Edgar Filing: VINTAGE PETROLEUM INC

Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended March 31, 2005

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

For the transition period from to

Commission file number 1-10578

VINTAGE PETROLEUM, INC.

(Exact name of registrant as specified in charter)


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

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

(918) 592-0101

(Registrant’s telephone number, including area code)

NOT APPLICABLE

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

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

Yes x No ¨

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

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


Class		Outstanding at April 29, 2005
Common Stock, $0.005 Par Value		66,786,091

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VINTAGE PETROLEUM, INC.

FORM 10-Q

THREE MONTHS ENDED MARCH 31, 2005

TABLE OF CONTENTS


		Page
PART I.	FINANCIAL INFORMATION

Item 1.	Financial Statements - Unaudited

	Consolidated Balance Sheets as of March 31, 2005, and December 31, 2004	4

	Consolidated Statements of Operations for the Three Months Ended March 31, 2005 and 2004	6

	Consolidated Statement of Changes in Stockholders’ Equity and Comprehensive Income for the Three Months Ended March 31, 2005	8

	Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2005 and 2004	9

	Notes to Unaudited Consolidated Financial Statements	10

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	24

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	39

Item 4.	Controls and Procedures	48

PART II.	OTHER INFORMATION

Item 1.	Legal Proceedings	50

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	50

Item 3.	Defaults Upon Senior Securities	50

Item 4.	Submission of Matters to a Vote of Security Holders	50

Item 5.	Other Information	50

Item 6.	Exhibits	50

	Signatures	51

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PART I

FINANCIAL INFORMATION

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ITEM 1. FINANCIAL STATEMENTS

VINTAGE PETROLEUM, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In thousands, except shares

and per share amounts)

(Unaudited)

ASSETS


	March 31, 2005		December 31, 2004
CURRENT ASSETS:
Cash and cash equivalents	$	163,808	$	124,221
Accounts receivable -
Oil and gas sales		110,311		107,870
Joint operations		8,980		12,479
Income taxes receivable		41,203		31,571
Deferred income taxes		27,077		15,364
Prepaids and other current assets		16,494		23,648

Total current assets		367,873		315,153

PROPERTY, PLANT AND EQUIPMENT, at cost:
Oil and gas properties, successful efforts method		2,217,325		2,163,176
Oil and gas gathering systems and plants		23,926		23,926
Other		32,441		31,932

		2,273,692		2,219,034
Less accumulated depreciation, depletion and amortization		975,072		942,656

Total property, plant and equipment, net		1,298,620		1,276,378

DEFERRED INCOME TAXES		12,118		13,200

OTHER ASSETS, net		42,493		40,161

TOTAL ASSETS	$	1,721,104	$	1,644,892

See notes to unaudited consolidated financial statements.

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VINTAGE PETROLEUM, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Continued)

(In thousands, except shares

and per share amounts)

(Unaudited)

LIABILITIES AND STOCKHOLDERS’ EQUITY


	March 31, 2005			December 31, 2004
CURRENT LIABILITIES:
Revenue payable	$	21,570		$	33,740
Accounts payable - trade		53,367			50,775
Current income taxes payable		28,552			23,565
Derivative financial instruments payable		96,311			27,672
Other payables and accrued liabilities		81,071			73,748

Total current liabilities		280,871			209,500

LONG-TERM DEBT		549,950			549,949

DEFERRED INCOME TAXES		69,266			80,383

LONG-TERM LIABILITY FOR ASSET RETIREMENT OBLIGATIONS		90,445			90,707

OTHER LONG-TERM LIABILITIES		40,402			30,675

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, 67,244,034 and 66,541,984 shares issued and 66,713,802 and 66,012,252 shares outstanding, respectively		336			333
Capital in excess of par value		376,465			361,120
Retained earnings		371,306			342,707
Accumulated other comprehensive loss		(46,733	)		(13,088	)

		701,374			691,072
Less treasury stock, at cost, 530,232 and 529,732 shares, respectively		4,319			4,319
Less unamortized cost of non-vested stock awards		6,885			3,075

Total stockholders’ equity		690,170			683,678

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	1,721,104		$	1,644,892

See notes to unaudited consolidated financial statements.

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VINTAGE PETROLEUM, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share amounts)

(Unaudited)


	Three Months Ended March 31,
	2005			2004
REVENUES:
Oil, condensate and NGL sales	$	165,557		$	113,431
Gas sales		49,886			35,068
Sulfur sales		738			473
Gas marketing		18,578			14,772

Total revenues		234,759			163,744

COSTS AND EXPENSES:
Production costs		43,670			35,827
Transportation and storage costs		3,918			1,852
Production and ad valorem taxes		6,884			5,306
Export taxes		13,336			6,206
Exploration costs		10,326			1,236
Gas marketing		17,542			14,071
General and administrative		15,844			14,303
Stock compensation		1,506			3,762
Depreciation, depletion and amortization		33,397			24,086
Impairment of proved oil and gas properties		—			3,915
Accretion		1,747			1,618
Other operating (income) expense		1,017			(4,817	)

Total costs and expenses		149,187			107,365

OPERATING INCOME		85,572			56,379

NON-OPERATING (INCOME) EXPENSE:
Interest expense		11,555			14,021
Loss on early extinguishment of debt		—			9,903
Derivative losses		40,716			4
Gain on disposition of assets		—			(59	)
Foreign currency exchange loss		1,266			1,143
Other non-operating income		(431	)		(11	)

Net non-operating expense		53,106			25,001

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		32,466			31,378

INCOME TAX PROVISION (BENEFIT):
Current		14,404			12,144
Deferred		(3,120	)		873

Total income tax provision		11,284			13,017

INCOME FROM CONTINUING OPERATIONS		21,182			18,361

INCOME FROM DISCONTINUED OPERATIONS, net of income taxes		10,743			774

NET INCOME	$	31,925		$	19,135

See notes to unaudited consolidated financial statements.

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VINTAGE PETROLEUM, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Continued)

(In thousands, except per share amounts)

(Unaudited)


	Three Months Ended March 31,
	2005		2004
BASIC INCOME PER SHARE:
Income from continuing operations	$	0.32	$	0.29
Income from discontinued operations		0.16		0.01

Net income	$	0.48	$	0.30

DILUTED INCOME PER SHARE:
Income from continuing operations	$	0.32	$	0.28
Income from discontinued operations		0.16		0.01

Net income	$	0.48	$	0.29

Weighted average common shares outstanding:
Basic		66,139		64,328

Diluted		66,888		65,030

See notes to unaudited consolidated financial statements.

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VINTAGE PETROLEUM, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY

AND COMPREHENSIVE INCOME (LOSS)

FOR THE THREE MONTHS ENDED MARCH 31, 2005

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

(Unaudited)


	Common Stock			Treasury Stock			Capital In Excess of Par Value			Unamortized Non-Vested Stock Awards			Retained Earnings			Accumulated Other Comprehensive Loss			Total
	Shares	Amount		Treasury Stock			Capital In Excess of Par Value			Unamortized Non-Vested Stock Awards			Retained Earnings			Accumulated Other Comprehensive Loss			Total
BALANCE AT DECEMBER 31, 2004	66,542	$	333	$	(4,319	)	$	361,120		$	(3,075	)	$	342,707		$	(13,088	)	$	683,678
Comprehensive income (loss):
Net income	—		—		—			—			—			31,925			—			31,925
Change in value of derivative financial instruments, net of tax	—		—		—			—			—			—			(33,645	)		(33,645	)

Total comprehensive loss																				(1,720	)
Issuance of stock options	—		—		—			2			—			—			—			2
Exercise of stock options and tax effects	536		2		—			9,043			—			—			—			9,045
Issuance of non-vested stock	154		1		—			4,660			(4,661	)		—			—			—
Amortization of non-vested stock awards and tax effects	—		—		—			1,648			846			—			—			2,494
Forfeitures of non-vested stock (500 shares)	—		—		—			(8	)		5			—			—			(3	)
Vesting of stock rights	12		—		—			—			—			—			—			—
Cash dividends declared ($0.05 per share)	—		—		—			—			—			(3,326	)		—			(3,326	)

BALANCE AT MARCH 31, 2005	67,244	$	336	$	(4,319	)	$	376,465		$	(6,885	)	$	371,306		$	(46,733	)	$	690,170

See notes to unaudited consolidated financial statements.

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VINTAGE PETROLEUM, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands, except per share amounts)

(Unaudited)


	Three Months Ended March 31,
	2005			2004
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	31,925		$	19,135
Adjustments to reconcile net income to cash provided by operating activities -
Income from discontinued operations, net of tax		(10,743	)		(774	)
Depreciation, depletion and amortization		33,397			24,086
Impairment of proved oil and gas properties		—			3,915
Accretion		1,747			1,618
Dry hole costs, impairments of unproved oil and gas properties and other		8,266			36
Provision (benefit) for deferred income taxes		(3,120	)		873
Foreign currency exchange loss		1,266			1,143
Gain on dispositions of assets		—			(59	)
Loss on early extinguishment of debt		—			9,903
Stock compensation		1,506			3,762
Non-cash derivative losses		40,716			4
Other non-cash items included in net income		305			372
(Increase) decrease in receivables		1,029			(2,536	)
Increase (decrease) in payables and accrued liabilities		(4,976	)		18,512
Other working capital changes		1,675			(5,553	)

Cash provided by continuing operations		102,993			74,437
Cash provided by discontinued operations		—			10,013

Cash provided by operating activities		102,993			84,450

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures
Oil and gas properties		(59,752	)		(44,649	)
Gathering systems and other		(509	)		(674	)
Payments on non-hedge derivative transactions		(4,349	)		—
Other		—			(1,578	)

Cash used by investing activities - continuing operations		(64,610	)		(46,901	)
Cash used by investing activities - discontinued operations		—			(7,379	)

Cash used by investing activities		(64,610	)		(54,280	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Issuance of common stock		5,739			2,446
Purchase of treasury stock		—			(50	)
Redemption of 9 3/4% Senior Subordinated Notes Due 2009		—			(157,313	)
Advances on revolving credit facility and other borrowings		29,200			201,900
Payments on revolving credit facility and other borrowings		(29,200	)		(64,000	)
Dividends paid ($0.05 and $0.045 per share, respectively)		(3,300	)		(2,893	)
Other		(1,061	)		3,385

Cash provided (used) by financing activities		1,378			(16,525	)

EFFECT OF EXCHANGE RATE CHANGES ON CASH		(174	)		(186	)

NET INCREASE IN CASH AND CASH EQUIVALENTS		39,587			13,459
CASH AND CASH EQUIVALENTS, beginning of period		124,221			32,264

CASH AND CASH EQUIVALENTS, end of period	$	163,808		$	45,723

See notes to unaudited consolidated financial statements.

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VINTAGE PETROLEUM, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2005 and 2004

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 interest in a joint venture engaged in exploration and production activities (collectively, the “Company”). All significant intercompany accounts and transactions have been eliminated in consolidation. Management believes that all material adjustments (consisting of only normal recurring adjustments) necessary for a fair presentation have been made. Certain 2004 amounts have been reclassified to conform with the 2005 presentation, including reclassifications required for presentation of the discontinued operations discussed in Note 8. These reclassifications had no effect on the Company’s net income or stockholders’ equity.

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, the 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 2004 audited financial statements and related notes included in the Company’s 2004 Annual Report on Form 10-K, Item 8. Financial Statements and Supplementary Data.

2.	SIGNIFICANT ACCOUNTING POLICIES

Oil and Gas Properties and Unproved Property Impairments

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 incurred in exploration activities, are expensed as incurred. The Company recognizes gains or losses on the sale of properties on a field basis.

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Unproved leasehold costs are capitalized and reviewed periodically for impairment. Individual unproved properties whose acquisition costs are significant are assessed for impairment 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 unproved oil and gas property impairments of $1.4 million and $36,000 for the three months ended March 31, 2005 and 2004, respectively, excluding the Company’s discontinued operations (see Note 8). Additional impairment expense could result if oil and gas prices decline in the future or if downward reserve revisions are recorded on nearby properties, as it may not be economic to develop some of these unproved properties. Leasehold impairments related to the Company’s discontinued Canadian operations were $1.3 million for the three months ended March 31, 2004.

As of March 31, 2005, the Company had total unproved oil and gas property costs of approximately $29.9 million, consisting of undeveloped leasehold costs of $16.2 million and unevaluated exploratory drilling costs of $13.7 million. Approximately $13.7 million of the total unevaluated costs are associated with the Company’s exploratory drilling program in Yemen and the remaining $16.2 million of unevaluated costs are associated with the Company’s exploration activities in the U.S.

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.

Exploration Drilling Costs

Costs of drilling exploratory wells are capitalized as part of the Company’s unproved costs pending management’s determination of whether the wells have found proved reserves. Management makes this determination as soon as possible after completion of drilling considering the guidance provided in Statement of Financial Accounting Standards No. 19, Financial Accounting and Reporting by Oil and Gas Producing Companies (“SFAS 19”). SFAS 19 provides that such costs should not be carried as an asset for more than one year following completion of drilling unless the well has found oil and gas reserves in an area requiring a major capital expenditure before production could begin. In that case, the costs of such exploration well continue to be carried as an asset pending determination of whether proved reserves have been found only as long as the well has found a sufficient quantity of reserves to justify its completion as a producing well if the required capital expenditure is made and drilling of the additional exploratory wells is under way or firmly planned for the near future. If both those conditions are not met, the well costs are charged to expense. Management performs this evaluation on a quarterly basis.

As of March 31, 2005, the Company had the following exploration wells capitalized and reported as unevaluated costs (in thousands):


Wells in progress	$	1,458
Drilling completed - less than one year		5,601
Drilling completed - over one year		6,606

Total exploration drilling costs	$	13,665

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As of March 31, 2005, the Company had one exploration well in Yemen on which the drilling was completed for more than one year with a total cost of approximately $6.6 million. Management believes that this well has found sufficient reserves to justify its completion and such well requires a major capital expenditure before production can begin. During 2004, the Company drilled another well in this area as part of the development with plans to continue development and evaluation of this area during 2005. Depending on the results of such activity, the costs capitalized for the completed wells may be charged to expense during 2005. The Company had no exploration wells capitalized in areas requiring a major capital expenditure before production could begin where additional drilling efforts are not underway or firmly planned and had no exploration wells capitalized in areas not requiring a major capital expenditure where more than one year has elapsed since completion of drilling.

On April 4, 2005, the Financial Accounting Standards Board (“FASB”) issued FASB Staff Position No 19-1, Accounting for Suspended Well Costs (“FSP 19-1”). FSP 19-1 amends SFAS 19 to provide that in those situations where exploration drilling has been completed and oil and gas reserves have been found, but such reserves cannot be classified as proved when drilling is complete, the drilling costs may be capitalized if the well has found a sufficient quantity of reserves to justify its completion as a producing well and the enterprise is making sufficient progress assessing the reserves and the economic and operating viability of the project. If either of the criteria is not met, the well is assumed to be impaired and the costs charged to expense. Any well which has not found reserves is charged to expense. FSP 19-1 is effective for the first reporting period beginning after April 4, 2005, which will be the three months ended September 30, 2005, for the Company. Management believes that no adjustment would have been required as of the beginning of and for the three months ended March 31, 2005 and 2004, from the application of FSP 19-1.

For the three months ended March 31, 2005, the changes in unevaluated capitalized exploratory drilling costs were as follows (in thousands):


Balance, beginning of period	$	11,137
Additions		5,133
Expensed		(2,605	)

Balance, end of period	$	13,665

Impairments of Proved Oil and Gas Properties

The Company reviews its proved oil and gas properties for impairment on a field basis. For each field, an impairment provision is recorded whenever events or circumstances indicate that the carrying value of those properties may not be recoverable from estimated future net revenues. The impairment provision is based on the excess of carrying value over fair value. Fair value is defined as the present value of the estimated future net revenues from production of total proved and risk-adjusted probable and possible oil and gas reserves over the economic life of the reserves, based on the Company’s expectations of future oil and gas prices and costs, consistent with price and cost assumptions used for acquisition evaluations. In the first quarter of 2004, the Company recorded an impairment of $3.9 million related to one proved oil and gas property in the U.S. No impairment provision related to the proved oil and gas properties was required in the first three months of 2005.

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Development Seismic Costs

The Company capitalizes delineation seismic costs incurred to select development drilling locations within a productive oil and gas field as development costs. Exploration seismic costs are expensed as incurred. The Company did not capitalize any delineation seismic costs in the three months ended March 31, 2005.

Asset Retirement Obligations

The Company records the discounted fair value of its asset retirement obligations as a liability at the time an asset is placed in service. 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 March 31, 2005, there were no assets legally restricted for purposes of settling asset retirement obligations. Of the liability for asset retirement obligations balance at March 31, 2005, approximately $2.4 million is classified as current and is included in “other payables and accrued liabilities” in the accompanying balance sheet.

The Company recorded the following activity related to its asset retirement liability for the three months ended March 31, 2005 (in thousands):


Liability for asset retirement obligations as of January 1, 2005	$	93,066
New obligations for wells drilled		187
Costs incurred		(2,197	)
Accretion expense		1,747

Liability for asset retirement obligations as of March 31, 2005	$	92,803

Other Payables and Accrued Liabilities

As of March 31, 2005, “other payables and accrued liabilities” includes $17.3 million of accrued oil and gas capital expenditures.

Derivative Financial Instruments

The Company periodically uses hedges to reduce the impact of oil and natural gas price fluctuations and generally attempts to qualify such derivatives as cash flow hedges for accounting purposes. 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. The Company defines fair value as the amount it would receive or pay to settle the derivative at period-end. 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.

-13-

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 expected cash flows of the item being hedged. To the extent the cumulative change in the derivative exceeds the cumulative change in the expected cash flows, the excess is recognized currently in earnings as non-operating income or expense. If the cumulative change in the expected cash flows exceeds the change in fair value of the derivative, the difference is ignored. Changes in the fair value and settlements of derivative financial instruments that do not qualify, or ceased to qualify, for accounting treatment as hedges, if any, are recognized currently as non-operating income or expense. The cash flows from derivative financial instruments that do not qualify for hedge accounting are included in investing activities in the consolidated statements of cash flows.

Derivative losses included in income from continuing operations consist of the following (in thousands):


	Three Months Ended March 31,
	2005			2004
Unrealized losses under derivative instruments that did not qualify, or ceased to qualify, for hedge accounting	$	36,613		$	—
Realized (gains) losses under derivative instruments that did not qualify, or ceased to qualify, for hedge accounting		4,349			(924	)
Hedge ineffectiveness (recoveries) losses		(246	)		928

	$	40,716		$	4

Revenue Recognition

A portion of the Company’s domestic oil sales in Argentina were previously subject to a domestic price cap agreement, relating to deliveries occurring between February 26, 2003, and April 30, 2004. Under the agreement, if the $28.50 price cap is less than the West Texas Intermediate posted price as quoted on the Platt’s Crude Oil Marketwire at the time of sale, the Company is entitled to charge the oil purchasers for such difference only when the West Texas Intermediate posted price is less than the $28.50 price cap in future periods. The Company does not record any revenue under such price cap agreement until such time as the billed amounts are actually received. As of March 31, 2005, the Company had an unbilled potential recovery of approximately $7.5 million under this agreement, excluding interest. During the three months ended March 31, 2005 and 2004, the Company did not record any revenues under this agreement.

Oil inventories held in storage facilities are valued at cost, which is lower than market value. Such inventories totaled $3.8 million at March 31, 2005 and are included in “prepaids and other current assets” in the accompanying consolidated balance sheet.

-14-

General and Administrative Expense

The Company receives fees for the operation of jointly-owned oil and gas properties and records such reimbursements as reductions of general and administrative expense. Such fees totaled approximately $0.7 million and $0.6 million for the first quarter of 2005 and 2004, respectively. These amounts exclude reimbursements related to the Company’s discontinued operations in Canada.

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 expense 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 applied 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 three months of 2005 and 2004 is less than that which would have been recognized if the fair value based method had been applied to all awards since the original effective date of SFAS 123. The following table illustrates the effect on net income and income per share if the fair value based method had been applied to all outstanding and unvested awards in each period (in thousands, except per share amounts):


	Three Months Ended March 31,
	2005		2004
Stock compensation expense - as reported	$	1,506	$	3,762
Stock compensation expense - pro forma		1,515		3,801

Net income - as reported		31,925		19,135
Net income - pro forma		31,918		19,111

Income per share - as reported:
Basic		0.48		0.30
Diluted		0.48		0.29

Income per share - pro forma:
Basic		0.48		0.30
Diluted		0.48		0.29

The fair value of each option grant is estimated on the date of grant using the Black-Scholes option-pricing model. The Company did not grant any stock options in 2004 or in the first three months of 2005.

-15-

Production and Ad Valorem Taxes

Included in production and ad valorem taxes are the following items (in thousands):


	Three Months Ended March 31,
	2005		2004
Gross production taxes	$	5,420	$	3,853
Ad valorem taxes		1,464		1,453

Income Per Share

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

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


	Three Months Ended March 31,
	2005	2004
Weighted average common shares outstanding - Basic	66,139	64,328
Dilutive effect of potential common shares issuable upon the exercise of outstanding stock options	577	555
Dilutive effect of potential common shares issuable upon the vesting of outstanding restricted stock rights	172	147

Weighted average common shares outstanding - Diluted	66,888	65,030

All of the outstanding options to purchase shares of the Company’s common stock were included in the dilution calculation for the three months ended March 31, 2005, because the assumed exercise of each of the options was dilutive. Certain options to purchase shares of the Company’s common stock have been excluded from the dilution calculation for the three months ended March 31, 2004, because the assumed exercise of these options was anti-dilutive. These 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 the anti-dilutive options as of March 31, 2004:


Options excluded from dilution calculations (in thousands)		724
Range of exercise prices	$	15.50 to $22.94
Weighted average exercise price		$15.82

-16-

Comprehensive Income (Loss)

Comprehensive income (loss) consists of the following (in thousands):


	Three Months Ended March 31,
	2005			2004
Net income	$	31,925		$	19,135
Foreign currency translation adjustments		—			(1,978	)
Changes in value of derivative financial instruments, net of tax		(33,645	)		(10,327	)

Comprehensive income (loss)	$	(1,720	)	$	6,830

The foreign currency translation adjustments shown previously relate entirely to the translation of the financial statements of the Company’s previously-owned 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 derivative financial instruments, net of tax, consist of the following (in thousands):


	Three Months Ended March 31,
	2005			2004
Unrealized loss during the period	$	(64,520	)	$	(16,902	)
Reclassification adjustment for losses included in net income		9,455			362

		(55,065	)		(16,540	)
Income tax benefit		(21,420	)		(6,213	)

Changes in value of derivative financial instruments, net of tax	$	(33,645	)	$	(10,327	)

The balance in accumulated other comprehensive income at both March 31, 2005, and December 31, 2004, relates entirely to changes in the value of derivative financial instruments.

Statements of Cash Flows

During the three months ended March 31, 2005 and 2004, the Company made cash payments for interest totaling approximately $0.4 million, and $2.4 million, respectively. The Company made cash payments for U.S. income taxes of $1.0 million in the three months ended March 31, 2005. The Company had no cash payments for U.S. income taxes in the three months ended March 31, 2004. The Company made cash payments for income taxes of $12.4 million and $9.0 million in Argentina during the first three months of 2005 and 2004, respectively.

Approximately $141.7 million of the Company’s cash at March 31, 2005, is related to the Company’s foreign operations and substantially all is held in U.S. banks.

-17-

3.	LONG-TERM DEBT

Long-term debt at March 31, 2005, and December 31, 2004, consisted of the following (in thousands):


	March 31, 2005		December 31, 2004
Secured Debt -
Revolving credit facility	$	—	$	—
Unsecured Debt -
8 1/4% senior notes due 2012		350,000		350,000
7 7/8% senior subordinated notes due 2011, less unamortized discount		199,950		199,949

	$	549,950	$	549,949

In February 2004, the Company advanced funds under its revolving credit facility to redeem the entire $150 million principal balance of its 9 3/4% senior subordinated notes due 2009. As a result, the Company was required to expense certain associated deferred financing costs. This $2.6 million non-cash charge and a $7.3 million cash charge for the call premium resulted in a one-time charge of approximately $9.9 million ($6.0 million net of tax).

The Company had $18.0 million and $6.9 million of accrued interest payable related to its long-term debt at March 31, 2005, and December 31, 2004, 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.

The Company declared cash dividends of $0.05 and $0.045 per share for the three months ended March 31, 2005 and 2004, respectively.

-18-

5.	COMMITMENTS AND CONTINGENCIES

The Company had approximately $4.5 million in letters of credit outstanding at March 31, 2005. 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 Bolivia whereby the Company has committed to have a third party transport and compress certain volumes of the Company’s 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 $0.3 million and $0.7 million under these agreements in the three months ended March 31, 2005 and 2004, respectively. Based on the current fee level, these commitments total approximately $0.9 million for the remainder of 2005, $1.3 million in 2006 and $0.3 million in each of the years 2007, 2008 and 2009.

The Company has future minimum long-term electric power purchase commitments in Argentina of $2.7 million for the remainder of 2005, $3.6 million in 2006 and $4.9 million in 2007. The Company paid $0.8 million and $0.4 million for electric power purchases under these agreements in the three months ended March 31, 2005 and 2004, respectively.

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 5.3 Bcf for the remainder of 2005, 7.0 Bcf in 2006, 6.0 Bcf in 2007, 6.9 Bcf in 2008 and 6.9 Bcf in 2009. The volumes contracted under the agreement in Argentina are 7.7 Bcf for the remainder of 2005, 5.3 Bcf in 2006, 3.6 Bcf in 2007 and 4.0 Bcf in 2008. The Company made no payments under these agreements in 2005 and 2004.

6.	PRICE RISK MANAGEMENT

The Company periodically uses derivative financial instruments to reduce the impact of oil and gas price fluctuations on its operating results and cash flows and generally attempts to qualify such derivatives as hedges for accounting purposes. During the third and fourth quarter of 2004, a substantial portion of the Company’s derivative financial instruments ceased to qualify for hedge accounting due to significant oil price fluctuations. The Company continued to monitor the correlation between the changes in NYMEX crude oil index prices and the changes in U.S. crude oil postings and, as of March 1, 2005, the Company determined that the correlation indicates that its existing oil price swap agreements would again be highly effective in achieving offsetting changes in the cash flows of the physical transactions. Accordingly, the Company redesignated all of its oil price swap contracts as cash flow hedges and resumed hedge accounting for these contracts as of March 1, 2005. As of March 1, 2005, and through March 31, 2005, all of the Company’s derivative financial instruments qualified as hedges for accounting purposes.

-19-

During the first quarter of 2004, the Company participated in oil price swap agreements covering 1.4 million barrels of its oil production at a weighted average NYMEX reference price of $29.77 per barrel. During the first quarter of 2005, the Company participated in oil price swap agreements covering 1.2 million barrels of its oil production at a weighted average NYMEX reference price of $37.77 per barrel, gas price swap agreements covering 1.2 million MMBtu of its gas production at a weighted average NYMEX reference price of $6.65 per MMBtu and gas price collar agreements covering 2.7 million MMBtu of its gas production with NYMEX floor reference prices of $6.00 per MMBtu and NYMEX cap reference prices ranging from $6.80 to $9.21 per MMBtu. In conjunction with each of the 2005 U.S. gas price swap and collar agreements, the Company entered into basis swap agreements covering identical periods of time and volumes. 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.

The Company has not entered into any new oil or gas price swap agreements or collars since December 31, 2004. The Company continues to monitor oil and gas prices and may enter into additional derivative transactions in the future.

The Company records the fair value of its commodity swap agreements as a current or long-term asset or liability based on the period in which the forecasted transaction will occur. The fair value of the derivative financial instrument obligation at March 31, 2005, consisted of a current liability of $96.3 million and an other long-term liability of $29.6 million.

7.	INCOME TAXES

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


	Three Months Ended March 31,
	2005		2004
U.S. federal statutory income tax rate	35.0	%	35.0	%
U.S. state income tax (net of federal tax benefit)	(2.1	)	(1.2	)
U.S. permanent differences	(5.2	)	6.4
Foreign operations	7.1		1.3

	34.8	%	41.5	%

The impact of foreign operations is primarily the result of lower tax depreciation, depletion and amortization in Argentina due to the inability to utilize inflation accounting for tax purposes. Earnings of the Company’s foreign subsidiaries are subject to foreign income taxes. No U.S. deferred tax liability will be recognized related to the unremitted earnings of these foreign subsidiaries, as it is the Company’s intention, generally, to reinvest such earnings permanently. At December 31, 2004, income considered to be permanently reinvested in certain foreign subsidiaries totaled approximately $425 million. The Company has paid or accrued foreign income taxes of approximately $230 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.

-20-

During the three months ended March 31, 2005, the Company reversed approximately $13.1 million of contingent liabilities related to U.S. federal and state income taxes. These contingent tax liabilities related to tax benefits resulting from certain filing positions taken for which the Company initially concluded, for financial reporting purposes, that, under GAAP, it was appropriate to recognize these benefits until the filing positions taken were sustained under a tax audit. During the first quarter of 2005, federal and state auditors completed audits of the Company’s tax returns for the periods involved, with no adjustments related to these filing positions required. Therefore, the Company concluded that it was now appropriate to recognize these tax benefits for financial reporting purposes. Approximately $10.7 million of these tax benefits related to previously-discontinued operations and are reflected as “income from discontinued operations” in the accompanying consolidated statement of operations for the three months ended March 31, 2005. The remaining $2.4 million is included in the continuing operations “deferred tax benefit” in the accompanying consolidated statement of operations for the three months ended March 31, 2005.

The American Jobs Creation Act of 2004 (the “Jobs Act”) introduced a special one-time dividends-received deduction on the repatriation of certain foreign earnings to the U.S., provided certain conditions are met. If certain conditions are met, a 5.25 percent effective income tax rate would apply to eligible repatriations of certain foreign earnings. The Company is currently evaluating these provisions under the Jobs Act and is also awaiting interpretive guidance relating to these regulations from either Congress or the Treasury Department. At the current date, the Company has not determined that it will repatriate any unremitted foreign earnings under the special one-time repatriation provisions of the Jobs Act. However, the Company continues to evaluate the special one-time repatriation provisions of the Jobs Act and that evaluation could result in the Company repatriating certain unremitted foreign earnings. The amount of unremitted foreign earnings that the Company is evaluating for repatriation, including projected 2005 earnings, ranges from zero to $500 million. The Company expects to complete its evaluation of the amount of repatriation, if any, during 2005. If the Company was to repatriate certain unremitted foreign earnings under the special one-time repatriation provisions of the Jobs Act in the range noted in the preceding sentence, the income tax effects of such repatriation could range from zero to approximately $26 million.

8.	DISCONTINUED OPERATIONS

On November 30, 2004, the Company completed the sale of its operations in Canada. The Company received $274.7 million in cash and recorded a gain of approximately $167.8 million ($198.5 million including income tax benefit).

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 Canada are accounted for as discontinued operations in the accompanying consolidated financial statements.

Following is summarized financial information for the Company’s operations in Canada for the three months ended March 31, 2004, (in thousands):


Revenues	$	25,035

Income from discontinued operations	$	1,127
Income tax expense		353

Income from discontinued operations, net of tax	$	774

-21-

As discussed in Note 7, in the three months ended March 31, 2005, the Company reversed approximately $10.7 million of contingent U.S. federal and state income tax liabilities related to its previously-discontinued operations in Trinidad.

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 crude oil, condensate, natural gas liquids and natural gas. The gas marketing segment generates a margin through the purchase and resale of both Company-produced and third party-produced gas volumes. The Company evaluates the performance of its operating segments based on operating income.

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

Operations in the gas marketing segment are in the U.S. The Company operates in the oil and gas exploration and production industry in the U.S., Argentina, Bolivia, Yemen and Bulgaria. The financial information related to the Company’s discontinued operations in Canada has been excluded in all periods presented (see Note 8). Summarized financial information for the Company’s reportable segments for the three months ended March 31, 2005 and 2004, is shown in the following tables (in thousands):


	Exploration and Production
	U.S.		Argentina			Bolivia		Yemen		Other Foreign
Three Months Ended 3/31/05
External segment revenues	$	98,052	$	98,842		$	2,583	$	16,704	$	—
Intersegment revenues		—		—			—		—		—
Depreciation, depletion and amortization expense		15,918		14,452			629		1,971		—
Operating income (loss)		46,050		44,806			941		8,690		(180	)
Total assets		690,127		644,287			113,429		66,417		—
Capital investments		28,739		29,287			—		6,098		163
Long-lived assets		569,921		582,204			88,061		53,223		—

	Gas Marketing		Corporate			Total
Three Months Ended 3/31/05
External segment revenues	$	18,578	$	—		$	234,759
Intersegment revenues		719		—			719
Depreciation, depletion and amortization expense		—		427			33,397
Operating income (loss)		1,036		(15,771	)		85,572
Total assets		20,635		186,209			1,721,104
Capital investments		—		509			64,796
Long-lived assets		—		5,211			1,298,620

-22-


	Exploration and Production
	U.S.		Argentina			Bolivia		Yemen			Other Foreign
Three Months Ended 3/31/04
External segment revenues	$	73,881	$	71,675		$	3,415	$	—		$	—
Intersegment revenues		—		—			—		—			—
Depreciation, depletion and amortization expense		10,665		12,103			715		—			—
Operating income (loss)		28,128		37,685			1,519		(265	)		(183	)
Total assets		487,117		549,509			112,644		26,502			1,352
Capital investments		21,997		21,311			—		2,567			328
Long-lived assets		451,965		500,305			90,721		25,929			992

	Gas Marketing		Corporate			Total
Three Months Ended 3/31/04
External segment revenues	$	14,773	$	—		$	163,744
Intersegment revenues		381		—			381
Depreciation, depletion and amortization expense		—		603			24,086
Operating income (loss)		701		(11,206	)		56,379
Total assets		14,423		73,402			1,264,949
Capital investments		—		674			46,877
Long-lived assets		—		5,146			1,075,058

-23-

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 the U.S., South America, Yemen, and Bulgaria. We are focused on the acquisition of oil and gas properties which 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 the U.S. that may impact production in the near term as well as high potential frontier prospects that may impact production in the longer term.

During 2004 and the first quarter of 2005, we have been focused on our core objectives of acquisitions, exploitation and exploration. We were able to complete two acquisitions of producing properties, one in September 2004 in Argentina at a total cost of $34.9 million and one in the U.S. in December 2004 at a total cost of $77.2 million. This increased focus on our core objectives has resulted in a significant improvement in our production levels and our operating results. It has also allowed us to significantly increase our capital expenditures in 2004 and 2005 compared to previous years. We incurred $64.3 million of oil and gas capital expenditures in the first quarter of 2005 and we plan to spend approximately $250 million in 2005, exclusive of acquisitions. We expect to have sufficient internally generated cash flows to fund our non-acquisition capital expenditures. In the event we successfully secure acquisitions of oil and gas properties, we will seek appropriate levels of oil and gas price risk management and debt and equity capital in order to maintain or improve our capital structure.

We reported net income of $31.9 million in the first quarter of 2005 compared to net income of $19.1 million in the first quarter of 2004. Net income for the first quarter of 2005 includes $10.7 million of income from discontinued operations versus $0.8 million of income from discontinued operations in the first quarter of 2004. Income from continuing operations for the first quarter of 2005 was significantly impacted by $36.4 million of unrealized losses from derivative transactions, which resulted from substantial increases in oil prices during January and February 2005, when most of our oil price swap agreements were accounted for under mark-to-market accounting. As of March 1, 2005, we redesignated all of our oil price swap agreements as cash flow hedges and therefore we were allowed to cease mark-to-market accounting for these derivative financial instruments.

Total production from continuing operations of 6.8 million barrels of oil equivalent (“BOE”) for the first quarter of 2005 was 20 percent higher than the 5.6 million BOE in the first quarter of 2004. This increase resulted from the acquisitions discussed above, the results of our successful exploration activities in Yemen and the results of our successful exploitation and exploration activities in the U.S. and Argentina. Our Argentina production in the first quarter of 2004 was negatively impacted by a labor strike, which reduced production for the quarter by an estimated 188,000 BOE. Our U.S. production in the first quarter of 2005 was reduced by an estimated 232,000 BOE as a result of heavy rains and mudslides in Ventura County, California which required us to shut in certain wells. Most of this shut-in production was restored throughout the first quarter of 2005 and the affected production is expected to be fully restored by the end of the second quarter of 2005.

-24-

As a result of the 20 percent increase in production on a BOE basis discussed above and higher oil and gas prices, our cash provided by continuing operations for the first quarter of 2005 was $103.0 million, which was 38 percent higher than the first quarter of 2004. The increases in production and prices were slightly offset by higher cash operating expenses.

Our future financial results depend on a number of factors, including, in particular, oil and gas prices, our ability to find or acquire oil and gas reserves, access to capital, our ability to control costs and both domestic and foreign regulatory developments. Commodity prices are impacted by many factors that are outside of our control. Historically, commodity prices have been volatile and we expect them to remain volatile. 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 can not 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.

-25-

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. Acquisitions of producing oil and gas properties in the U.S. and Argentina during late 2004 and the disposition of our Canadian operations in November 2004 affect the comparability of operating data for the periods presented in the tables below. Fluctuations in oil and gas prices have also significantly affected our results. The following table reflects our oil and gas production and our average oil and gas sales prices for the periods presented:


	Three Months Ended March 31,
	2005	2004
Production:
Oil (MBbls) -
U.S. (a).	1,464	1,513
Argentina (b)(c)	3,084	2,441
Bolivia (b)	15	20
Yemen (b)	361	—
Continuing operations	4,924	3,974
Canada	—	235
Total	4,924	4,209

Gas (MMcf) -
U.S. (a).	7,683	6,240
Argentina (c)	2,153	2,032
Bolivia	1,331	1,719
Continuing operations	11,167	9,991
Canada	—	3,938
Total	11,167	13,929

MBOE from continuing operations	6,785	5,639
Total MBOE	6,785	6,531

(a)	U.S. production for the three months ended March 31, 2005, is estimated to have been reduced as a result of mudslides in Ventura County, California by 192 MBbls of oil and 238 MMcf of gas, or 232 MBOE.

(b)	Oil production (in MBbls) before the impact of changes in inventories:


	Three Months Ended March 31,
	2005	2004
Argentina	2,824	2,475
Bolivia	13	21
Yemen	344	1

(c)	Argentina production for the three months ended March 31, 2004, is estimated to have been reduced as the result of a labor strike by 165 MBbls of oil and 135 MMcf of gas, or 188 MBOE.

-26-


	Three Months Ended March 31,
	2005			2004
Average Sales Price (including impact of hedges):
Oil (per Bbl) -
U.S.	$	35.01	(a)	$	27.94
Argentina		31.53			28.95
Bolivia		23.14			23.86
Yemen		46.24			—
Continuing operations		33.62	(a)		28.54
Canada		—			27.84

Gas (per Mcf) -
U.S.	$	5.99		$	4.99
Argentina		0.74			0.49
Bolivia		1.69			1.70
Continuing operations		4.47			3.51
Canada		—			4.68

Average Sales Price (excluding impact of hedges):
Oil (per Bbl) -
U.S.	$	42.33		$	32.51
Argentina		31.53			28.95
Bolivia		23.14			23.86
Yemen		46.24			—
Continuing operations		35.80			30.28
Canada		—			30.78

Gas (per Mcf) -
U.S.	$	5.83		$	4.99
Argentina		0.74			0.49
Bolivia		1.69			1.70
Continuing operations		4.36			3.51
Canada		—			4.68

(a)

The average oil sales price per barrel for the U.S. and continuing operations for the three months ended March 31, 2005, does not reflect realized losses of $2.98 and $0.89 per barrel, respectively, which relate to settlements on economic hedges. These losses have been reflected in non-operating expense. Economic hedges are derivative financial instruments, intended to hedge a specific exposure, that do not qualify or ceased to qualify for hedge accounting under SFAS 133.

-27-

Oil Prices

Average U.S. oil prices we receive generally fluctuate with changes in the NYMEX reference price for oil. Our oil production in Argentina is sold primarily at West Texas Intermediate spot prices as quoted on the Platt’s Crude Oil Marketwire (approximately equal to the NYMEX reference price) less a specified differential. Our Yemen oil production is sold at Dated Brent prices as quoted in Platt’s Crude Oil Marketwire less a specified differential. In the first quarter of 2005, we experienced an 18 percent increase in our average oil price from continuing operations, both including and excluding the impact of hedging activities, compared to the first quarter of 2004.

During late 2004 and continuing in the first quarter of 2005, the NYMEX reference price for crude oil was at or above $45.00 per barrel and our contract differentials on our California and Argentina properties increased, thus lowering our average realized oil prices as a percent of NYMEX. If future NYMEX reference prices stay at or above this level our realized price as a percentage of NYMEX may be lower than our previous historical relationships.

Our Argentina oil production is subject to an export tax. This tax is applied on the sales value after the tax, thus, the effective tax rate is less than the stated rate. The export tax rate was 20 percent in the first quarter of 2004. In May 2004, the Argentine government increased the export tax from 20 percent to 25 percent. In August 2004, the Argentine government further increased the export tax rates for oil exports. The export tax now escalates from 25 percent (which results in a 20 percent effective rate) to a maximum rate of 45 percent (which results in a 31 percent effective rate) of the realized value for exported barrels as West Texas Intermediate posted prices per Bbl increase from less than $32.00 to $45.00 and above. The export tax is deducted for income tax purposes but is not deducted in the calculation of royalty payments. The export tax expires in February 2007. Given the number of governmental changes during 2004 affecting the realized price we receive for our oil sales, no specific predictions can be made about the future of oil prices in Argentina; however, in the short term, we expect Argentine oil realizations to be less than oil realizations in the U.S. Export oil sales are valued and paid in U.S. dollars. Domestic Argentine oil sales, while valued in U.S. dollars, are paid in equivalent pesos.

We currently export approximately 35 percent of our Argentine oil production. 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.

On January 2, 2003, at the Argentine government’s request, crude oil producers and refiners agreed to limit amounts payable for certain 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 West Texas Intermediate posted price and the maximum price would be payable once the West Texas Intermediate posted price fell below the maximum. The debt payable under the original agreement accrues interest at eight percent. The total debt will be collected by invoicing future deliveries at $28.50 per Bbl after the West Texas Intermediate posted price falls below the maximum price. Additionally, the agreement allowed for renegotiation if the West Texas Intermediate reference price exceeded $35.00 per Bbl for 10 consecutive days, which occurred on February 24, 2003.

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On February 25, 2003, the agreement between the producers and the refiners was modified to limit the amount payable from refiners to producers for deliveries occurring between February 26, 2003, and March 31, 2003. While the $28.50 per Bbl payable maximum was maintained, under the modified terms refiners have no obligation to pay producers for sales values that exceed $36.00 per Bbl. This agreement, which was extended several times under similar terms, expired on April 30, 2004. At March 31, 2005, the accumulated balance of amounts which we may charge to domestic oil purchasers in Argentina, if the West Texas Intermediate posted price decreases below the established maximum price in the future, was approximately $7.5 million, excluding interest. We do not have the right to invoice for such amounts until such time as the West Texas Intermediate posted price declines below the established price cap of $28.50. Accordingly, we have adopted a revenue recognition accounting policy for this potential revenue in which we will record such revenue only upon the receipt of payment for this additional billing due to the uncertainty of recovery of such amounts and the timing thereof. During 2004 and 2005, we did not record any revenue under this agreement.

To the extent that derivative financial instruments qualify for accounting treatment as cash flow hedges, we record the cash settlements as an adjustment to oil and gas sales. During the first quarter of 2004, we participated in oil price swap agreements covering 1.4 million barrels of our oil production at a weighted average NYMEX reference price of $29.77 per barrel and during the first quarter of 2005, we participated in oil price swap agreements covering 1.2 million barrels of our oil production at a weighted average NYMEX reference price of $37.77 per barrel. We accounted for all of the first quarter 2004 oil price swaps as cash flow hedges and we accounted for 0.7 million barrels of the first quarter 2005 oil price swaps as cash flow hedges. The impact of the cash settlements under oil price swaps accounted for as cash flow hedges are reflected in the preceding tables. The impact of the 0.5 million barrels under the first quarter 2005 oil price swaps not accounted for as cash flow hedges did not impact reported oil sales.

Gas Prices

Average U.S. gas prices we receive generally fluctuate with changes in spot market prices, which may vary significantly by region. Most of our Bolivian gas production is sold at average gas 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 and we are paid in pesos. This 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. Market prices for gas in Argentina have historically been significantly less than developed countries, such as the U.S. This is primarily due to limited gas markets and gas infrastructure in the region whose developed supplies have been sufficient to meet both internal demand and allow for exports to Chile. Our total average gas price from continuing operations for the first quarter of 2005 was 27 percent higher than the first quarter of 2004, including the impact of hedging activities (24 percent higher excluding hedging activities).

During the first quarter of 2005, we participated in gas price swap agreements covering 1.2 million MMBtu of our gas production at a weighted average NYMEX reference price of $6.65 per MMBtu and gas price collar agreements covering 2.7 million MMBtu of our gas production with NYMEX floor reference prices of $6.00 per MMBtu and NYMEX cap reference prices ranging from $6.80 to $9.21 per MMBtu. In conjunction with each of our 2005 U.S. gas price swap and collar agreements, we entered into basis swap agreements covering identical periods of time and volumes. These basis swaps establish a differential between the NYMEX reference price and the various delivery points at levels that are comparable to the historical differentials we have received. All of these gas price swaps were accounted for as cash flow hedges. The impacts of the cash settlements under these cash flow hedges on our average gas prices are reflected in the preceding tables. We did not hedge any of our gas production in the first quarter of 2004.

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Future Period Price Risk Management

We have previously engaged in oil and gas derivative transactions and we intend to continue to consider various derivative transactions to realize commodity prices which we consider favorable. The counterparties to all of our current derivative transactions are commercial or investment banks.

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


Quarter Ending	Barrels	NYMEX Reference Price Per Barrel
June 30, 2005	1,255,800	$	36.49
September 30, 2005	1,269,600		35.57
December 31, 2005	1,269,600		34.88

March 31, 2006	427,500		37.39
June 30, 2006	432,250		36.80
September 30, 2006	437,000		36.32
December 31, 2006	437,000		35.93

March 31, 2007	189,000		34.26
June 30, 2007	63,700		39.66
September 30, 2007	64,400		39.38
December 31, 2007	64,400		39.10

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


Quarter Ending	MMBtu	NYMEX Reference Price Per MMBtu
June 30, 2005	1,173,900	$	6.15
September 30, 2005	1,186,800		6.17
December 31, 2005	1,186,800		6.37

March 31, 2006	243,000		6.47
June 30, 2006	245,700		6.47
September 30, 2006	248,400		6.47
December 31, 2006	248,400		6.47

March 31, 2007	225,000		6.00
June 30, 2007	227,500		6.00
September 30, 2007	230,000		6.00
December 31, 2007	230,000		6.00

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We have also entered into various gas price collar arrangements for 2005. The following table reflects the MMBtu covered by these gas price collars and the corresponding NYMEX floor and cap reference prices:


Remaining 2005 Gas Production (MMBtu)	NYMEX Floor Reference Price Per MMBtu		NYMEX Cap Reference Price Per MMBtu
1,375,000	$	6.00	$	6.80
2,750,000		6.00		8.02
1,375,000		6.00		8.73
2,750,000		6.00		9.21

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

Period to Period Comparison

On November 30, 2004, we sold all of our Canadian operations. We received $274.7 million in cash and recorded a gain of $167.8 million ($198.5 million after income taxes) in the fourth quarter of 2004. In accordance with the rules established by Statement of Financial Accounting Standards No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, our operations in Canada are accounted for as discontinued operations in our consolidated financial statements. Accordingly, the revenues and operating expenses discussed below exclude the results related to our operations in Canada for all periods.

Oil, condensate and NGL sales. Oil, condensate and NGL sales increased by $52.2 million, 46 percent, to $165.6 million for the first quarter of 2005 from $113.4 million for the first quarter of 2004. The increase resulted from a 24 percent increase in oil production for the first quarter of 2005 compared to the first quarter of 2004, along with an 18 percent increase in our average oil price between the same periods.

Argentina oil production increased by 0.7 million barrels, 26 percent, to 3.1 million barrels in the first quarter of 2005 from 2.4 million barrels in the first quarter of 2004. The first quarter of 2004 was negatively impacted by a labor strike which reduced reported production for the quarter by an estimated 165,000 barrels of oil. The remaining increase in our Argentina oil production was a result of our acquisition of producing properties in the San Jorge basin in September 2004 and additional production resulting from our 2004 and 2005 drilling and workover programs.

Oil production from our An Nagyah field in Yemen began making a contribution in the second quarter of 2004 and our Yemen oil production was 0.4 million barrels in the first quarter of 2005. All of the An Nagyah field production is transported by truck to a nearby facility for processing and transporting to an export terminal until our planned pipeline is operational. The trucking capacity is approximately 7,500 gross barrels of oil production per day (“BOPD”) (3,900 BOPD net). Our pipeline to the processing facility is under construction and is scheduled to be operational late in the second quarter of 2005 with initial throughput anticipated at 10,000 gross BOPD (5,200 net). A central processing facility with an initial capacity of 10,000 to 12,000 gross BOPD (5,200 to 6,250 net) is scheduled to begin operation during the third quarter of 2005.

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Our U.S. oil production in the first quarter of 2005 was reduced by an estimated 192,000 barrels as a result of heavy rains and mudslides in Ventura County, California which required us to shut in certain wells. We estimate that oil production of 400 BOPD currently remains shut in, but we expect this production to be restored by the end of the second quarter of 2005.

Gas sales. Gas sales increased $14.8 million, 42 percent, to $49.9 million for the first quarter of 2005 from $35.1 million for the first quarter of 2004. The increase is the result of a 27 percent increase in our average gas price along with a 12 percent increase in gas production for the first quarter of 2005 compared to the first quarter of 2004.

The increase in gas production primarily relates to a 23 percent increase in our gas production in the U.S. for the first quarter of 2005 compared to the first quarter of 2004. The U.S. increase resulted from exploitation and exploration successes and the December 2004 acquisition of producing properties in the Gulf Coast area of Alabama. The increase in the U.S. was offset by an estimated reduction in gas production of 238 MMcf resulting from the heavy rains and mudslides in California discussed above. We estimate that daily gas production of 1.0 MMcf currently remains shut in, but we expect this production to be restored by the end of the second quarter of 2005.

Gas production in Argentina for the first quarter of 2004 was reduced by an estimated 135 MMcf due to the labor strike discussed above. There was no similar disruption in 2005.

Production costs. Production costs increased $7.9 million, 22 percent, to $43.7 million for the first quarter of 2005 from $35.8 million for the first quarter of 2004. On a BOE basis, production costs increased by one percent to $6.44 for the first quarter of 2005 from $6.35 for the first quarter of 2004. During the first quarter of 2005, we incurred approximately $3.5 million to repair the damage from the heavy rains and mudslides in California. We expect to spend an additional $4.0 million in total during the second and third quarters of 2005 on these repairs. Production costs for the first quarter of 2004 included $1.9 million for costs to repair damage resulting from fires in California during late 2003.

Transportation and storage costs. Transportation and storage costs increased $2.0 million, 112 percent, to $3.9 million for the first quarter of 2005 from $1.9 million for the first quarter of 2004. This increase is primarily the result of trucking costs associated with our new Yemen production area. We began incurring these costs in the second quarter of 2004 to deliver our product to a nearby processing facility. Our pipeline and processing facility are currently under construction and completion is scheduled for the second and third quarters of 2005, respectively.

Production and ad valorem taxes. Production and ad valorem taxes increased $1.6 million, 30 percent, to $6.9 million for the first quarter of 2005 from $5.3 million for the first quarter of 2004. This increase is primarily the result of higher oil and gas prices and an increase in U.S. production on a BOE basis of eight percent from the first quarter of 2004 to the first quarter of 2005.

Export taxes. Export taxes in Argentina increased $7.1 million, 115 percent, to $13.3 million for the first quarter of 2005 from $6.2 million for the first quarter of 2004. Our Argentine domestic sales volumes as a percent of our total sales volumes have increased slightly in the first quarter of 2005 compared to the first quarter of 2004. However, higher oil prices and the increased export tax rates in 2004 offset the decreases in export volumes. The export tax rate increased from 20 percent to 25 percent in May 2004 and was further increased in August 2004. The average effective export tax rate for the first quarter of 2005 on our exported volumes was 30.4 percent.

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Exploration costs. Exploration costs increased $9.1 million, 735 percent, to $10.3 million for the first quarter of 2005 from $1.2 million for the first quarter of 2004. Exploration costs for the first quarter of 2005 consisted of $6.3 million for seismic and other geological and geophysical costs, $2.6 million for unsuccessful exploratory drilling, primarily in Yemen, and $1.4 million for impairment of unproved leaseholds. During the first quarter of 2004, our exploration costs were primarily comprised of $1.2 million for seismic and other geological and geophysical costs.

General and administrative expenses. General and administrative expenses increased $1.5 million, 11 percent, to $15.8 million for the first quarter of 2005 from $14.3 million for the first quarter of 2004. The increase primarily related to employee performance bonuses. We have accrued amounts for estimated 2005 employee performance bonuses in the first quarter of 2005 while none were accrued during the same period of 2004. Our 2004 bonus program was not in place until the end of the second quarter of 2004.

Stock compensation. Stock compensation decreased $2.3 million, 60 percent, to $1.5 million in the first quarter of 2005 from $3.8 million in the first quarter of 2004. In March 2004, we entered into a separation agreement with a former executive under which we extended the period in which he could exercise his outstanding vested stock options to the end of the option term. Under the terms of the restricted stock award agreements with the former executive, all of the restricted shares granted to him under these agreements became fully vested as of his termination date. As a result of these events, we recorded additional non-cash stock compensation expense of approximately $2.2 million in the first quarter of 2004. There were no comparable charges in the first quarter of 2005.

Depreciation, depletion and amortization. Depreciation, depletion and amortization increased $9.3 million, 39 percent, to $33.4 million for the first quarter of 2005 from $24.1 million for the first quarter of 2004. A production increase of 20 percent on a BOE basis primarily led to the increase in total depreciation, depletion and amortization. Our average oil and gas amortization rate per BOE of production increased from $4.12 for the first quarter of 2004 to $4.83 for the first quarter of 2005. This increase was primarily a result of our acquisitions of producing properties in the Argentina San Jorge basin in September 2004 and in the Gulf Coast area of Alabama in December 2004.

Impairment of proved oil and gas properties. In the first quarter of 2004, we recorded impairment expense of $3.9 million related to one proved oil and gas property in the U.S. This impairment resulted from a revision of our estimate of that property’s proved oil and gas reserves based on its production level in early 2004. No impairments were required in the first quarter of 2005.

Other operating (income) expense. We had $1.0 million of other operating expense in the first quarter of 2005 and other operating income of $4.8 million in the first quarter of 2004. In the first quarter of 2004, we recorded a gain of $6.0 million from a settlement of a certain contract claim that we had against a third party. There was no similar income in the first quarter of 2005.

Interest expense. Interest expense decreased $2.6 million, 18 percent, to $11.6 million for the first quarter of 2005 from $14.0 million for the first quarter of 2004 due to a 19 percent reduction in our average debt outstanding. 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. We subsequently paid off the balance on our revolving credit facility with cash on hand and proceeds from the November 2004 sale of our Canadian operations.

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Loss on early extinguishment of debt. In connection with the redemption of our senior subordinated notes discussed above, we were required to pay call premiums on the notes and expense certain associated deferred financing costs and discounts related to the notes, resulting in a loss on early extinguishment of debt of $9.9 million, $6.0 million after tax, in the first quarter of 2004. There was no such charge in the first quarter of 2005.

Losses on derivative transactions. We recorded total losses on derivative transactions of $40.7 million during the first quarter of 2005 related to realized and unrealized market value adjustments of derivative commodity instruments that did not qualify or ceased to qualify for hedge accounting. The non-cash unrealized losses during the first quarter of 2005 were $36.4 million ($22.2 million after tax). Beginning in September 2004 and continuing through February 2005, the differential between the NYMEX index price for crude oil and West Coast and other U.S. crude oil postings widened. Although the NYMEX crude oil index prices increased, many crude oil postings under which we sell our oil did not increase at the same rate. This market fluctuation caused us to conclude that most of our crude oil hedges were no longer highly effective in achieving offsetting changes in the cash flows of the physical transactions. In accordance with SFAS 133, we discontinued hedge accounting for these contracts beginning in September and recorded the changes in the fair value of these contracts as a charge to “losses on derivative transactions.” As of March 1, 2005, we determined that the correlation indicated that our existing oil price swap agreements will again be highly effective in achieving offsetting changes in the cash flows of the physical transactions and, accordingly, we redesignated all of our oil price swap contracts as cash flow hedges and resumed hedge accounting for these contracts as of March 1, 2005. During the first quarter of 2004, all of our derivative financial instruments qualified as cash flow hedges.

Cash Flows

Our primary sources of cash during the first quarter of 2005 were funds generated from operations. The cash was primarily used to fund capital expenditures and acquisitions of producing properties and pay dividends, with the remainder increasing our cash position by $39.6 million. See below for additional discussion of our cash flows from operating activities.


	Three Months Ended March 31,
	2005			2004			Change
Cash provided (used) by (in thousands):
Operating activities - continuing operations	$	102,993		$	74,437		$	28,556
Operating activities - discontinued operations		—			10,013			(10,013	)
Investing activities - continuing operations		(64,610	)		(46,901	)		(17,709	)
Investing activities - discontinued operations		—			(7,379	)		7,379
Financing activities		1,378			(16,525	)		17,903

Cash provided by continuing operations increased 38 percent to $103.0 million in the first quarter of 2005 compared to $74.4 million in the first quarter of 2004. Increases in production from continuing operations and higher product prices for the first quarter of 2005 compared to the same period in 2004 led to the increase. Higher revenues more than offset higher production costs and general and administrative expenses. We had $2.3 million of cash used by changes in working capital for the first quarter of 2005 compared to $10.4 million of cash provided by changes in working capital for the first quarter of 2004. See “Results of Operations” and “Period to Period Comparison” for further discussion.

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Investing activities in the first quarter of 2005 included capital spending of $60.3 million on a cash basis, or 59 percent of cash provided by continuing operations. This compares to capital spending in the first quarter of 2004 of $45.3 million, or 61 percent of cash provided by continuing operations. Cash used by investing activities in the first quarter of 2005 also includes $4.3 million for payments on derivative financial instruments that did not qualify, or ceased to qualify, for hedge accounting.

Cash used by financing activities in the first quarter of 2004 reflects the redemption of the entire $150 million principal balance of our 9 3/4% senior subordinated notes due 2009, funded by borrowings on our revolving credit facility.

Capital Expenditures

During the first quarter of 2005, our total capital expenditures were $64.3 million. In the U.S., our capital expenditures totaled $28.7 million. Exploitation activities accounted for $21.0 million of the U.S. capital expenditures with exploration activities contributing $7.7 million. Our capital expenditures outside the U.S. totaled $35.6 million. This amount consists of Argentine exploitation activities of $29.3 million, $4.0 million for exploitation activities in Yemen, and exploration activities of $2.3 million, primarily in Yemen.

As of March 31, 2005, we had total unproved oil and gas property costs of approximately $29.9 million, consisting of undeveloped leasehold costs of $16.2 million and unevaluated exploratory drilling costs of $13.7 million. Approximately $13.7 million of the total unevaluated costs are associated with our exploratory drilling program in Yemen and the remaining $16.2 million of unevaluated costs are associated with our exploration activities in the U.S. 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 our capital expenditures other than significant acquisitions. Our capital expenditure budget for 2005 is currently set at $250 million, exclusive of acquisitions. We do not have a specific acquisition budget since the timing and size of acquisitions are difficult to forecast. We are actively pursuing additional acquisitions of oil and gas properties. In addition to internally-generated cash flows and advances under our revolving credit facility, we may seek additional sources of capital to fund any future significant acquisitions, 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 flows 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.

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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 May 2005. As of March 31, 2005, we had unused availability under our revolving credit facility of $295.5 million (considering outstanding letters of credit of approximately $4.5 million).

Our internally generated cash flows, results of operations and financing for our operations are dependent on oil and gas prices. Realized oil and gas prices for the first quarter of 2005 were 18 percent and 27 percent higher, respectively, compared to the first quarter of 2004. These prices have historically fluctuated widely in response to changing market forces. For the first quarter of 2005, approximately 73 percent of our production from continuing operations was oil. We believe that our cash flows and unused availability under our revolving credit facility are sufficient to fund our planned capital expenditures for the foreseeable future. To the extent oil and gas prices decline, our earnings and cash flows from operations may be adversely impacted. Prolonged periods of low oil and gas prices could cause us to not be in compliance with maintenance covenants under our revolving credit facility and could negatively affect our credit statistics and coverage ratios and thereby affect our liquidity.

Contractual Obligations

Our contractual obligations have not changed significantly since December 31, 2004.

Inflation

During the first quarter of 2005, the Argentine inflation rate amounted to four percent and is expected to be approximately eight percent for all of 2005. In recent years, inflation outside of Argentina has not had a significant impact on our operations or financial condition and is not currently expected to have a significant impact on future periods.

Income Taxes

We incurred a current provision for income taxes from continuing operations of approximately $14.4 million and $12.1 million for the first three months of 2005 and 2004, 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, 2004, income considered to be permanently reinvested in certain foreign subsidiaries totaled approximately $425 million. We have paid or accrued foreign income taxes of approximately $230 million related to this income which may be available as a credit against U.S. federal income taxes on such income, if distributed. It is not practicable to estimate the amount of additional tax that might be payable on this foreign income if distributed because the amount of foreign taxes eligible for credit against U.S. federal income taxes on any such distribution will be determined based on facts and circumstances at the time of any actual distribution.

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During the three months ended March 31, 2005, we reversed approximately $13.1 million of contingent liabilities related to U.S. federal and state income taxes. These contingent tax liabilities related to tax benefits resulting from certain filing positions taken for which we initially concluded, for financial reporting purposes, that it was not appropriate, under GAAP, to recognize these benefits until the filing positions taken were sustained under a tax audit. During the first quarter of 2005, federal and state auditors completed audits of our tax returns for the periods involved, with no adjustments related to these filing positions required. Therefore, we concluded that it was now appropriate to recognize these tax benefits for financial reporting purposes. Approximately $10.7 million of these tax benefits related to previously-discontinued operations and are reflected as “income from discontinued operations” in the accompanying consolidated statement of operations for the three months ended March 31, 2005. The remaining $2.4 million is included in the continuing operations “deferred tax benefit” in the accompanying consolidated statement of operations for the three months ended March 31, 2005.

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


	Three Months Ended March 31,
	2005		2004
U.S. federal statutory income tax rate	35.0	%	35.0	%
U.S. state income tax (net of federal tax benefit)	(2.1	)	(1.2	)
U.S. permanent differences	(5.2	)	6.4
Foreign operations	7.1		1.3

	34.8	%	41.5	%

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

The American Jobs Creation Act of 2004 (the “Jobs Act”) introduced a special one-time dividends-received deduction on the repatriation of certain foreign earnings to the U.S., provided certain conditions are met. If certain conditions are met, a 5.25 percent effective income tax rate would apply to eligible repatriations of certain foreign earnings. We are currently evaluating these provisions under the Jobs Act and we are also awaiting interpretive guidance relating to these regulations from either Congress or the Treasury Department. At the current date, we have not determined that we will repatriate any unremitted foreign earnings under the special one-time repatriation provisions of the Jobs Act. However, we continue to evaluate the special one-time repatriation provisions of the Jobs Act and that evaluation could result in our repatriating certain unremitted foreign earnings. The amount of unremitted foreign earnings that we are evaluating for repatriation, including projected 2005 earnings, ranges from zero to $500 million. We expect to complete our evaluation of the amount of repatriation, if any, during 2005. If we were to repatriate certain unremitted foreign earnings under the special one-time repatriation provisions of the Jobs Act in the range noted in the preceding sentence, the income tax effects of such repatriation could range from zero to approximately $26 million.

Critical Accounting Policies and Estimates

Our critical accounting policies are discussed in our 2004 Annual Report on Form 10-K (the “2004 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 2004 Form 10-K.

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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;

•

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 2004 Form 10-K, and listed from time to time in our filings with the Securities and Exchange Commission;

•

oil and gas prices;

•

exploitation and exploration successes;

•

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

•

continued availability of capital and financing;

•

changes in foreign exchange rates and inflation rates;

•

general economic, market or business conditions;

•

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

•

changes in laws or regulations; and

•

other factors, most of which are beyond our control.

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

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

Commodity Price Risk

We produce, purchase and sell crude oil, natural gas, condensate, natural gas liquids and sulfur. As a result, our financial results can be significantly impacted as these commodity prices fluctuate widely in response to changing market forces. Relatively modest changes in either oil or gas prices significantly impact our results of operations and cash flows. However, the impact of changes in the market prices for oil and gas on our average realized prices may be reduced from time to time based on the level of our hedging activities. Based on oil production from continuing operations for the first quarter of 2005, 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 $11.8 million and $18.3 million, respectively. A 10 cent per Mcf change in the average gas price we realize, before hedges, would result in a change in net income and revenues less production taxes on an annual basis of approximately $2.8 million and $4.4 million, respectively, based on gas production for the first quarter of 2005.

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. The counterparties to our hedging agreements are commercial or investment banks. At March 31, 2005, we would have been required to pay approximately $125.9 million to terminate our swap agreements and price collars then in place.

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


Quarter Ending	Barrels	NYMEX Reference Price Per Barrel
June 30, 2005	1,255,800	$	36.49
September 30, 2005	1,269,600		35.57
December 31, 2005	1,269,600		34.88

March 31, 2006	427,500		37.39
June 30, 2006	432,250		36.80
September 30, 2006	437,000		36.32
December 31, 2006	437,000		35.93

March 31, 2007	189,000		34.26
June 30, 2007	63,700		39.66
September 30, 2007	64,400		39.38
December 31, 2007	64,400		39.10

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


Quarter Ending	MMBtu	NYMEX Reference Price Per MMBtu
June 30, 2005	1,173,900	$	6.15
September 30, 2005	1,186,800		6.17
December 31, 2005	1,186,800		6.37

March 31, 2006	243,000		6.47
June 30, 2006	245,700		6.47
September 30, 2006	248,400		6.47
December 31, 2006	248,400		6.47

March 31, 2007	225,000		6.00
June 30, 2007	227,500		6.00
September 30, 2007	230,000		6.00
December 31, 2007	230,000		6.00


Remaining 2003 Gas Production (MMBtu)	NYMEX Floor Reference Price Per MMBtu		NYMEX Cap Reference Price Per MMBtu
1,375,000	$	6.00	$	6.80
2,750,000		6.00		8.02
1,375,000		6.00		8.73
2,750,000		6.00		9.21

Interest Rate Risk

Our interest rate risk exposure results primarily from short-term rates, mainly LIBOR-based on borrowings from our commercial banks. To reduce the impact of fluctuations in interest rates, we have historically maintained a portion of our total debt portfolio in fixed-rate debt. At March 31, 2005, all of our outstanding debt was at fixed rates. However, we expect that this relationship will not continue and that a portion of our debt in future periods will be at variable rates. 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 our 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.

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Because we had no outstanding borrowings under variable-rate debt instruments as of March 31, 2005, a change in the average interest rate of 100 basis points would result in no change in our net income (loss) and cash flows before income taxes.

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


	2005	2006	2007	2008	2009	Thereafter			Total			Fair Value at 3/31/05
Long-Term Debt:
Fixed rate (in thousands)	—	—	—	—	—	$	549,950		$	549,950		$	589,125
Average interest rate	—	—	—	—	—		8.1	%		8.1	%		—
Variable rate (in thousands)	—	—	—	—	—		—			—			—
Average interest rate	—	—	—	—	—		—			—			—

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 Argentina, Bolivia, Yemen and Bulgaria. For the first quarter of 2005, our operations in Argentina accounted for approximately 42 percent of our revenues and 37 percent of our total assets. During the first quarter of 2005, our operations in Argentina represented our only foreign operation accounting for more than 10 percent of our revenues from continuing operations or total assets. We continue to identify and evaluate international opportunities, but we currently have no binding agreements or commitments to make any material international investment. As a result of such significant foreign operations, our financial results could be affected by factors such as changes in foreign currency exchange rates, weak economic conditions or changes in the political climate in these foreign countries.

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 and could negatively impact our net realized oil and gas prices;

•

exchange controls and currency fluctuations could result in financial losses;

•

royalty and tax increases and retroactive royalty and tax claims could increase costs of our foreign operations or decrease our net realized oil and gas prices;

•

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.

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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, the Argentine 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 of one peso to one U.S. dollar. The exchange rate at March 31, 2005, was 2.92 pesos to one U.S. dollar. The devaluation of the peso reduced our gas revenues and peso-denominated costs. Our oil revenues remain valued on a U.S. dollar basis.

Monetary assets and liabilities denominated in pesos at March 31, 2005, were as follows (in thousands):


	Peso Balance		U.S. Dollar Equivalent
Current assets	54,957		$	18,821
Current liabilities	(103,611	)		(35,483	)
Non-current liabilities	(72,470	)		(24,819	)

Net monetary liabilities	(121,124	)	$	(41,481	)

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. Because the tax is applied on the sales value after the tax, the net effect of the 20 and 25 percent rates was 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 25 percent (20 percent effective rate) to a maximum rate of 45 percent (31 percent effective rate) of the realized value for exported barrels as West Texas Intermediate posted prices per Bbl increase from less than $32.00 to $45.00 and above. This tax is limited by law to a maximum term through February 2007.

We currently export approximately 35 percent of our Argentine oil production. 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 export tax is deducted for income tax purposes but is not deducted in the calculation of royalty payments.

In accordance with Executive Decree 1589/89, companies engaged in oil and gas production activities are granted the right to freely sell and dispose of their hydrocarbons production. Furthermore, companies are entitled to collect export sales proceeds outside of Argentina and maintain up to 70 percent of U.S. dollar collections outside the country. According to the decree, companies should repatriate the remaining 30 percent of export collections through the exchange markets of Argentina. This requirement places no significant limitations on us based upon our cash flow projections.

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Beginning in December 2001, as a result of the economic crisis in the country, Argentina enacted several emergency decrees, including the reinstatement of foreign exchange controls and the mandatory repatriation of most export proceeds. The emergency decrees created some confusion in relation to the regime established under Executive Decree 1589/89, which allows hydrocarbons producers to retain 70 percent of their export collections outside of Argentina. In order to address this matter, Executive Decree No. 2703/02 was issued on December 27, 2002, which confirmed the right to maintain 70 percent of export proceeds outside the country effective January 1, 2003, and therefore did not address transactions which occurred during 2002 after the emergency decrees. We have collected and maintained as much as 70 percent of export proceeds in U.S. dollar bank accounts under the regime established by Executive Decree No. 1589/89 including transactions which occurred during 2002. Although we believe we have acted in accordance with the emergency measures and Executive Decrees in place during 2002, we are aware that the Argentine Central Bank has inquired about certain transactions made by other producers related to retention of export proceeds outside the country during the period in question.

On November 5, 2004, we received a letter from the Ministry of Economy of the Argentine Province of Santa Cruz requesting that royalty payments made since March 2002 be amended to eliminate the market impact of the Argentine export tax on sales to domestic refiners. We believe this request is made without merit, as royalties are calculated and paid on the actual prices received from third party purchasers.

On December 24, 2004, the Secretary of Energy issued Administrative Resolution 1679/2004, in order to alleviate shortages in domestic diesel markets by insuring adequate oil supplies to Argentine refiners. The terms of the resolution require producers to submit evidence to the Secretary of Energy that its oil to be exported has been offered to domestic refiners prior to the government’s issuance of export permission.

After a year of negotiations, on January 24, 2003, the International Monetary Fund (“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. Additionally, they agreed to a strategy to assure strengthening of the banking system, to facilitate increases in bank lending, and to further institutional and tax reforms to facilitate corporate debt restructuring and fundamental improvements to the investment climate. On January 28, 2004, the IMF completed and approved its first review of Argentina’s performance under the three-year program. On March 22, 2004, the second review and disbursement of the next $3.1 billion tranche was approved. A third review is pending and is expected to be completed during 2005. On January 12, 2005, the Argentine government announced a debt swap offer to external creditors. The offer commenced on January 14, 2005 and concluded on February 25, 2005.

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On March 3, 2005, the Argentine government announced a successful conclusion to the sovereign debt swap, reporting that 76 percent of bond holders will participate in the exchange. The bonds declared in default in December 2001 have a face value of $81.8 billion, and including unpaid interest, now amount to approximately $103 billion. The debt offered in exchange will be issued for approximately $35.2 billion. After completion of the transaction, total public debt-service costs will be reduced from approximately $10 billion to approximately $3 billion per year. Since good faith negotiations with bond holders and public debt restructuring were important steps for continued negotiations with the IMF, it appears more likely that Argentina and the IMF will be able to either modify the stand-by credit arrangement in place or negotiate a new agreement during the near term. It is also likely that other issues outstanding between Argentina and the IMF must still be addressed prior to a new agreement, such as an increase to public utility tariffs, a new loan to govern the fiscal relationship between the federal government and provinces and reform of the banking system.

On January 2, 2003, at the Argentine government’s request, crude oil producers and refiners agreed to limit amounts payable for certain 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 West Texas Intermediate posted price and the maximum price would be payable once the West Texas Intermediate posted price fell below the maximum. The debt payable under the agreement accrues interest at eight percent. The total debt will be collected by invoicing future deliveries at $28.50 per Bbl after the West Texas Intermediate posted price falls below the maximum price. Additionally, the agreement allowed for renegotiation if the West Texas Intermediate reference price exceeded $35.00 per Bbl for 10 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, which was extended several times under similar terms, expired on April 30, 2004. At March 31, 2005, the accumulated balance of amounts which we may charge to domestic oil purchasers in Argentina, if the West Texas Intermediate posted price decreases below the established maximum price in the future, was approximately $7.5 million, excluding interest. We do not have the right to invoice for such amounts until such time as the West Texas Intermediate posted price declines below the established price cap of $28.50. Accordingly, we have adopted a revenue recognition accounting policy for this potential revenue in which we will record such revenue only upon the receipt of payment for this additional billing due to the uncertainty of recovery of such amounts and the timing thereof. During 2004 and the first quarter of 2005, we did not record any revenue under this agreement. Cumulatively, we have sold approximately 2.0 MMBbls of net oil production under the agreement. We have not recorded revenue nor a receivable for any amounts above the $28.50 per Bbl maximum that have not yet been received. Repayments received from refiners will be recorded as revenues when received.

Bolivia. Since replacing former President Gonzalo Sanchez de Lozada, who was forced to resign during October 2003, current President Carlos Mesa has been forced on several occasions to make changes to his cabinet team due to continued political pressure from rival political parties and associated social unrest. After a transportation strike and demonstrations by university students and government pensioners that were held in April 2004, labor unions began threatening to escalate unrest by announcing general strikes during May 2004. On July 18, 2004, voters approved President Mesa’s public referendum on several proposed changes in Bolivia’s Hydrocarbon Law, including the export of Bolivian gas.

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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. This proposal includes both increased state control over hydrocarbons commercialization and a new taxation regime. Since then, debate has been ongoing and members of congress and rival political parties have proposed changes to President Mesa’s reform bill. In early March 2005, political tensions escalated as the Bolivian congress voted among rival proposals concerning the bill’s new taxation regime. Leftist opposition groups, led by Evo Morales and the M.A.S. (Socialist Movement) party, have demanded that President Mesa’s taxation reform proposals be abandoned in favor of increasing royalty rates from the current 18 percent level to a new rate of 50 percent. On March 7, 2005, President Mesa submitted his letter of resignation to the Bolivian congress in protest of the proposal and in response to demonstrations and blockades initiated by the opposition groups. On March 8, 2005, in a strong show of support for President Mesa, the congress voted unanimously to reject his resignation.

On March 15, 2005, the lower house of the Bolivian congress voted to approve a hydrocarbons bill that would establish fixed royalties at the current level of 18 percent. The bill also introduces a new production tax of 32 percent and enables the government to mandate that existing concession agreements be migrated to new agreements that comply with the newly proposed law. On April 29, 2005, the Bolivian senate approved a modified version of the bill which, among other things, allows for reducing the new production tax rate on marginal and minor fields. The reduced rate and the term minor field are not defined in the bill. On May 5, 2005, the lower house of congress approved the bill as modified by the senate. President Mesa now has ten days to, among other things, make line item vetoes, propose modifications or approve the bill into law. Until the final version of the bill becomes law, we are unable to predict the impact on our operations.

During April 2005, the M.A.S. and other opposition parties questioned the legality of concession agreements, which were signed by the state oil company, Y.P.F.B. and the companies. We believe the concession agreements between the Bolivian government and us are valid and the question of their legality is without merit.

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. This tax has not had a significant impact on our operations and we do not expect it to have a significant impact on future periods.

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

On January 7, 2005, the Bolivian government issued Executive Decree 27967, stating that prices in the internal Bolivian gas distribution market could not exceed the average of the last three natural gas purchase agreements registered with the Superintendent of Hydrocarbons. In accordance with the Executive Decree on February 3, 2005, the Superintendent of Hydrocarbons issued Resolution SSDH 124-2005 determining the new maximum price in the Bolivian gas distribution market to be US$0.80 per Mcf, effective February 4, 2005, and its terms are effective until April 30, 2006. All natural gas purchase agreements in place with Bolivian local distribution companies prior to the resolution are required to lower their price in accordance with the terms of the new resolution. In the remainder of 2005 and in 2006, we have contracted volumes of 4.6 Bcf and 0.3 Bcf, respectively which are impacted by the decree. Also, we expect that our 2005 and 2006 revenues will be reduced by approximately $230,000 and $100,000, respectively, as a result of the current resolution.

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Bolivian gas markets have historically been limited to exports to Brazil via the Bolivia-to-Brazil gas pipeline and to those internal gas sales necessary to meet Bolivian industrial and consumer demand. We are working to increase sales in both of these areas and we currently have capacity to deliver gas volumes in excess of our contracted volumes. The current daily productive capacity of our properties in Bolivia is approximately 46 MMcf of gas, gross and 28 MMcf of gas, net. During the past several years, Bolivian gas reserve growth has exceeded the demand growth in Bolivia’s existing markets. Therefore, we believe substantial competition for gas markets will continue at least until new market areas are established. On April 21, 2004, the Argentine and Bolivian governments agreed to a gas supply arrangement for 141 MMcf per day of gas to Argentina for a six-month period beginning in May 2004, and in July 2004, the government signed a letter of intent to increase those exports by 88 MMcf per day. As a result, our Bolivian sales volumes increased. However, it is unclear if these increased sales volumes will continue in future periods. On October 14, the Argentine and Bolivian governments signed a letter of intent for Bolivia to export up to 706 MMcf per day, which is estimated to commence during 2006. This additional quantity is subject to the successful conclusion of a Hydrocarbon Law reform which proves to be acceptable to investors. With the June 2004 approval from the Bolivian public in the referendum on the matter of gas exports, we believe that new projects, such as exports to Mexico and the U.S., as well as additional exports to Argentina, will become feasible in the future, also subject to the successful conclusion of a Hydrocarbon Law reform which proves to be acceptable to investors.

In 1987, the Boliviano replaced the peso and became Bolivia’s currency. The exchange rate is set daily by the government’s exchange house, “The Bolsin”, which is under the supervision of the Bolivian Central Bank. Foreign exchange transactions are not subject to any controls. The exchange rate at March 31, 2005, was 8.1 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.

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 introduced a floating exchange rate system in 1996, which had helped the Rial to stabilize in real terms. The Yemeni central bank has often attempted to stabilize the exchange rate in times of trouble through interest rate policy and the auctioning of foreign exchange to moneychangers and banks. The exchange rate on March 31, 2005, was 181.12 Rials to the U.S. dollar, after experiencing a gradual depreciation during 2004. Since our oil revenues are received in U.S. dollars, we believe that any currency risk associated with our Yemen operations would not have a material impact on our financial position or results of operations.

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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. Further concerns about continued implementations of economic reform measures as well as increased government control are ongoing business risks. We have evaluated the risk of operating in Yemen and we believe that the current risks are manageable.

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ITEM 4. CONTROLS AND PROCEDURES

We carried out an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) of the Securities Exchange Act of 1934, as amended) as of March 31, 2005. Our management, including the Chief Executive Officer and Chief Financial Officer, does not expect that our disclosure controls and procedures or our internal controls will prevent all error and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. The inherent limitations in all control systems include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the control. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. Based upon the 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.

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PART II

OTHER INFORMATION

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Item 1.

Legal Proceedings

For information regarding legal proceedings, see our Form 10-K for the year ended December 31, 2004.

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds

Not applicable

Item 3.

Defaults Upon Senior Securities

Not applicable

Item 4.

Submission of Matters to a Vote of Security Holders

Not applicable

Item 5.

Other Information

Not applicable

Item 6.

Exhibits

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


10.1		Amendment No. 7 to Vintage Petroleum, Inc. 1990 Stock Plan dated January 27, 2005, (filed as Exhibit 10.9 to our report on Form 10-K for the year ended December 31, 2004, filed March 11, 2005).

10.2		Agreement and release dated as of March 31, 2005, between us and William E. Dozier.

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

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

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

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

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Signatures

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


				VINTAGE PETROLEUM, INC.
				(Registrant)

DATE: May 6, 2005

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

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Exhibit Index


Exhibit Number		Description

10.1		Amendment No. 7 to Vintage Petroleum, Inc. 1990 Stock Plan dated January 27, 2005, (filed as Exhibit 10.9 to our report on Form 10-K for the year ended December 31, 2004, filed March 11, 2005).

10.2		Agreement and release dated as of March 31, 2005, between us and William E. Dozier.

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.