEX reference price of $5.92 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.

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 affected by acquisitions and dispositions we made 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). 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, 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 for all periods.

Three months ended March 31, 2004, compared to three months ended March 31, 2003

We reported net income of $19.1 million in the first quarter of 2004, which was lower than our net income of $40.7 million in the first quarter of 2003. Net income in the first quarter of 2003 included income from discontinued operations of $10.8 million and a positive cumulative effect of a change in accounting principle of $7.1 million. Net income in the first quarter of 2004 included charges for the early extinguishment of debt of $6.0 million after tax related to the retirement of the entire $150 million principal balance of our 9 3/4% senior subordinated notes and $2.4 million after tax for the impairment of a certain proved oil and gas property in the United States. Partially offsetting these charges was a $6.0 million gain after tax for the settlement of a certain contract claim we had against a third party. Operating income for the first quarter of 2004 of $56.9 million was 11 percent lower than operating income for the first quarter of 2003 of $64.1 million primarily as the result of a seven percent decrease in production on an equivalent barrel basis, mostly from Canadian production declines, and costs incurred in the first quarter of 2004 to repair damage resulting from the October 2003 fires in California, which were partially offset by our $6.0 million gain on the contract claim discussed above.

-25-

Oil, condensate and NGL sales decreased $6.2 million, five percent, to $120.0 million for the first quarter of 2004 from $126.2 million for the first quarter of 2003, primarily as a result of a labor strike in Argentina and natural production declines in Canada. Oil production declined by six percent in the first quarter of 2004 compared to the first quarter of 2003. Argentine production was adversely impacted by a labor strike by contract oil field workers late in the first quarter of 2004. As a result of the strike, a portion of our first and second quarter 2004 Argentine production was temporarily shut-in and drilling and workover operations were temporarily suspended. During the first quarter of 2004, we estimate that this temporary shut-in period reduced Argentina oil volumes by approximately 165 MBbls. The impact on the second quarter of 2004 is estimated at a 200 MBbl reduction due to the temporary shut-ins. The labor strike has been resolved with production and work activities returning to pre-strike levels. Our realized oil price was relatively unchanged from period to period, increasing one percent in the first quarter of 2004 compared to the first quarter of 2003.

Gas sales decreased by $5.9 million, 10 percent, to $53.5 million for the first quarter of 2004 from $59.4 million for the first quarter of 2003, resulting from a nine percent decrease in gas production. This decline in gas production resulted from the combined effects of non-strategic asset sales in the U.S. and Canada in 2003, natural production declines in Canada and the labor strike in Argentina. We estimate that the temporary shut-in period resulting from the strike reduced Argentina gas volumes by approximately 135 MMcf for the first quarter of 2004 and we estimate the strike’s effect on the second quarter of 2004 to be a reduction in gas volumes of approximately 165 MMcf. Our realized gas price was relatively unchanged from period to period, decreasing one percent in the first quarter of 2004 compared to the first quarter of 2003.

Revenues and expenses for gas marketing decreased significantly from the first quarter of 2003 to the first quarter of 2004 primarily due to a reduction in volumes we marketed in the U.S. as a result of the sale of certain non-strategic assets in the United States.

Production costs increased $8.4 million, 23 percent, to $45.7 million for the first quarter of 2004 from $37.3 million for the first quarter of 2003. This increase is primarily due to costs incurred to repair damage resulting from the October 2003 fires in California and higher costs, expressed in U.S. dollars, in Argentina and Canada resulting from the strengthening of the Argentine peso and Canadian dollar.

Export taxes in Argentina decreased $4.0 million, 39 percent, to $6.2 million for the first quarter of 2004 from $10.2 million for the first quarter of 2003, primarily as a result of a shift in sales volumes from the export market to the domestic market in the first quarter of 2004 compared to the same period in 2003.

Exploration costs decreased $9.7 million, 69 percent, to $4.4 million for the first quarter of 2004 from $14.1 million for the first quarter of 2003. Exploration costs for the first quarter of 2004 consisted of $1.8 million for seismic and other geological and geophysical costs, $1.3 million for unsuccessful exploratory drilling and $1.3 million for impairments of unproved leasehold. During the first quarter of 2003, our exploration costs included $9.7 million for unsuccessful exploratory drilling, $2.3 million for seismic and other geological and geophysical costs and $2.1 million for impairments of unproved leaseholds. The majority of the leasehold impairments in both periods were from Canadian acreage.

-26-

General and administrative expenses increased $3.4 million, 25 percent, to $16.9 million for the first quarter of 2004 from $13.5 million for the first quarter of 2003. In the first quarter of 2004, we recorded expenses related to employee bonuses and severance benefits for a former executive. There were no corresponding amounts in the first quarter of 2003. Expenses also increased due to higher costs, expressed in U.S. dollars, in Argentina and Canada resulting from the strengthening of the Argentine peso and Canadian dollar.

Stock compensation increased $2.8 million to $3.8 million in the first quarter of 2004 from $1.0 million in the first quarter 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 $2.2 million in the first quarter of 2004. There were no comparable charges in the first quarter of 2003.

Depreciation, depletion and amortization decreased $5.0 million, 13 percent, to $32.3 million for the first quarter of 2004 from $37.3 million for the first quarter of 2003. Our average oil and gas amortization rate per equivalent barrel produced decreased to $4.79 for the first quarter of 2004 from $5.16 for the first quarter of 2003. Both of these decreases primarily relate to our Canadian operations. In the fourth quarter of 2003, we recorded impairments of proved oil and gas properties of $356.2 million, most of which related to Canadian properties. Although we also recorded significant downward revisions to our Canadian oil and gas reserve estimates in the fourth quarter of 2003, the impairments and reserve revisions together resulted in a significant reduction in our Canadian oil and gas amortization rate per equivalent barrel produced. This rate decrease, along with a seven percent decrease in our worldwide production on an equivalent barrel basis, primarily from Canadian production declines, resulted in the lower depreciation, depletion and amortization expense.

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

We reported $4.9 million of net other operating income for the first quarter of 2004 compared to net other operating expenses of $1.2 million for the first quarter of 2003. The change from period to period primarily relates to a $6.0 million gain for the settlement of a certain contract claim that we had against a third party.

Interest expense decreased $4.5 million, 24 percent, to $14.0 million for the first quarter of 2004 from $18.5 million for the first quarter of 2003 due to a 16 percent reduction in our average debt outstanding and a six percent decrease in our average interest rate from the first quarter of 2003 to the first 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. In addition to cash payments for the call premiums on the notes, we were required to expense 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 quarter of 2004 and $1.4 million, $0.9 million after tax, in the first quarter of 2003.

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We recorded foreign currency exchange losses of $1.1 million in the first quarter of 2004 and $3.6 million in the first quarter of 2003. These losses are primarily related to our operations in Argentina. During the first quarter of 2004, the Argentine peso strengthened against the U.S. dollar, with an exchange rate of 2.86 pesos to one U.S. dollar at March 31, 2004, compared to a rate of 2.94 pesos to one U.S. dollar at December 31, 2003. The strengthening of the Argentine peso was even more significant in the first quarter of 2003, with an exchange rate of 2.98 pesos to one U.S. dollar at March 31, 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.

We implemented Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations (“SFAS No. 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 No. 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 No. 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 quarter of 2004 were funds generated from operations and borrowings under our revolving credit facility. The cash was primarily used to fund capital expenditures, redeem higher rate debt and pay dividends, with the remainder increasing our cash position by $13.0 million. See below for additional discussion of our cash flows from operating activities.


	Three Months Ended March 31,						Change
	2004			2003			Change
	(in thousands)
Cash provided (used) by:
Operating activities - continuing operations	$	84,450		$	82,893		$	1,557
Operating activities - discontinued operations		—			(2,045	)		2,045
Investing activities - continuing operations		(54,303	)		97,740			(152,043	)
Investing activities - discontinued operations		—			10,309			(10,309	)
Financing activities		(16,525	)		(88,115	)		71,590

Cash provided by continuing operations increased two percent to $84.5 million in the first quarter of 2004 compared to $82.9 million in the first quarter of 2003. Production in the first quarter of 2004 declined seven percent versus the first quarter of 2003 on a BOE basis and we incurred higher production costs related to the repair of damage resulting from October 2003 fires in California. These decreases in cash provided by continuing operations were more than offset by an increase in cash provided by changes in working capital. See Results of Operations and Period to Period Comparison for further discussion.

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Investing activities in the first quarter of 2004 include capital spending of $52.8 million, or 62 percent of cash provided by operating activities. This compares to capital spending in the first quarter of 2003 of $46.4 million, or 57 percent of cash provided by operating activities. Cash provided by investing activities in the first quarter of 2003 includes $174.0 million for proceeds from the sales of our operations in Ecuador and certain properties in the U.S. We have increased our 2004 capital budget to more closely match expected cash flows.

Cash used by financing activities in the first quarters 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.

Capital Expenditures

During the first three months of 2004, our total capital expenditures were $54.2 million. In North America, our capital expenditures totaled $30.0 million, including $1.8 million for acquisitions. Exploitation activities accounted for $17.7 million of the North America capital expenditures with exploration activities contributing $10.5 million. Our capital expenditures outside of North America totaled $24.2 million. This amount consists of exploitation activities of $21.3 million in Argentina and $2.9 million for exploration activities, primarily in Yemen.

As of March 31, 2004, we had unproved oil and gas property costs of approximately $57.0 million, consisting of undeveloped leasehold costs of $38.6 million, including $28.3 million in Canada, and unevaluated exploratory drilling costs of $18.4 million. Approximately $11.9 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. Our capital expenditure budget for 2004 is currently set at $225 million, exclusive of acquisitions. We do not have a specific acquisition budget since the timing and size of acquisitions are difficult to forecast. 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.

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.

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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 as well as two public debt offerings and three Rule 144A private debt offerings, all of 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).

During the first quarter of 2003, we advanced funds under our revolving credit facility to redeem the 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 three-year senior secured credit facility maturing in May 2005 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 $300 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 also currently set at $300 million. The next borrowing base redetermination will be in May 2004 and we do not expect a significant change in the borrowing base. We also expect an extension of our revolving credit facility to 2008. As of March 31, 2004, we have unused availability under our revolving credit facility of $161.2 million (considering outstanding letters of credit of approximately $0.9 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 quarter of 2004 were relatively unchanged compared to the same period in 2003. However, these prices have historically fluctuated widely in response to changing market forces. For the first three months of 2004, approximately 64 percent of our production 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.

Consistent with our stated goal of maintaining financial flexibility and optimizing our portfolio of assets, we announced in early 2002 plans 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 March 31, 2004, was $620.0 million, compared to approximately $1.0 billion at December 31, 2001.

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Contractual Obligations

Our contractual obligations have not changed significantly since December 31, 2003, except that 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. The revolving credit facility matures in May 2005.

Inflation

As a result of the recent 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 during the first quarter of 2004, the Argentine inflation rate was 1.3 percent. 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 of approximately $12.6 million and $14.5 million for the first three 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.

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


	Three Months Ended March 31,
	2004		2003
U.S. federal statutory income tax rate	35.0	%	35.0	%
U.S. state income tax (net of federal tax benefit)	(0.7	)	0.5
U.S. permanent differences	(0.9	)	(0.6	)
Foreign operations	7.7		7.8

	41.1	%	42.7	%

The impact of foreign operations in 2004 and 2003 is primarily the result of lower tax depreciation, depletion and amortization in Argentina due to the inability to utilize inflation accounting for tax purposes. We recorded additional U.S. income taxes of $37.8 million in the first quarter of 2003 related to the repatriation of previously untaxed foreign earnings as a result of the sale of all of our interest in Ecuador in January.

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Critical Accounting Policies and Estimates

Our critical accounting policies are discussed in our 2003 Annual Report on Form 10-K (the “Annual Report”), “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 Annual Report.

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.

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 Form 10-K for the year ended December 31, 2003, 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;

•

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.

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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 the first three months of 2004 oil production from continuing operations, 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 $10.4 million and $15.9 million, respectively. A 10 cent per Mcf change in the average price we realize, before hedges, would result in a change in net income and revenues less production taxes on an annual basis of approximately $4.1 million and $5.5 million, respectively, based on gas production for the first three 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 March 31, 2004, we have entered into various oil price swap agreements for various periods of the remainder of 2004 and 2005 covering approximately 5.3 million barrels at a weighted average NYMEX reference price of $28.50 per barrel. Subsequent to March 31, 2004, we entered into gas price swap agreements for various periods of the remainder of 2004 covering approximately 3.7 million MMBtu a weighted average NYMEX reference price of $5.92 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 March 31, 2004, we would have paid approximately $23.4 million to terminate our swap agreements then in place. 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 March 31, 2004, 80 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 March 31, 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 and $1.4 million, respectively.

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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 3/31/04
Long-Term Debt:
Fixed rate (in thousands)	—		—	—	—	—	$	549,944		$	549,9447		$	603,500
Average interest rate	—		—	—	—	—		8.1	%		8.1	%		—
Variable rate (in thousands)	—	$	137,900	—	—	—		—		$	137,900		$	137,900
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 2.25 percent. Current increment above LIBOR at March 31, 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. For the first quarter of 2004, our operations in Argentina and Canada accounted for approximately 37 percent and 13 percent, respectively, of our revenues and 37 percent and 13 percent, respectively, of our total assets. During the first quarter of 2004, our operations in Argentina and Canada represented our only foreign operations accounting 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.

Historically, we have 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.

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 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.

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

Canada. We view the operating environment and economy in Canada as stable. Substantially all of our Canadian revenues and costs are denominated in Canadian dollars. While the value of the Canadian dollar does fluctuate in relation to the U.S. dollar, we believe that any currency risk associated with our Canadian operations would not have a material impact on our results of operations. The exchange rate at March 31, 2004, was US$1:C$1.31 as compared to US$1:C$1.30 at December 31, 2003.

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 March 31, 2004, was 2.86 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 March 31, 2004, were as follows (in thousands):


	Peso Balance		U.S. Dollar Equivalent
Current assets	66,041		$	23,091
Current liabilities	(79,328	)		(27,737	)
Non-current liabilities	(123,052	)		(43,025	)

Net monetary liabilities	(136,339	)	$	(47,671	)

On February 13, 2002, the Argentine government announced a 20 percent tax on oil exports, effective March 1, 2002. The tax is limited by law to a maximum of five years. The tax of 20 percent is applied on the sales value after the tax, thus the net effect is 16.7 percent. During 2003, we exported approximately 60 percent of our Argentine oil production and in the first quarter of 2004, we exported approximately 45 percent of our Argentine oil production. 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 (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 net cost savings resulting from the devaluation of the peso on peso-denominated costs and is further reduced 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.

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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.

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.

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 to LIBOR.

We sold approximately 1.4 MMBbls of our net Argentine oil production (approximately 14 percent) under this agreement during 2003. During the first quarter of 2004, we sold approximately 400 MBbls of additional net oil production (approximately 16 percent) under the agreement. 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 to make changes to his cabinet team due to continued political pressure and 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. President Mesa continues to promise a public referendum on plans to export Bolivian gas. The vote is scheduled to occur during the third quarter 2004 and is expected to take place only after a new hydrocarbons law is presented to the Bolivian Congress for consideration. The government continues to debate proposed revisions to the hydrocarbons law, which targets to increase taxation of the energy industry by as much as $50 million per year. We cannot predict the outcome of such political events, but we will continue to monitor their progress.

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In March 2004, the Bolivian government proposed a new tax on all banking transactions, except for payments made to the Bolivian government. The tax is expected to be effective for two years beginning June 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 us in 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 March 31, 2004, was 7.90 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.

Bolivian gas markets are generally 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 substantially in excess of our contracted volumes. 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. With President Mesa’s promise of a public referendum on the matter of gas exports, we believe that new projects, such as exports to Mexico and the U.S., 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 and kidnappings are ongoing security 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

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 March 31, 2004. Based upon that evaluation, 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. During the first quarter of 2004, 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.

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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.

Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Securities

The following table provides information about purchases by us during the quarter ended March 31, 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
January 1, 2004 - January 31, 2004	4,000	$	12.45	—	—
February 1, 2004 - February 29, 2004	—		—	—	—
March 1, 2004 - March 31, 2004	—		—	—	—

Total	4,000	$	12.45	—	—

⁽¹⁾	In connection with the maturity of certain indebtedness to us, an employee transferred 4,000 shares of common stock owned by him securing this indebtedness to us and paid a certain amount of cash 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

Item 4.

Submission of Matters to a Vote of Security Holders

not applicable

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Item 5.

Other Information

not applicable

Item 6.

Exhibits and Reports on Form 8-K

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 herewith.

10.1

Separation Agreement and Release between us and S. Craig George dated March 3, 2004.

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.

Reports on Form 8-K

None.

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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: May 6, 2004

/s/ MICHAEL F. MEIMERSTORF

Michael F. Meimerstorf

Vice President and Controller

(Principal Accounting Officer)

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Exhibit Index


Exhibit Number		Description

10.1		Separation Agreement and Release between us and S. Craig George dated March 3, 2004.

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.