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 June 30, 2004

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

For the transition period from to

Commission file number 1-10578

VINTAGE PETROLEUM, INC.

(Exact name of registrant as specified in charter)


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

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

(918) 592-0101

(Registrant’s telephone number, including area code)

NOT APPLICABLE

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes x No ¨

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

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


Class		Outstanding at July 30, 2004
Common Stock, $0.005 Par Value		65,174,644

VINTAGE PETROLEUM, INC.

FORM 10-Q

THREE MONTHS ENDED JUNE 30, 2004

TABLE OF CONTENTS


		Page

PART I.	FINANCIAL INFORMATION

Item 1.	Financial Statements

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

	Consolidated Statements of Operations for the Three Months and Six Months Ended June 30, 2004 and 2003	6

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

	Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2004 and 2003	9

	Notes to Unaudited Consolidated Financial Statements	10

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	23

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	39

Item 4.	Controls and Procedures	45

PART II.	OTHER INFORMATION

Item 1.	Legal Proceedings	47

Item 2.	Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Securities	47

Item 3.	Defaults Upon Senior Securities	47

Item 4.	Submission of Matters to a Vote of Security Holders	48

Item 5.	Other Information	48

Item 6.	Exhibits and Reports on Form 8-K	48

	Signatures	50

PART I

FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

VINTAGE PETROLEUM, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In thousands, except shares

and per share amounts)

(Unaudited)

ASSETS


	June 30, 2004		December 31, 2003
CURRENT ASSETS:
Cash and cash equivalents	$	75,470	$	54,880
Accounts receivable–
Oil and gas sales		99,654		89,674
Joint operations		11,938		9,359
Prepaids and other current assets		17,413		14,702

Total current assets		204,475		168,615

PROPERTY, PLANT AND EQUIPMENT, at cost:
Oil and gas properties, successful efforts method		2,796,217		2,717,193
Oil and gas gathering systems and plants		23,725		23,344
Other		30,071		29,072


		2,850,013		2,769,609

Less accumulated depreciation, depletion and amortization		1,582,080		1,535,715

Total property, plant and equipment, net		1,267,933		1,233,894

OTHER ASSETS, net		43,108		44,329

TOTAL ASSETS	$	1,515,516	$	1,446,838

See notes to unaudited consolidated financial statements.

VINTAGE PETROLEUM, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Continued)

(In thousands, except shares

and per share amounts)

(Unaudited)

LIABILITIES AND STOCKHOLDERS’ EQUITY


	June 30, 2004		December 31, 2003
CURRENT LIABILITIES:
Revenue payable	$	33,984	$	26,654
Accounts payable – trade		51,779		55,601
Current income taxes payable		13,204		19,933
Derivative financial instruments payable		30,293		7,876
Other payables and accrued liabilities		80,627		70,028

Total current liabilities		209,887		180,092

LONG-TERM DEBT		699,046		699,943

DEFERRED INCOME TAXES		50,157		54,302

LONG-TERM LIABILITY FOR ASSET RETIREMENT OBLIGATIONS		91,809		89,076

OTHER LONG-TERM LIABILITIES		554		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, 65,392,733 and 64,720,975 shares issued and 64,937,989 and 64,281,199 outstanding, respectively		327		324
Capital in excess of par value		346,683		337,080
Retained earnings		73,235		22,844
Accumulated other comprehensive income		51,829		70,482

		472,074		430,730
Less treasury stock, at cost 454,744 and 439,776 shares		3,246		3,117
Less unamortized cost of restricted stock awards		4,765		5,127

Total stockholders’ equity		464,063		422,486

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	1,515,516	$	1,446,838

See notes to unaudited consolidated financial statements.

VINTAGE PETROLEUM, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share amounts)

(Unaudited)


	Three Months Ended June 30,						Six Months Ended June 30,
	2004			2003			2004			2003
REVENUES:
Oil, condensate and NGL sales	$	123,698		$	111,485		$	243,662		$	237,700
Gas sales		62,470			48,036			115,955			107,479
Sulfur sales		350			703			908			1,209
Gas marketing		23,884			26,741			46,140			59,661

Total revenues		210,402			186,965			406,665			406,049

COSTS AND EXPENSES:
Production costs		44,245			39,753			89,968			76,581
Transportation and storage costs		3,142			2,357			5,091			4,784
Production and ad valorem taxes		5,818			4,026			11,514			8,759
Export taxes		6,706			8,183			12,912			18,405
Exploration costs		9,573			32,449			13,933			46,527
Gas marketing		22,902			26,386			44,457			58,423
General and administrative		17,061			14,386			33,965			27,840
Stock compensation		2,176			1,482			5,938			2,434
Depreciation, depletion and amortization		29,550			34,783			61,805			72,077
Impairment of proved oil and gas properties		–			12,571			3,915			12,571
Accretion		1,970			1,832			3,939			3,579
Other operating (income) expense		1,151			403			(3,745	)		1,579

Total costs and expenses		144,294			178,611			283,692			333,559

OPERATING INCOME		66,108			8,354			122,973			72,490

OTHER (INCOME) EXPENSE:
Interest expense		12,674			18,016			26,695			36,557
Loss on early extinguishment of debt		–			–			9,903			1,426
(Gain) loss on disposition of assets		4			(305	)		(55	)		345
Foreign currency exchange (gain) loss		(1,960	)		3,514			(838	)		7,151
Other non-operating (income) expense		531			(1,665	)		(96	)		(1,444	)

Net other expense		11,249			19,560			35,609			44,035

Income (loss) from continuing operations before income taxes and cumulative effect of change in accounting principle		54,859			(11,206	)		87,364			28,455

INCOME TAX PROVISION (BENEFIT):
Current		13,520			16,369			26,168			30,832
Deferred		3,930			(18,888	)		4,652			(16,408	)

Total income tax provision (benefit)		17,450			(2,519	)		30,820			14,424

Income (loss) from continuing operations before cumulative effect of change in accounting principle		37,409			(8,687	)		56,544			14,031
INCOME FROM DISCONTINUED OPERATIONS, net of income tax provision of $38,226		–			–			–			10,844

Income (loss) before cumulative effect of change in accounting principle		37,409			(8,687	)		56,544			24,875
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE, net of income tax provision of $4,104		–			–			–			7,119

NET INCOME (LOSS)	$	37,409		$	(8,687	)	$	56,544		$	31,994

See notes to unaudited consolidated financial statements.

VINTAGE PETROLEUM, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Continued)

(In thousands, except per share amounts)

(Unaudited)


	Three Months Ended June 30,					Six Months Ended June 30,
	2004		2003			2004		2003
BASIC INCOME (LOSS) PER SHARE:
Income (loss) from continuing operations before cumulative effect of change in accounting principle	$	0.58	$	(0.14	)	$	0.88	$	0.22
Income from discontinued operations		–		–			–		0.17

Income (loss) before cumulative effect of change in accounting principle		0.58		(0.14	)		0.88		0.39
Cumulative effect of change in accounting principle		–		–			–		0.11

Net income (loss)	$	0.58	$	(0.14	)	$	0.88	$	0.50

DILUTED INCOME (LOSS) PER SHARE:
Income (loss) from continuing operations before cumulative effect of change in accounting principle	$	0.57	$	(0.14	)	$	0.87	$	0.22
Income from discontinued operations		–		–			–		0.17

Income (loss) before cumulative effect of change in accounting principle		0.57		(0.14	)		0.87		0.39
Cumulative effect of change in accounting principle		–		–			–		0.11

Net income (loss)	$	0.57	$	(0.14	)	$	0.87	$	0.50

Weighted average common shares outstanding:
Basic		64,741		63,991			64,535		63,791

Diluted		65,487		63,991			65,258		64,193

See notes to unaudited consolidated financial statements.

VINTAGE PETROLEUM, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY

AND COMPREHENSIVE INCOME

FOR THE SIX MONTHS ENDED JUNE 30, 2004

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

(Unaudited)


	Common Stock			Treasury Stock			Capital In Excess of Par Value			Unamortized Restricted Stock Awards			Retained Earnings			Accumulated Other Comprehensive Income			Total
	Shares	Amount		Treasury Stock			Capital In Excess of Par Value			Unamortized Restricted Stock Awards			Retained Earnings			Accumulated Other Comprehensive Income			Total
BALANCE AT DECEMBER 31, 2003	64,721	$	324	$	(3,117	)	$	337,080		$	(5,127	)	$	22,844		$	70,482		$	422,486
Comprehensive income:
Net income	–		–		–			–			–			56,544			–			56,544
Foreign currency translation adjustment	–		–		–			–			–			–			(4,830	)		(4,830	)
Change in value of derivatives, net of tax	–		–		–			–			–			–			(13,823	)		(13,823	)

Total comprehensive income																				37,891

Stock options granted	–		–		–			376			–			–			–			376
Exercise of stock options and resulting tax effects	466		2		–			4,028			–			–			–			4,030
Issuance of restricted stock	166		1		–			2,494			(2,495	)		–			–			–
Amortization of restricted stock awards	–		–		–			2,791			2,828			–			–			5,619
Forfeitures of restricted stock (5,530 shares)	–		–		–			(86	)		29			–			–			(57	)
Vesting of restricted stock rights	40		–		–			–			–			–			–			–
Purchase of treasury stock (9,438 shares)	–		–		(129	)		–			–			–			–			(129	)
Cash dividends declared ($0.095 per share)	–		–		–			–			–			(6,153	)		–			(6,153	)


BALANCE AT JUNE 30, 2004	65,393	$	327	$	(3,246	)	$	346,683		$	(4,765	)	$	73,235		$	51,829		$	464,063

See notes to unaudited consolidated financial statements.

VINTAGE PETROLEUM, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)


	Six Months Ended June 30,
	2004			2003
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	56,544		$	31,994
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		61,805			72,077
Impairment of proved oil and gas properties		3,915			12,571
Accretion		3,939			3,579
Exploration costs		10,192			41,416
Provision (benefit) for deferred income taxes		4,652			(16,408	)
Foreign currency exchange (gain) loss		(838	)		7,151
(Gain) loss on dispositions of assets		(55	)		345
Loss on early extinguishment of debt		9,903			1,426
Stock compensation		5,938			2,434
Other non-cash items included in net income		918			5,393
Increase in receivables		(17,725	)		(10,421	)
Decrease in payables and accrued liabilities		(1,561	)		(20,107	)
Other working capital changes		4,579			1,557

Cash provided by continuing operations		142,206			115,044
Cash used by discontinued operations		–			(20,929	)

Cash provided by operating activities		142,206			94,115

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures–
Oil and gas properties		(106,263	)		(72,797	)
Gathering systems and other		(1,430	)		(3,024	)
Proceeds from sale of oil and gas properties		134			41,483
Proceeds from sale of company, net of cash sold		–			116,107
Other		(1,022	)		(2,717	)

Cash provided (used) by investing activities–continuing operations		(108,581	)		79,052
Cash provided by investing activities–discontinued operations		–			10,309

Cash provided (used) by investing activities		(108,581	)		89,361

CASH FLOWS FROM FINANCING ACTIVITIES:
Issuance of common stock		4,030			581
Purchase of treasury stock		(129	)		(1,295	)
Redemption of 9% Senior Subordinated Notes due 2005		–			(50,750	)
Redemption of 9³/4% Senior Subordinated Notes due 2009		(157,313	)		–
Advances on revolving credit facility and other borrowings		294,000			115,400
Payments on revolving credit facility and other borrowings		(144,900	)		(147,436	)
Dividends paid		(5,798	)		(5,089	)
Other		(3,053	)		–

Cash used by financing activities		(13,163	)		(88,589	)

EFFECT OF EXCHANGE RATE CHANGES ON CASH		128			2,670

NET INCREASE IN CASH AND CASH EQUIVALENTS		20,590			97,557

CASH AND CASH EQUIVALENTS, beginning of period		54,880			9,259

CASH AND CASH EQUIVALENTS, end of period	$	75,470		$	106,816

See notes to unaudited consolidated financial statements.

VINTAGE PETROLEUM, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2004 and 2003

1. GENERAL

The accompanying financial statements are unaudited. The consolidated financial statements include the accounts of Vintage Petroleum, Inc. and its wholly- and majority-owned subsidiaries and its proportionately consolidated general partner and limited partner interests in various joint ventures and partnerships (collectively, the “Company”). Management believes that all material adjustments (consisting of only normal recurring adjustments) necessary for a fair presentation have been made. Certain 2003 amounts have been reclassified to conform with the 2004 presentation. 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. The Company capitalized development seismic costs of $5.3 million and $1.4 million for the six months ended June 30, 2004 and 2003, respectively. The Company recognizes gains or losses on the sale of properties on a field basis.

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 $4.5 million and $31.2 million for the six months ended June 30, 2004 and 2003, respectively, and $3.1 million and $29.0 million for the three months ended June 30, 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. Leasehold impairments in the second quarter of 2003 included an expense of $23.7 million to fully impair the Company’s undeveloped leaseholds in the Northwest Territories.

As of June 30, 2004, the Company had unproved oil and gas property costs of approximately $63.7 million, consisting of undeveloped leasehold costs of $40.2 million, including $26.2 million in Canada, and unevaluated exploratory drilling costs of $23.5 million. Approximately $13.0 million of the total unevaluated costs are associated with the Company’s drilling program in Yemen.

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

In August 2001, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations (“SFAS 143”). The Company was required to adopt this new standard beginning January 1, 2003. Through December 31, 2002, the Company accrued an estimate of future abandonment costs of wells and related facilities through its depreciation calculation and included the cumulative accrual in accumulated depreciation in accordance with the provisions of Statement of Financial Accounting Standards No. 19, Financial Accounting and Reporting by Oil and Gas Producing Companies, and industry practice. SFAS 143 requires that the Company record the discounted fair value of the retirement obligation as a liability at the time a well is drilled or acquired. The asset retirement obligations consist primarily of costs associated with the plugging and abandonment of oil and gas wells, site reclamation and facilities dismantlement. However, future abandonment liabilities are also recorded for other assets such as pipelines, processing plants and compressors. A corresponding amount is capitalized as part of the related property’s carrying amount. The discounted capitalized asset retirement cost is amortized to expense through the depreciation calculation over the estimated useful life of the asset based on proved developed reserves. The liability accretes over time with a charge to accretion expense. At December 31, 2003 and June 30, 2004, there were no assets legally restricted for purposes of settling asset retirement obligations. Of the liability for asset retirement obligations balance at June 30, 2004, approximately $7.3 million is classified as current and is included in “other payables and accrued liabilities” in the accompanying balance sheet.

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

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


Liability for asset retirement obligations as of January 1, 2004	$	94,886
New obligations for wells drilled		222
New obligations for interests acquired		1,535
Costs incurred		(969	)
Accretion expense		3,939
Changes in foreign currency exchange rates		(505	)
Revisions in estimated cash flows		(22	)

Liability for asset retirement obligations as of June 30, 2004	$	99,086

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 second quarter of 2004 or the first quarter of 2003. In the second quarter of 2003, the Company recorded an impairment provision of $12.6 million related to its Canadian proved oil and gas properties.

Other Payables and Accrued Liabilities

As of June 30, 2004, “other payables and accrued liabilities” included $14.8 million of accrued production costs and $20.2 million of accrued oil and gas capital expenditures.

Statements of Cash Flows

During the six months ended June 30, 2004 and 2003, the Company made cash payments for interest totaling approximately $26.2 million, and $35.3 million, respectively. The Company had no cash payments for U.S. income taxes in the first six months of 2004. Cash payments for U.S. income taxes of $29.9 million were made during the first six months of 2003. The Company made cash payments of $37.0 million and $25.8 million, primarily in Argentina, during the first six months of 2004 and 2003, respectively, for foreign income taxes.

Hedging

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

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

General and Administrative Expense

The Company receives fees for the operation of jointly-owned oil and gas properties and records such reimbursements as reductions of general and administrative expense. Such fees totaled approximately $1.7 million and $2.1 million for the first six months of 2004 and 2003, respectively.

Income (Loss) Per Share

Basic income (loss) per common share was computed by dividing net income by the weighted average number of shares outstanding during the period. Diluted income (loss) per common share for all periods presented was computed assuming the exercise of all dilutive options, as determined by applying the treasury stock method, and assuming the vesting of all dilutive restricted stock rights. For the three months ended June 30, 2003, the assumed exercise for all options and the assumed vesting of all restricted stock rights would have been anti-dilutive because the Company had a net loss for the period. Therefore, the amounts reported for basic and diluted loss per share were the same. Had the Company been in a net income position for this period, the Company’s diluted weighted average outstanding common shares would have been approximately 64,444,000.

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


	Three Months Ended June 30,		Six Months Ended June 30,
	2004	2003	2004	2003
Weighted average common shares outstanding – Basic	64,741	63,991	64,535	63,791

Dilutive effect of potential common shares issuable upon the exercise of outstanding stock options	568	–	561	281

Dilutive effect of potential common shares issuable upon the vesting of outstanding restricted stock rights	178	–	162	121


Weighted average common shares outstanding – Diluted	65,487	63,991	65,258	64,193

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


	Three Months Ended June 30,				Six Months Ended June 30,
	2004		2003		2004		2003
Options excluded from dilution calculations (in thousands)		724		3,188		724		1,006
Range of exercise prices	$	15.50 - $22.94	$	7.25 - $22.94	$	15.50 - $22.94	$	10.34 - $22.94
Weighted average exercise price		$15.82		$10.45		$15.82		$14.79

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.

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 six months of 2004 and 2003 and for the second 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 (loss) and income (loss) 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 June 30,					Six Months Ended June 30,
	2004		2003			2004		2003
Stock compensation expense – as reported	$	2,176	$	1,482		$	5,938	$	2,434
Stock compensation expense – pro forma		2,210		1,452			6,011		3,057
Net income (loss) – as reported		37,409		(8,687	)		56,544		31,994
Net income (loss) – pro forma		37,387		(8,670	)		56,498		31,562
Income (loss) per share – as reported:
Basic		0.58		(0.14	)		0.88		0.50
Diluted		0.57		(0.14	)		0.87		0.50
Income (loss) per share – pro forma:
Basic		0.58		(0.14	)		0.88		0.49
Diluted		0.57		(0.14	)		0.87		0.49

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 June 30,						Six Months Ended June 30,
	2004			2003			2004			2003
Net income (loss)	$	37,409		$	(8,687	)	$	56,544		$	31,994
Foreign currency translation adjustments		(2,852	)		42,314			(4,830	)		75,698
Changes in value of derivatives, net of tax		(3,496	)		1,206			(13,823	)		(2,809	)

Comprehensive income	$	31,061		$	34,833		$	37,891		$	104,883

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).

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


	Three Months Ended June 30,						Six Months Ended June 30,
	2004			2003			2004			2003
Unrealized loss during the period	$	(7,773	)	$	(1,605	)	$	(24,675	)	$	(14,704	)
Reclassification adjustment for losses included in net income		1,571			4,622			1,933			10,917

		(6,202	)		3,017			(22,742	)		(3,787	)
Income tax provision (benefit)		(2,706	)		1,811			(8,919	)		(978	)

Changes in value of derivatives, net of tax	$	(3,496	)	$	1,206		$	(13,823	)	$	(2,809	)

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


	June 30, 2004			December 31, 2003
Foreign currency translation adjustments	$	67,721		$	72,551
Changes in value of derivatives, net of tax		(15,892	)		(2,069	)

	$	51,829		$	70,482

3. LONG-TERM DEBT

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


	June 30, 2004		December 31, 2003
Revolving credit facility	$	149,100	$	–
8¹/4% Senior Notes due 2012		350,000		350,000
Senior Subordinated Notes:
9³/4% Notes due 2009		–		150,000
7⁷/8% Notes due 2011, less unamortized discount		199,946		199,943

	$	699,046	$	699,943

During February 2004, the Company advanced funds under its revolving credit facility to redeem the entire principal balance of the 9³/4% Senior Subordinated Notes due 2009. As a result, the Company was required to expense certain associated deferred financing costs. This $2.6 million non-cash charge and a $7.3 million cash charge for the call premium resulted in a one-time charge of approximately $9.9 million ($6.0 million net of tax).

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

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

4. CAPITAL STOCK

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

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

The Company declared cash dividends of $0.095 and $0.085 per share for the six months ended June 30, 2004 and 2003, respectively, and $0.05 and $0.045 per share for the three months ended June 30, 2004 and 2003, respectively.

5. COMMITMENTS AND CONTINGENCIES

The Company had approximately $0.9 million in letters of credit outstanding at June 30, 2004. These letters of credit relate primarily to bonding requirements of various state regulatory agencies in the U.S. for oil and gas operations. The Company’s availability under its revolving credit facility is reduced by the outstanding letters of credit.

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 $2.1 million and $2.6 million under these agreements in the six months ended June 30, 2004 and 2003, respectively and paid $1.0 million and $1.3 million under these agreements in the three months ended June 30, 2004 and 2003, respectively. Based on the current fee level, these commitments total approximately $1.0 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 $1.8 million in 2004, $3.5 million in 2005, $3.5 million in 2006 and $4.9 million in 2007. The Company paid $1.1 million and $0.7 million under these agreements in the six months and three months ended June 30, 2004, respectively. 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 $0.2 million and $0.1 million under these agreements in the six months ended June 30, 2004 and 2003, respectively, and $0.1 million in each of the three months ended June 30, 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.

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 5.8 Bcf for the remainder of 2004, 6.1 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 5.0 Bcf for the remainder of 2004, 6.1 Bcf in 2005, 3.3 Bcf in 2006, 3.6 Bcf in 2007 and 4.0 Bcf in 2008. The Company made no payments under these agreements in the six months ended June 30, 2004 and 2003.

In June 2004, the Company signed an agreement to acquire 100 percent of an Argentine company whose principal asset is an operated producing concession in the San Jorge basin of Argentina. The Company will pay $36.4 million in cash, net of working capital and subject to adjustments, with funds provided by cash on hand. The transaction is anticipated to close in August 2004.

6. PRICE RISK MANAGEMENT

The Company periodically uses hedges to reduce the impact of oil and gas price fluctuations. The Company participated in hedges covering approximately 2.9 million barrels of oil and 1.2 million MMBtu of gas in the first six months of 2004.

As of June 30, 2004, the Company has entered into oil price swap agreements for various periods of the remainder of 2004 and for 2005, 2006 and 2007 covering approximately 5.3 million barrels at a weighted average NYMEX reference price of $29.81 per barrel and gas price swap agreements for various periods of the remainder of 2004 covering approximately 2.5 million MMBtu at a weighted average NYMEX reference price of $5.96 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 June 30, 2004, the Company had a derivative financial instrument payable of $30.3 million related to cash flow hedges in place on anticipated future oil and gas production. The Company did not discontinue any hedges in the first six months 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:


	Six Months Ended June 30,
	2004		2003
U.S. federal statutory income tax rate	35.0	%	35.0	%
U.S. state income tax (net of federal tax benefit)	0.4		1.6
U.S. permanent differences	1.0		0.9
Foreign operations	(1.1	)	13.2

	35.3	%	50.7	%

The impact of foreign operations in 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. 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 Statement of Financial Accounting Standards No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, the Company’s operations in Ecuador, along with the gain on the sale, 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):


	Six Months Ended June 30, 2003
Revenues	$	3,083

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

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

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

9. SEGMENT INFORMATION

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

The Company previously reported its gathering and plant operations as a separate business segment. Due to changes in the Company’s internal organization, as of January 1, 2004, the gathering and plant operations are now considered to be a part of the Company’s 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 six month and three month periods ended June 30, 2004 and 2003, is shown in the following tables (in thousands):


	Exploration and Production
	U.S.			Canada			Argentina			Bolivia		Yemen
Six Months Ended 6/30/04
Revenues from external customers	$	154,504		$	50,747		$	146,818		$	6,727	$	1,729
Intersegment revenues		–			–			–			–		–
Depreciation, depletion and amortization expense		22,234			15,668			21,003			1,460		222
Operating income (loss)		65,315			7,902			80,362			2,894		763
Total assets		510,620			181,945			563,211			112,274		26,027
Capital investments		52,063			11,114			42,562			–		7,139
Long-lived assets		468,009			161,357			512,325			89,973		29,989

	Other Foreign Explor. & Production			Gas Marketing			Corporate			Total
Six Months Ended 6/30/04
Revenues from external customers	$	–		$	46,140		$	–		$	406,665
Intersegment revenues		–			926			–			926
Depreciation, depletion and amortization expense		–			–			1,218			61,805
Operating income (loss)		1,032			1,683			(36,978	)		122,973
Total assets		1,925			17,814			101,700			1,515,516
Capital investments		4,016			–			1,049			117,943
Long-lived assets		–			–			6,280			1,267,933

	Exploration and Production
	U.S.			Canada			Argentina			Bolivia		Yemen
Six Months Ended 6/30/03
Revenues from external customers	$	134,693		$	65,724		$	138,828		$	7,143	$	–
Intersegment revenues		–			–			–			–		–
Depreciation, depletion and amortization expense		20,206			27,813			20,880			1,430		–
Operating income (loss)		59,232			(31,230	)		71,862			2,272		(2,435	)
Total assets		464,496			601,651			529,230			121,930		22,294
Capital investments		34,350			14,993			19,621			1,419		8,290
Long-lived assets		429,314			577,425			474,802			92,859		21,752

	Other Foreign Explor. & Production			Gas Marketing			Corporate			Total
Six Months Ended 6/30/03
Revenues from external customers	$	–		$	59,661		$	–		$	406,049
Intersegment revenues		–			626			–			626
Depreciation, depletion and amortization expense		–			–			1,748			72,077
Operating income (loss)		(265	)		1,238			(28,184	)		72,490
Total assets		566			13,641			136,623			1,890,431
Capital investments		453			–			1,169			80,295
Long-lived assets		276			–			5,700			1,602,128


	Exploration and Production
	U.S.			Canada			Argentina			Bolivia		Yemen
Three Months Ended 6/30/04
Revenues from external customers	$	80,623		$	25,712		$	75,143		$	3,311	$	1,729
Intersegment revenues		–			–			–			–		–
Depreciation, depletion and amortization expense		11,570			7,584			8,899			744		222
Operating income (loss)		37,186			5,119			42,678			1,375		1,028
Total assets		510,620			181,945			563,211			112,274		26,027
Capital investments		30,066			3,108			21,251			–		4,572
Long-lived assets		468,009			161,357			512,325			89,973		29,989

	Other Foreign Explor. & Production			Gas Marketing			Corporate			Total
Three Months Ended 6/30/04
Revenues from external customers	$	–		$	23,884		$	–		$	210,402
Intersegment revenues		–			545			–			545
Depreciation, depletion and amortization expense		–			–			531			29,550
Operating income (loss)		1,215			981			(23,474	)		66,108
Total assets		1,925			17,814			101,700			1,515,516
Capital investments		3,688			–			375			63,060
Long-lived assets		–			–			6,280			1,267,933

	Exploration and Production
	U.S.			Canada			Argentina			Bolivia		Yemen
Three Months Ended 6/30/03
Revenues from external customers	$	63,956		$	27,132		$	65,101		$	4,035	$	–
Intersegment revenues		–			–			–			–		–
Depreciation, depletion and amortization expense		10,245			12,479			10,582			781		–
Operating income (loss)		28,565			(38,589	)		32,440			1,003		(591	)
Total assets		464,496			601,651			529,230			121,930		22,294
Capital investments		13,296			3,497			12,559			1,162		3,091
Long-lived assets		429,314			577,425			474,802			92,859		21,752

	Other Foreign Explor. & Production			Gas Marketing			Corporate			Total
Three Months Ended 6/30/03
Revenues from external customers	$	–		$	26,741		$	–		$	186,965
Intersegment revenues		–			298			–			298
Depreciation, depletion and amortization expense		–			–			696			34,783
Operating income (loss)		(259	)		355			(14,570	)		8,354
Total assets		566			13,641			136,623			1,890,431
Capital investments		307			–			1,092			35,004
Long-lived assets		276			–			5,700			1,602,128

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS

OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Overview

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

Since the beginning of 2002, we have been focused on managing our financial leverage, maintaining liquidity and positioning ourselves for long-term growth. As a result of acquisitions in Canada and Argentina in 2001, we ended 2001 with $1.0 billion of long-term debt. Since that time, we have improved our balance sheet and leverage position by reducing long-term debt by over $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 $75.5 million of cash at June 30, 2004. In addition, as of June 30, 2004, we have unused availability under our revolving credit facility of $150 million (considering outstanding letters of credit of approximately $0.9 million).

Net income increased significantly in the second quarter of 2004 and the first six months of 2004 compared to the same periods in 2003. Operating income increased 691 percent from $8.4 million for the second quarter of 2003 to $66.1 million for the second quarter of 2004 and increased 70 percent from $72.5 million for the first six months of 2003 to $123.0 million for the first six months of 2004. Declines in production from continuing operations were more than offset by increases in oil and gas prices, with total revenues increasing by 13 percent from the second quarter of 2003 to the second quarter of 2004 and remaining relatively unchanged from the first six months of 2003 to the first six months of 2004. Operating costs and expenses decreased in the second quarter of 2004 and the first six months of 2004 compared to the same periods in 2003. Higher production costs and general and administrative expenses were more than offset by decreases in export taxes, exploration costs, and depreciation expense and lower impairments of proved oil and gas properties. Operating income for the first six months of 2004 also included a $6.0 million gain for the settlement of a certain contract claim we had against a third party. Non-operating expenses declined in the second quarter of 2004 and the first six months of 2004 compared to the same periods in 2003 due to lower interest expense. The decrease in interest expense for the first six months of 2004 compared to the same period in 2003 was partially offset by higher losses on the early extinguishment of debt. Net income in the first half 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. Our cash provided by continuing operations for the first half of 2004 was $142.2 million, which was 24 percent higher than the same period in 2003.

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

In June 2004, we signed an agreement to acquire certain operated producing properties in the San Jorge basin of Argentina. We will pay $36.4 million in cash, net of working capital and subject to adjustments, with funds provided by cash on hand. We expect this transaction to close in August 2004. In the event we successfully secure additional acquisitions of oil and gas properties, we will seek appropriate levels of oil and gas price risk management and equity capital in order to maintain or improve our capital structure.

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 June 30,			Six Months Ended June 30,
	2004		2003	2004		2003
Production:
Oil (MBbls) –
U.S.	1,532		1,613	3,045		3,169
Canada	215		297	450		671
Argentina (a)	2,434	(d)	2,538	4,875	(d)	5,064
Bolivia (b)	21		21	41		40
Yemen (c)	59		–	59		–
Continuing operations	4,261		4,469	8,470		8,944
Ecuador	–		–	–		114
Total	4,261		4,469	8,470		9,058
Gas (MMcf) –
U.S.	7,125		5,960	13,365		11,977
Canada	3,868		4,486	7,806		10,362
Argentina	2,147	(d)	2,561	4,179	(d)	4,591
Bolivia	1,829		1,635	3,548		3,053
Total	14,969		14,642	28,898		29,983
MBOE from continuing operations	6,756		6,909	13,286		13,941
Total MBOE	6,756		6,909	13,286		14,055

(a)	Production for Argentina for the three months ended June 30, 2004 and 2003, and for the six months ended June 30, 2004 and 2003 before the impact of changes in inventories, was 2,455 MBbls, 2,526 MBbls, 4,931 MBbls and 5,055 MBbls, respectively.

(b)	Production for Bolivia for the three months ended June 30, 2004 and 2003, and for the six months ended June 30, 2004 and 2003 before the impact of changes in inventories, was 22 MBbls, 21 MBbls, 43 MBbls and 41 MBbls.

(c)	Production for Yemen for the three months and six months ended June 30, 2004, before the impact of changes in inventories, was 108 MBbls and 109 MBbls.

(d)	Argentina production for the three months and six months ended June 30, 2004, is estimated to have been reduced as the result of a labor strike by 200 MBbls of oil and 165 MMcf of gas, or 228 MBOE, and 365 MBbls of oil and 300 MMcf of gas, or 415 MBOE, respectively.


	Three Months Ended June 30,				Six Months Ended June 30,
	2004		2003		2004		2003
Average Sales Price (including impact of hedges):
Oil (per Bbl) –
U.S.	$	27.12	$	24.47	$	27.53	$	25.49
Canada		28.80		25.64		28.30		28.56
Argentina		30.29		25.19		29.62		27.02
Bolivia		24.67		23.29		24.26		22.90
Yemen		29.15		–		29.15		–
Continuing operations		29.03		24.95		28.77		26.58
Ecuador		–		–		–		26.87
Total		29.03		24.95		28.77		26.58
Gas (per Mcf) –
U.S.	$	5.45	$	4.02	$	5.24	$	4.43
Canada		5.02		4.31		4.85		4.46
Argentina		0.66		0.46		0.58		0.44
Bolivia		1.54		2.17		1.62		2.04
Total		4.17		3.28		4.01		3.58
Average Sales Price (excluding impact of hedges):
Oil (per Bbl) –
U.S.	$	34.54	$	25.71	$	33.54	$	28.55
Canada		33.94		25.41		32.29		28.60
Argentina		30.29		25.19		29.62		27.02
Bolivia		24.67		23.29		24.26		22.90
Yemen		29.15		–		29.15		–
Continuing operations		31.96		25.38		31.14		27.67
Ecuador		–		–		–		26.87
Total		31.96		25.38		31.14		27.65
Gas (per Mcf) –
U.S.	$	5.52	$	4.68	$	5.28	$	5.23
Canada		5.02		4.76		4.85		5.08
Argentina		0.66		0.46		0.58		0.44
Bolivia		1.54		2.17		1.62		2.04
Total		4.20		3.69		4.03		4.11

In late July 2004, protestors seeking employment began an occupation of an oil loading facility in Argentina. A significant portion of our Argentine production is transported through this facility. As a result, we have shut-in a portion of our production. Although we are unable to predict the outcome, we anticipate a resolution in the near term and we do not expect this to have a material effect on our results of operations.

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 an eight percent increase in our average oil price, including the impact of hedging activities (13 percent increase excluding hedging activities), during the first six months of 2004 as compared to the same period of 2003. Our realized average oil price for the first six months of 2004 (before hedges) was approximately 85 percent of the NYMEX reference price compared to 88 percent for the same period of 2003. We experienced a 16 percent increase in our average oil price, including the impact of hedging activities (26 percent increase excluding hedging activities), during the second quarter of 2004 as compared to the same period of 2003. Our realized average oil price for the second quarter of 2004 (before hedges) was approximately 83 percent of the NYMEX reference price compared to 88 percent for the same period of 2003.

In the first six months of 2004, we exported approximately 40 percent of our Argentine oil production. Argentina oil exports are subject to an export tax. On May 11, 2004, the Argentina government raised this tax from 20 percent to 25 percent. This tax is applied on the sales value after the tax, thus, the net effect of the 20 and 25 percent rates is 16.7 and 20 percent, respectively. On August 6, 2004, the Argentine government further increased the export tax rates for oil exports. The export tax now escalates from the current 25 percent (a 20 percent effective rate) to a maximum rate of 45 percent (31 percent effective rate) of the realized value for exported barrels as West Texas Intermediate posted prices per barrel increase from less than $32.00 to $45.00 and above. The export tax is not deducted in the calculation of royalty payments and is limited by law to a maximum term through February 2007. We believe that this export tax has and will continue to have the effect of decreasing all future Argentine oil revenues (not only export revenues) by as much as the tax rate for the duration of the tax. The U.S. dollar equivalent value for domestic Argentine oil sales (paid in pesos) has generally moved toward parity with the U.S. dollar-denominated export values, net of the export tax. The adverse impact of this tax has been partially offset by the 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 2.9 MMBbls and 2.3 MMBbls in the six months 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 six months of 2004, including the impact of hedging activities, was 12 percent higher (two percent lower excluding hedging activities) than the same period of 2003. Our total average gas price for the second quarter of 2004, including the impact of hedging activities, was 27 percent higher (14 percent higher excluding hedging activities) than the same period of 2003.

We participated in gas hedges covering approximately 1.2 million MMBtu and 10.0 million MMBtu during the first six months of 2004, and 2003, respectively.

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 June 30, 2004, we have entered into oil price swap agreements for various periods of the remainder of 2004 and for 2005, 2006 and 2007 covering approximately 5.3 million barrels at a weighted average NYMEX reference price of $29.81 per barrel and gas price swap agreements for various periods of the remainder of 2004 covering approximately 2.5 million MMBtu at a weighted average NYMEX reference price of $5.96 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 following table reflects the volume of our oil under price swap arrangements and the corresponding weighted average NYMEX reference prices by quarter:


Quarter Ending	Barrels	NYMEX Reference Price Per Barrel

September 30, 2004	1,453,600	$30.44
December 31, 2004	1,264,500	30.20

March 31, 2005	449,700	29.14
June 30, 2005	470,200	28.39
September 30, 2005	484,500	27.94
December 31, 2005	490,700	27.67

March 31, 2006	126,000	33.24
June 30, 2006	127,400	32.67
September 30, 2006	128,800	32.14
December 31, 2006	128,800	31.68

March 31, 2007	126,000	31.42

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


Quarter Ending	MMBtu	NYMEX Reference Price Per MMBtu

September 30, 2004	1,840,000	$5.96
December 31, 2004	620,000	5.97

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 dispositions during the periods. On January 31, 2003, we completed the sale of our operations in Ecuador. We received $137.4 million in cash, and recorded a gain of approximately $47.3 million ($9.5 million after income taxes). 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.

Oil, condensate and NGL sales. Oil, condensate and NGL sales increased $6.0 million, three percent, to $243.7 million for the first six months of 2004 from $237.7 million for the first six months of 2003. An eight percent increase in our average oil price more than offset a five percent decrease in oil production for the first half of 2004 compared to the same period in 2003.

Oil, condensate and NGL sales increased $12.2 million, 11 percent, to $123.7 million for the second quarter of 2004 from $111.5 million for the second quarter of 2003. A 16 percent increase in our average oil price more than offset a five percent decrease in oil production for the second quarter of 2004 compared to the same period in 2003.

The decreases in oil production were primarily related to Canadian property divestitures in the second half of 2003 and a labor strike by contract oil field workers in Argentina impacting the end of the first quarter and the beginning of the second quarter of 2004. In addition, we estimate that the strike reduced our Argentine oil production during the first and second quarters of 2004 by approximately 165 MBbls and 200 MBbls, respectively, due to the temporary suspension of operations and shut-ins. Argentina net production rebounded after the temporary strike-related shut-in period early in the second quarter of 2004 to a level of 28,900 Bbls per day in June 2004. As a result of our successful exploration at our An Nagyah field in Yemen, oil production from our area of commercial development began making a contribution in the second quarter of 2004, rising to the targeted 2,500 gross (1,300 net) barrels per day late in the quarter.

Gas sales. Gas sales increased $8.5 million, eight percent, to $116.0 million for the first six months of 2004 from $107.5 million for the first six months of 2003. A 12 percent increase in our average gas price more than offset a four percent decrease in gas production for the first half of 2004 compared to the same period in 2003.

Gas sales increased $14.4 million, 30 percent, to $62.5 million for the second quarter of 2004 from $48.0 million for the second quarter of 2003. The increase resulted from a 27 percent increase in our average gas price, along with a two percent increase in gas production for the second quarter of 2004 compared to the same period in 2003.

The decrease in gas production for the first half of 2004 compared to the first half of 2003 was primarily related to the Canadian property divestitures in the second half of 2003 and the Argentina labor strike discussed above. In addition, we estimate that the strike reduced our Argentine gas production during the first and second quarters of 2004 by approximately 135 MMcf and 165 MMcf, respectively, due to the temporary suspension of operations and shut-ins. Argentina net production rebounded after the temporary strike related shut-in period early in the second quarter of 2004 to a level of 24.8 MMcf per day in June 2004.

Increased gas production in the U.S. and Bolivia more than offset the temporary production interruptions in Argentina in the second quarter of 2004 and also more than offset the gas production declines in Canada in the second quarter of 2004. This increased U.S. gas production is a result of exploration and exploitation successes. Our Bolivian gas production has increased to an average of 20 MMcf per day for the second quarter as a result of increased gas demand in Argentina.

Gas marketing revenues and expenses. Revenues and expenses for gas marketing decreased from the first half of 2003 to the first half of 2004 and from the second quarter of 2003 to the second quarter of 2004 primarily due to a reduction in third party volumes we market in the U.S. as a result of the sale of certain non-strategic assets. The decreases in volumes were partially offset by increases in gas prices. As a result of higher gas prices, gas marketing margins were higher in the first half of 2004 and second quarter of 2004 compared to the same periods in 2003.

Production costs. Production costs increased $13.4 million, 17 percent, to $90.0 million for the first six months of 2004 from $76.6 million for the first six months of 2003. On an equivalent barrel basis, production costs increased by 23 percent to $6.77 for the first six months of 2004 from $5.49 for the first six months of 2003. These increases are primarily due to costs incurred in the first quarter of 2004 to repair damage resulting from the October 2003 fires in California, increased workover activity, higher U.S. power costs and higher costs, expressed in U.S. dollars, in Argentina and Canada resulting from the strengthening of the Argentine peso and Canadian dollar.

Production costs increased $4.5 million, 11 percent, to $44.2 million for the second quarter of 2004 from $39.7 million for the second quarter of 2003. On an equivalent barrel basis, production costs increased by 14 percent to $6.55 for the second quarter of 2004 from $5.75 for the second quarter of 2003. These increases are primarily due to increased workover activity and higher U.S. power costs.

Production and ad valorem taxes. Production and ad valorem taxes increased $2.8 million, 31 percent, to $11.5 million for the first six months of 2004 from $8.8 million for the first six months of 2003. Production and ad valorem taxes increased $1.8 million, 45 percent, to $5.8 million for the second quarter of 2004 from $4.0 million for the second quarter of 2003. These increases are primarily the result of higher oil and gas prices and an increase in U.S. production on an equivalent barrel basis of two percent from the first half of 2003 to the first half of 2004 and four percent from the second quarter of 2003 to the second quarter of 2004.

Export taxes. Export taxes in Argentina decreased $5.5 million, 30 percent, to $12.9 million for the first six months of 2004 from $18.4 million for the first six months of 2003. Export taxes decreased $1.5 million, 18 percent, to $6.7 million for the second quarter of 2004 from $8.2 million for the second quarter of 2003. These decreases were primarily a result of a shift in sales volumes from the export market to the domestic market in 2004 compared to the same periods in 2003. The decreases were slightly offset by the increase in the export tax rate from 20 percent to 25 percent on May 11, 2004.

Exploration costs. Exploration costs decreased $32.6 million, 70 percent, to $13.9 million for the first six months of 2004 from $46.5 million for the first six months of 2003. Exploration costs for the first six months of 2004 consisted of $3.7 million for seismic and other geological and geophysical costs, $5.7 million for unsuccessful exploratory drilling and $4.5 million for impairments of unproved leasehold. During the first six months of 2003, our exploration costs included $5.1 million for seismic and other geological and geophysical costs, $10.2 million for unsuccessful exploratory drilling and $31.2 million for impairments of unproved leaseholds. The leasehold impairments in the first half of 2003 include $23.7 million ($13.9 million net of taxes) related to the Company’s Northwest Territories project in Canada.

Exploration costs decreased $22.9 million, 70 percent, to $9.6 million for the second quarter of 2004 from $32.5 million for the second quarter of 2003. Exploration costs for the second quarter of 2004 consisted of $2.0 million for seismic and other geological and geophysical costs, $4.5 million for unsuccessful exploratory drilling, primarily in Italy, and $3.1 million for impairments of unproved leasehold. During the second quarter of 2003, our exploration costs included $2.9 million for seismic and other geological and geophysical costs, $0.6 million for unsuccessful exploratory drilling and $29.0 million for impairments of unproved leaseholds, including the impairment of the Canadian properties discussed above.

General and administrative expenses. General and administrative expenses increased $6.1 million, 22 percent, to $34.0 million for the first six months of 2004 from $27.8 million for the first six months of 2003. In the first half of 2004, we recorded expenses related to employee bonuses and severance benefits for a former executive. There was no corresponding amount in the first half of 2003. We also accrued higher estimated employee bonuses in the first six months of 2004 than in the same period in 2003.

General and administrative expenses increased $2.7 million, 19 percent, to $17.1 million for the second quarter of 2004 from $14.4 million for the second quarter of 2003 primarily due to the accrual of higher estimated employee bonuses in the second quarter of 2004 compared to the same period in 2003.

Stock compensation. Stock compensation increased $3.5 million, 144 percent, to $5.9 million in the first six months of 2004 from $2.4 million in the first six months of 2003. In March 2004, we entered into a separation agreement with a former executive under which we extended the period in which he may exercise his outstanding vested stock options to the end of the term of the options. Under the terms of the restricted stock award agreements with the former executive, all of the restricted shares granted to him under these agreements became fully vested as of his termination date. As a result of these events, we recorded additional non-cash stock compensation expense of approximately $1.8 million in the first six months of 2004. In June 2004, we recorded stock compensation expense of $1.1 million related to the vesting of certain performance-based restricted stock grants. There were no comparable charges in the first six months of 2003.

Stock compensation increased $0.7 million, 47 percent, to $2.2 million for the second quarter of 2004 from $1.5 million for the second quarter of 2003 primarily due to the expense associated with the performance-based restricted stock grants discussed above.

Depreciation, depletion and amortization. Depreciation, depletion and amortization decreased $10.3 million, 14 percent, to $61.8 million for the first six months of 2004 from $72.1 million for the first six months of 2003. Our average oil and gas amortization rate per equivalent barrel produced decreased to $4.52 for the first six months of 2004 from $5.01 for the first six months 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 two percent decrease in our worldwide production on an equivalent barrel basis, resulted in the lower depreciation, depletion and amortization expense.

Depreciation, depletion and amortization decreased $5.2 million, 15 percent, to $29.6 million for the second quarter of 2004 from $34.8 million for the second quarter of 2003. Our average oil and gas amortization rate per equivalent barrel produced decreased to $4.26 for the second quarter of 2004 from $4.80 for the second quarter of 2003. Both of these decreases primarily relate to the Canadian book basis reductions and reserve revisions discussed above. The decrease in total depreciation, depletion, and amortization expense also relates to a two percent decrease in our worldwide production on an equivalent barrel basis.

Impairment of proved oil and gas properties. In the first half 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 early 2004. We recorded an impairment of $12.6 million in the second quarter of 2003 related to certain producing oil and gas properties in Canada. These impairments were caused by negative reserve revisions as a result of unsuccessful workover operations and additional technical evaluation of other non-producing projects. We had no impairments of proved oil and gas properties in the second quarter of 2004.

Other operating costs. We reported $3.7 million of net other operating income for the first six months of 2004 compared to net other operating expenses of $1.6 million for the first six months 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. Interest expense decreased $9.9 million, 27 percent, to $26.7 million for the first six months of 2004 from $36.6 million for the first six months of 2003 due to a 14 percent reduction in our average debt outstanding and a 12 percent decrease in our average interest rate from the first six months of 2003 to the first six months of 2004. Interest expense decreased $5.3 million, 30 percent, to $12.7 million for the second quarter of 2004 from $18.0 million for the second quarter of 2003 due to a 12 percent reduction in our average debt outstanding and an 18 percent decrease in our average interest rate from the second quarter of 2003 to the second 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

Loss on early extinguishment of debt. In connection with the redemptions of our senior subordinated notes discussed above, we were required to pay call premiums on the notes and 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 six months of 2004 and $1.4 million, $0.9 million after tax, in the first six months of 2003.

Foreign currency exchange (gain) loss. We recorded foreign currency exchange gains of $0.8 million in the first six months of 2004 and foreign currency exchange losses of $7.2 million in the first six months of 2003. These gains and losses are primarily related to our operations in Argentina. During the first six months of 2004, the Argentine peso was relatively unchanged against the U.S. dollar, with an exchange rate of 2.97 pesos to one U.S. dollar at June 30, 2004, compared to a rate of 2.94 pesos to one U.S. dollar at December 31, 2003. The Argentine peso strengthened significantly against the U.S. dollar in the first six months of 2003, with an exchange rate of 2.82 pesos to one U.S. dollar at June 30, 2003, compared to a rate of 3.38 pesos to one U.S. dollar at December 31, 2002. Foreign currency exchange gains and losses in other countries were not significant in either period.

We recorded foreign currency exchange gains of $2.0 million in the second quarter of 2004 and foreign currency exchange losses of $3.5 million in the second quarter of 2003. During the second quarter of 2004, the Argentine peso weakened against the U.S. dollar, with an exchange rate of 2.96 pesos to one U.S. dollar at June 30, 2004, compared to a rate of 2.86 pesos to one U.S. dollar at March 31, 2004. The Argentine peso strengthened against the U.S. dollar in the second quarter of 2003, with an exchange rate of 2.82 pesos to one U.S. dollar at June 30, 2003, compared to a rate of 2.97 pesos to one U.S. dollar at March 31, 2003. Foreign currency exchange gains and losses in countries other than Argentina were not significant in either period.

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

Cash Flows

Our primary sources of cash during the first six months 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 $20.6 million. See below for additional discussion of our cash flows from operating activities.


	Six Months Ended June 30,						Change
	2004			2003			Change
Cash provided (used) by (in thousands):
Operating activities – continuing operations	$	142,206		$	115,044		$	27,162
Operating activities – discontinued operations		–			(20,929	)		20,929
Investing activities – continuing operations		(108,581	)		79,052			(187,633	)
Investing activities – discontinued operations		–			10,309			(10,309	)
Financing activities		(13,163	)		(88,589	)		75,426

Cash provided by continuing operations increased 24 percent to $142.2 million in the first half of 2004 compared to $115.0 million in the first half of 2003. Declines in production from continuing operations for the first six months of 2004 compared to the same period in 2003 were more than offset by increases in oil and gas prices. Higher revenues and lower export taxes were offset by higher production costs and general and administrative expenses. Cash used by changes in working capital decreased by 49 percent for the first six months of 2004 compared to the first six months of 2003. See “Results of Operations” and “Period to Period Comparison” for further discussion.

Investing activities in the first half of 2004 include capital spending of $107.7 million on a cash basis, or 76 percent of cash provided by operating activities. This compares to capital spending in the first six months of 2003 of $75.8 million, or 81 percent of cash provided by operating activities. Cash provided by investing activities in the first six months of 2003 includes $157.6 million for proceeds from the sales of our operations in Ecuador and certain properties in the U.S.

Cash used by financing activities in the first half 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 six months of 2004, our total capital expenditures were $116.9 million. In North America, our capital expenditures totaled $63.2 million, including $1.7 million for acquisitions. Exploitation activities accounted for $40.3 million of the North America capital expenditures with exploration activities contributing $21.2 million. Our capital expenditures outside North America totaled $53.7 million. This amount consists of exploitation activities of $42.5 million in Argentina and exploration activities of $11.2 million, primarily in Yemen and Italy.

As of June 30, 2004, we had unproved oil and gas property costs of approximately $63.7 million, consisting of undeveloped leasehold costs of $40.2 million, including $26.2 million in Canada, and unevaluated exploratory drilling costs of $23.5 million. Approximately $13.0 million of the total unproved costs are associated with our drilling program in Yemen. Future exploration expense and earnings may be impacted to the extent our future exploration activities are unsuccessful in discovering commercial oil and gas reserves in sufficient quantities to recover our costs.

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

In June 2004, we signed an agreement to acquire 100 percent of an Argentine company whose principal asset is an operated producing concession which covers approximately 54,000 acres in the north flank of the San Jorge basin of Argentina. We will pay $36.4 million in cash, net of working capital and subject to adjustments, with funds provided by cash on hand. The transaction is anticipated to close in August 2004. We estimate that the current net production attributable to the producing Bella Vista Oeste concession is 1,900 barrels of oil and natural gas liquids per day from approximately 50 active producing wells. We believe that the properties contain significant workover, drilling and waterflood potential which we plan to pursue along with the implementation of operational efficiencies.

In Yemen, we have received approval from the government to expand our planned drilling activity. As a result of our drilling success to date, we plan to increase its capital spending for drilling. The added capital will be spent principally to accelerate the drilling program at our An Nagyah field to raise productive capacity of the field toward the 10,000 barrel of oil per day capacity of the central processing facility, which is targeted for completion early in the second quarter 2005. In addition, we plan to drill two exploratory wells, at least one of which, the Al Hareth, will target the Alif formation in a new prospect area within our area of development

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.

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 the first half of 2004, we redeemed the entire $150 million principal balance of our 9³/4% 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 half 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 senior secured credit facility maturing in May 2008 with availability governed by a borrowing base determination. Our availability under the revolving credit facility is reduced by our outstanding letters of credit. The borrowing base (currently $325 million) is based on the banks’ evaluation of our oil and gas reserves. The amount available to be borrowed under the revolving credit facility is limited to the lesser of the borrowing base or the facility size, which is currently set at $300 million. The next borrowing base redetermination will be in November 2004 and we do not expect a significant change in the borrowing base. As of June 30, 2004, we have unused availability under our revolving credit facility of $150 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 half 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 half 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. In addition, after a review of our Canadian oil and gas reserves and the strategic alternatives available, we are considering the sale of these assets. Our proved reserves in Canada at December 31, 2003, were approximately three percent of our total proved reserves. Our debt, less cash on hand, at June 30, 2004, was $623.6 million, compared to approximately $1.0 billion at December 31, 2001.

Contractual Obligations

Our contractual obligations have not changed significantly since December 31, 2003, except 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 9³/4% senior subordinated notes due 2009. The revolving credit facility matures in May 2008.

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 half of 2004, the Argentine inflation rate was 3.3 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 $26.2 million and $30.8 million for the first half 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:


	Six Months Ended June 30,
	2004		2003
U.S. federal statutory income tax rate	35.0	%	35.0	%
U.S. state income tax (net of federal tax benefit)	0.4		1.6
U.S. permanent differences	1.0		0.9
Foreign operations	(1.1	)	13.2

	35.3	%	50.7	%

Critical Accounting Policies and Estimates

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

Foreign Operations

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

Forward-Looking Statements

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

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

•

amounts and nature of future capital expenditures;

•

oil and gas prices and demand;

•

operating costs;

•

estimates of proved oil and gas reserves;

•

business strategy;

•

production of oil and gas reserves;

•

expansion and growth of our business and operations; and

•

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

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

•

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

•

oil and gas prices;

•

exploitation and exploration successes;

•

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

•

continued availability of capital and financing;

•

general economic, market or business conditions;

•

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

•

changes in laws or regulations; and

•

other factors, most of which are beyond our control.

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

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

Commodity Price Risk

We produce, purchase and sell crude oil, natural gas, condensate, natural gas liquids and sulfur. As a result, our financial results can be significantly impacted as these commodity prices fluctuate widely in response to changing market forces. Relatively modest changes in either oil or gas prices significantly impact our results of operations and cash flows. However, the impact of changes in the market prices for oil and gas on our average realized prices may be reduced from time to time based on the level of our hedging activities. Based on oil production from continuing operations for the first six months of 2004, a change in the average oil price we realize, before hedges, of $1.00 per Bbl would result in a change in net income and revenues less production and export taxes on an annual basis of approximately $10.4 million and $15.8 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 $4.2 million and $5.7 million, respectively, based on gas production for the first six 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 June 30, 2004, we have entered into oil price swap agreements for various periods of the remainder of 2004 and for 2005, 2006 and 2007 covering approximately 5.3 million barrels at a weighted average NYMEX reference price of $29.81 per barrel. We have also entered into gas price swap agreements for various periods of the remainder of 2004 covering approximately 2.5 million MMBtu a weighted average NYMEX reference price of $5.96 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 June 30, 2004, we would have paid approximately $30.3 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 June 30, 2004, 79 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 June 30, 2004, a change in the average interest rate of 100 basis points would have impacted our net income and cash flow by $0.9 million and $1.5 million, respectively.

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

Long-Term Debt:

2004

2005

2006

2007

2008

There-
after

Total

Fair Value
at 6/30/04

Fixed rate (in thousands)

–

549,946

576,000

Average interest rate

–

8.1%

Variable rate (in thousands)

–

149,100

–

149,100

Average interest rate

–

)

–

)

(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 June 30, 2004, was 1.5 percent.

Foreign Currency and Operations Risk

International investments represent, and are expected to continue to represent, a significant portion of our total assets. We currently have international operations in Canada, Argentina, Bolivia, Yemen, Italy and Bulgaria. For the first six months of 2004, our operations in Argentina and Canada accounted for approximately 36 percent and 13 percent, respectively, of our revenues and 38 percent and 12 percent, respectively, of our total assets. During the first half 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, other than the pending Argentina acquisition discussed in “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Capital Expenditures.” 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.

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 June 30, 2004, was US$1:C$1.33 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 June 30, 2004, was 2.97 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 June 30, 2004, were as follows (in thousands):


	Peso Balance		U.S. Dollar Equivalent
Current assets	12,703		$	4,283
Current liabilities	(89,575	)		(30,200	)
Non-current liabilities	(43,168	)		(14,554	)

Net monetary liabilities	(120,040	)	$	(40,471	)

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

During 2003, we exported approximately 60 percent of our Argentine oil production and in the first six months of 2004, we exported approximately 40 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.

After a year of negotiations, on January 24, 2003, the International Monetary Fund (the “IMF”) executed a transitional $6.8 billion, eight-month stand-by credit arrangement to provide financial stability through the presidential elections. After a successful transition of government, and as a result of restoring a measure of economic stability and growth during 2002, in September 2003, the IMF approved a $13.5 billion stand-by credit arrangement, to be disbursed in stages over a three-year period, to succeed the transitional arrangement that expired on August 31, 2003. The economic program to which the Argentine government and the IMF agreed is based on a fiscal framework to meet growth, employment, and social objectives, while providing a basis for normalizing relations with creditors and ensuring debt sustainability, a strategy to assure strengthening of the banking system and facilitating an increase in bank lending, and further institutional and tax reforms to facilitate corporate debt restructuring and fundamentally improving the investment climate. On January 28, 2004, the IMF completed and approved its first review of Argentina’s performance under the three-year program. On March 22, 2004, the second review and disbursement of the next $3.1 billion tranche was approved. A third review is currently underway and if the tranche is approved, the IMF and World Bank would disburse $500 million to the Argentine government.

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. The agreement has not been extended past April 2004.

We sold approximately 1.4 MMBbls of our net Argentine oil production (approximately 14 percent) under this agreement during 2003. During the first six months of 2004 we sold approximately 560 MBbls of additional net oil production (approximately 11 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. On July 18, 2004, voters approved a public referendum on several proposed changes in Bolivia’s Hydrocarbon Law, including the export of Bolivian gas. As a result of the referendum, on July 30, 2004, President Mesa presented his proposed Hydrocarbons Law reform bill to the Bolivian congress for consideration. When congressional debate concludes, we expect the Hydrocarbons Law to be reformed to allow increased state control over hydrocarbons commercialization and to enact a new taxation regime.

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

In 1987, the Boliviano replaced the peso and became Bolivia’s legal currency. The exchange rate is set daily by the government’s exchange house, “The Bolsin”, which is under the supervision of the Bolivian Central Bank. Foreign exchange transactions are not subject to any controls. The exchange rate at June 30, 2004, was 7.94 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 in excess of our contracted volumes. The current daily productive capacity of our properties in Bolivia is approximately 50 MMcf, gross and 31 MMcf, net of gas. During the past several years, Bolivian gas reserve growth has exceeded the demand growth in Bolivia’s existing markets. Therefore, we believe substantial competition for gas markets will continue at least until new market areas are established. On April 21, 2004, the Argentine and Bolivian governments agreed to a gas supply arrangement for 141 MMcf per day of gas to Argentina for a six-month period beginning in May 2004 and in July 2004, the government signed a letter of intent to increase those exports by 88.3 MMcf per day. With approval from the Bolivian public in the referendum on the matter of gas exports, we believe that new projects, such as exports to Mexico and the U.S., as well as additional exports to Argentina, will become feasible in the future.

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

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

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 June 30, 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 period covered by this Form 10-Q, there were no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II

OTHER INFORMATION

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 June 30, 2004, of equity securities that are registered by us pursuant to Section 12 of the Securities Exchange Act of 1934, as amended.

ISSUER PURCHASES OF EQUITY SECURITIES


Period	(a) Total Number of Shares Purchased (1)	(b) Average Price Paid per Share (2)		(c) Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	(d) Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plans or Programs
April 1, 2004 – April 30, 2004	–	$	–	–	–
May 1, 2004 – May 31, 2004	5,438		14.48	–	–
June 1, 2004 – June 30, 2004	–		–	–	–

Total	5,438	$	14.48	–	–

(1)

In connection with the maturity of certain indebtedness to us, an officer transferred 5,438 shares of common stock owned by him securing this indebtedness to us in full satisfaction of this indebtedness.

(2)

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

Item 3.

Defaults Upon Senior Securities

Not applicable

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

Our Annual Meeting of Stockholders (the “Annual Meeting”) was held on May 11, 2004, in Tulsa, Oklahoma. At the Annual Meeting, stockholders elected William L. Abernathy, Brian H. Lawrence and Gerald J. Maier as Class II Directors. The stockholders also considered and approved the appointment of Ernst & Young LLP as our independent auditors for the fiscal year ending December 31, 2004.

There were present at the Annual Meeting, in person or by proxy, stockholders holding 53,070,261 shares of our Common Stock, or 82 percent of the total stock outstanding and entitled to vote at the Annual Meeting. The table below describes the results of voting at the Annual Meeting.


	Votes For	Votes Against or Withheld	Abstentions	Broker Non- Votes
1. Election of Directors:

William L. Abernathy	37,765,916	15,304,345	–0–	–0–
Bryan H. Lawrence	31,039,373	22,030,888	–0–	–0–
Gerald J. Maier	34,476,298	18,593,963	–0–	–0–

2. Ratification of Appointment of Ernst & Young LLP as our Independent Auditors for Fiscal 2004	32,517,417	20,516,396	36,448	–0–

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 or furnished herewith.

10.1

Third Amendment to Credit Agreement dated as of May 12, 2003, among us, as Borrower, the Lenders party thereto, Bank of Montreal, as administrative agent, Deutsche Bank Trust Company, as syndication agent, and Fleet National Bank, Societe Generale and The Bank of New York, as co-documentation agents.

10.2

Form of Restricted Stock Rights Award Agreement for executive officers under the Vintage Petroleum, Inc. 1990 Stock Plan.

10.3

Form of Restricted Stock Award Agreement under the Vintage Petroleum, Inc. 1990 Stock Plan.

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.

b)	Reports on Form 8-K

None.

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: August 6, 2004

\s\ Michael F. Meimerstorf

Michael F. Meimerstorf

Vice President and Controller

(Principal Accounting Officer)

Exhibit Index


Exhibit Number		Description

10.1		Third Amendment to Credit Agreement dated as of May 12, 2003, among us, as Borrower, the Lenders party thereto, Bank of Montreal, as administrative agent, Deutsche Bank Trust Company, as syndication agent, and Fleet National Bank, Societe Generale and The Bank of New York, as co-documentation agents.

10.2		Form of Restricted Stock Rights Award Agreement for executive officers under the Vintage Petroleum, Inc. 1990 Stock Plan.

10.3		Form of Restricted Stock Award Agreement under the Vintage Petroleum, Inc. 1990 Stock Plan.

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.