Edgar Filing: VINTAGE PETROLEUM INC

Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended September 30, 2002

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

Class		Outstanding at November 13, 2002
Common Stock, $.005 Par Value		63,320,272

PART I

FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

VINTAGE PETROLEUM, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In thousands, except shares

and per share amounts)

(Unaudited)

ASSETS

	September 30, 2002		December 31, 2001
CURRENT ASSETS:
Cash and cash equivalents	$	16,375	$	14,568
Accounts receivable—
Oil and gas sales		94,782		74,435
Joint operations and other		11,836		12,041
Derivative financial instruments receivable		—		4,701
Prepaids and other current assets		27,850		37,635
Assets to be sold		—		9,172

Total current assets		150,843		152,552

PROPERTY, PLANT AND EQUIPMENT, at cost:
Oil and gas properties, successful efforts method		2,538,295		2,490,666
Oil and gas gathering systems and plants		22,368		20,508
Other		26,472		25,494

		2,587,135		2,536,668
Less accumulated depreciation, depletion and amortization		922,981		809,522

		1,664,154		1,727,146

GOODWILL, net		96,861		156,990

OTHER ASSETS, net		55,238		60,100

	$	1,967,096	$	2,096,788

See notes to unaudited consolidated financial statements.

VINTAGE PETROLEUM, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In thousands, except shares

and per share amounts)

(Unaudited)

LIABILITIES AND STOCKHOLDERS’ EQUITY

	September 30, 2002			December 31, 2001
CURRENT LIABILITIES:
Revenue payable	$	27,500		$	25,625
Accounts payable—trade		37,944			61,047
Current income taxes payable		17,218			21,638
Short-term debt		5,455			17,320
Derivative financial instruments payable		11,491			—
Other payables and accrued liabilities		62,243			46,172

Total current liabilities		161,851			171,802

LONG-TERM DEBT		924,215			1,010,673

DEFERRED INCOME TAXES		171,090			166,662

OTHER LONG-TERM LIABILITIES		6,100			18,208

STOCKHOLDERS’ EQUITY, per accompanying statement:
Preferred stock, $.01 par, 5,000,000 shares authorized, zero shares issued and outstanding		—			—
Common stock, $.005 par, 160,000,000 shares authorized, 63,404,972 and 63,081,322 shares issued and 63,328,972 and 63,081,322 outstanding, respectively		317			315
Capital in excess of par value		326,163			324,077
Retained earnings		409,451			428,443
Accumulated other comprehensive loss		(29,426	)		(21,632	)

		706,505			731,203
Less unamortized cost of restricted stock awards		2,665			1,760

		703,840			729,443

	$	1,967,096		$	2,096,788

See notes to unaudited consolidated financial statements.

VINTAGE PETROLEUM, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share amounts)

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2002			2001			2002			2001
REVENUES:
Oil and gas sales	$	157,137		$	173,227		$	438,265		$	588,610
Gas marketing		15,482			20,481			45,215			115,295
Oil and gas gathering and processing		1,671			794			4,524			15,100
Gain (loss) on disposition of assets		(450	)		—			17,259			24
Foreign currency exchange gain (loss)		(694	)		(544	)		3,408			(301	)
Other income (expense)		(562	)		(66	)		674			2,673

		172,584			193,892			509,345			721,401

COSTS AND EXPENSES:
Lease operating, including production and export taxes		52,229			58,314			157,269			159,062
Exploration costs		5,638			9,516			21,566			15,178
Gas marketing		15,192			20,540			43,937			112,163
Oil and gas gathering and processing		1,795			1,299			5,077			15,776
General and administrative		12,258			12,954			38,258			36,883
Depreciation, depletion and amortization		43,767			48,072			140,236			116,060
Impairment of oil and gas properties		—			10,706			—			10,706
Amortization of goodwill		—			4,417			—			7,191
Interest		20,048			19,867			58,226			46,658
Loss on early extinguishment of debt		—			—			8,154			—

		150,927			185,685			472,723			519,677

Income from continuing operations before income taxes and cumulative effect of change in accounting principle		21,657			8,207			36,622			201,724

PROVISION (BENEFIT) FOR INCOME TAXES:
Current		7,210			6,370			19,004			56,565
Deferred		(2,307	)		(4,457	)		(16,402	)		15,650

		4,903			1,913			2,602			72,215

Income from continuing operations before cumulative effect of change in accounting principle		16,754			6,294			34,020			129,509
INCOME (LOSS) FROM DISCONTINUED OPERATIONS, net of tax		14,941			(52	)		14,485			(350	)

Income before cumulative effect of change in accounting principle		31,695			6,242			48,505			129,159
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE		—			—			(60,547	)		—

NET INCOME (LOSS)	$	31,695		$	6,242		$	(12,042	)	$	129,159

See notes to unaudited consolidated financial statements.

VINTAGE PETROLEUM, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share amounts)

(Unaudited)

	Three Months Ended September 30,				Nine Months Ended September 30,
	2002		2001		2002			2001
BASIC INCOME (LOSS) PER SHARE:
Income from continuing operations before cumulative effect of change in accounting principle	$	.26	$	.10	$	.54		$	2.06
Income (loss) from discontinued operations		.24		—		.23			(.01	)

Income before cumulative effect of change in accounting principle		.50		.10		.77			2.05
Cumulative effect of change in accounting principle		—		—		(.96	)		—

Net income (loss)	$	.50	$	.10	$	(.19	)	$	2.05

DILUTED INCOME (LOSS) PER SHARE:
Income from continuing operations before cumulative effect of change in accounting principle	$	.26	$	.10	$	.53		$	2.03
Income (loss) from discontinued operations		.24		—		.23			(.01	)

Income before cumulative effect of change in accounting principle		.50		.10		.76			2.02
Cumulative effect of change in accounting principle		—		—		(.95	)		—

Net income (loss)	$	.50	$	.10	$	(.19	)	$	2.02

Weighted average common shares outstanding:
Basic		63,335		63,080		63,181			63,003

Diluted		63,977		64,068		63,661			64,092

See notes to unaudited consolidated financial statements.

VINTAGE PETROLEUM, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY

AND COMPREHENSIVE INCOME (LOSS)

FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2002

(In thousands)

(Unaudited)

	Common Stock			Treasury Stock	Capital In Excess of Par Value			Unamortized Restricted Stock Awards			Retained Earnings			Accumulated Other Comprehensive Income (Loss)
	Shares	Amount		Shares	Capital In Excess of Par Value			Unamortized Restricted Stock Awards			Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total
BALANCE AT DECEMBER 31, 2001	63,081	$	315	—	$	324,077		$	(1,760	)	$	428,443		$	(21,632	)	$	729,443
Comprehensive income (loss):
Net loss	—		—	—		—			—			(12,042	)		—			(12,042	)
Foreign currency translation adjustment	—		—	—		—			—			—			1,585			1,585
Change in value of derivatives, net of tax	—		—	—		—			—			—			(9,379	)		(9,379	)

Total comprehensive loss																		(19,836	)
Exercise of stock options and resulting tax effects	63		1	—		513			—			—			—			514
Issuance of restricted stock	261		1	—		2,879			(2,880	)		—			—			—
Amortization of restricted stock awards	—		—	—		—			1,126			—			—			1,126
Forfeiture of restricted stock and other	—		—	76		(1,306	)		849			—			—			(457	)
Cash dividends declared ($.115 per share)	—		—	—		—			—			(6,950	)		—			(6,950	)

BALANCE AT SEPTEMBER 30, 2002	63,405	$	317	76	$	326,163		$	(2,665	)	$	409,451		$	(29,426	)	$	703,840

See notes to unaudited consolidated financial statements.

VINTAGE PETROLEUM, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)

	Nine Months Ended September 30,
	2002			2001
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	(12,042	)	$	129,159
Adjustments to reconcile net income (loss) to cash provided by operating activities—
(Income) loss from discontinued operations, net of tax		(14,485	)		350
Cumulative effect of change in accounting principle		60,547			—
Depreciation, depletion and amortization		140,236			116,060
Impairment of oil and gas properties		—			10,706
Amortization of goodwill		—			7,191
Exploration costs		21,566			15,178
Provision (benefit) for deferred income taxes		(16,402	)		15,650
Foreign currency exchange (gain) loss		(3,408	)		301
Gain on dispositions of assets		(17,259	)		(24	)
Loss on early extinguishment of debt		8,154			—
Other non-cash items		188			462

		167,095			295,033
Decrease (increase) in receivables		(31,274	)		62,026
Increase (decrease) in payables and accrued liabilities		13,343			(67,529	)
Other working capital changes		7,321			(21,549	)

Cash provided by operating activities		156,485			267,981

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures—
Oil and gas properties		(91,077	)		(214,479	)
Gathering systems and other		(4,384	)		(3,971	)
Proceeds from sale of oil and gas properties		22,856			24
Purchase of companies, net of cash acquired		—			(478,417	)
Proceeds from sale of company, net of cash sold		39,314			—
Other		(1,216	)		(9,644	)

Cash used by investing activities		(34,507	)		(706,487	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Issuance of common stock		514			1,216
Issuance of 8 1/4% Senior Notes due 2012		350,000			—
Partial redemption of 9% Senior Subordinated Notes due 2005		(103,000	)		—
Issuance of 7 7/8% Senior Subordinated Notes due 2011		—			199,930
Advances on revolving credit facility and other borrowings		208,827			719,090
Payments on revolving credit facility and other borrowings		(557,192	)		(480,880	)
Dividends paid		(6,952	)		(5,981	)
Transaction costs on debt issuance		(9,887	)		—

Cash provided (used) by financing activities		(117,690	)		433,375

EFFECT OF EXCHANGE RATE CHANGES ON CASH		(2,481	)		(363	)

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		1,807			(5,494	)
CASH AND CASH EQUIVALENTS, beginning of period		14,568			19,506

CASH AND CASH EQUIVALENTS, end of period	$	16,375		$	14,012

See notes to unaudited consolidated financial statements.

VINTAGE PETROLEUM, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2002 and 2001

1. GENERAL

The accompanying financial statements are unaudited. The consolidated financial statements include the accounts of Vintage Petroleum, Inc. and its wholly- and majority-owned subsidiaries and its proportionately consolidated general partner and limited partner interests in various joint ventures and partnerships (collectively, the “Company”). Management believes that all material adjustments (consisting of only normal recurring adjustments) necessary for a fair presentation have been made. Certain 2001 amounts have been reclassified to conform with the 2002 presentation, including reclassifications required for presentation of the discontinued operations discussed in Note 9. All significant intercompany accounts and transactions have been eliminated in consolidation.

On May 2, 2001, the Company completed the acquisition of Canadian-based Genesis Exploration Ltd. (“Genesis”) for total consideration of $617 million, including transaction costs and the assumption of the net indebtedness of Genesis at closing. The cash portion of the acquisition price was paid through advances under the Company’s revolving credit facility and cash on hand. The acquisition of Genesis was accounted for using purchase accounting and, as such, only five months of Genesis activity is included in the Company’s statement of operations for the nine months ended September 30, 2001.

The preparation of financial statements in conformity with accounting principles generally accepted in the United States (“GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. These financial statements and notes should be read in conjunction with the 2001 audited financial statements and related notes included in the Company’s 2001 Annual Report on Form 10-K, Item 8. Financial Statements and Supplementary Data.

2. SIGNIFICANT ACCOUNTING POLICIES

Oil and Gas Properties

Under the successful efforts method of accounting, the Company capitalizes all costs related to property acquisitions and successful exploratory wells, all development costs and the costs of support equipment and facilities. All costs related to unsuccessful exploratory wells are expensed when such wells are determined to be non-productive; other exploration costs, including geological and geophysical costs, are expensed as incurred. The Company recognizes gains or losses on the sale of properties on a field basis.

Unproved leasehold costs are capitalized and reviewed periodically for impairment on a property-by-property basis, considering factors such as future drilling and exploitation plans and lease terms. Costs related to impaired prospects are charged to expense. An impairment expense could result if oil and gas prices decline in the future or if downward reserve revisions are recorded, as it may not be economic to develop some of these unproved properties.

As of September 30, 2002, the Company has unproved oil and gas property costs of approximately $102.9 million, consisting of undeveloped leasehold costs of $76.3 million, including $56.2 million in Canada, and unevaluated exploratory drilling costs of $26.6 million. Approximately $22.0 million of the total unevaluated costs are associated with the Company’s Yemen drilling program.

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

In August 2001, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations. Currently, the Company accrues future abandonment costs of wells and related facilities through its depreciation calculation and includes the cumulative accrual in accumulated depreciation. The new standard will require that the Company record the discounted fair value of the retirement obligation as a liability at the time a well is drilled or acquired. A corresponding amount will be capitalized as part of the related property’s carrying amount. The capitalized asset retirement cost will be amortized to expense on the unit-of-production method based on proved developed reserves. The liability will accrete over time with a charge to interest expense. The Company will adopt the new standard effective January 1, 2003. While the new standard will require that the Company change its accounting for such abandonment obligations, the Company has not completed its evaluation of the impact of the new standard on its financial statements.

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. No impairment provision related to proved oil and gas properties was required for the first nine months or the third quarter of 2002. The Company recorded a $9.1 million impairment charge during the third quarter of 2001 related to certain domestic properties that were held for sale during the fourth quarter of 2001. The results of operations from these properties is immaterial to the accompanying consolidated statements of operations. The Company also recorded a $1.6 million impairment charge during the third quarter of 2001 related to certain Canadian producing oil and gas properties. No other impairment charges were recorded in the first nine months of 2001.

On January 1, 2002, the Company adopted the provisions of Statement of Financial Accounting Standards No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets (“SFAS No. 144”). SFAS No. 144 creates accounting and reporting standards to establish a single accounting model, based on the framework established in Statement of Financial Accounting Standards No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of, for long-lived assets to be disposed of by sale. The adoption of SFAS No. 144 did not have a material impact on the Company’s financial position or results of operations. See further discussion of discontinued operations in Note 9.

Goodwill

Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in the purchase of Genesis, which was accounted for using the purchase method of accounting. In 2001, goodwill was amortized using the unit-of-production basis over the total proved reserves acquired. Accumulated amortization was approximately $11.9 million at December 31, 2001.

On July 20, 2001, the FASB issued Statement of Financial Accounting Standards No. 141, Business Combinations (“SFAS No. 141”), and Statement of Financial Accounting Standards No. 142, Goodwill and Other Intangible Assets (“SFAS No. 142”). SFAS No. 141 requires all business combinations initiated after June 30, 2001, to be accounted for using the purchase method of accounting. Under SFAS No. 142, goodwill is no longer subject to amortization. Rather, goodwill is subject to at least an annual assessment for impairment by applying a fair-value based test. Additionally, an acquired intangible asset should be separately recognized if the benefit of the intangible asset is obtained through contractual or other legal rights, or if the intangible asset can be sold, transferred, licensed, rented or exchanged, regardless of the acquirer’s intent to do so.

The Company adopted SFAS No. 141 and SFAS No. 142 effective January 1, 2002, resulting in the elimination of goodwill amortization from statements of operations in future periods. Upon adoption, the Company recorded an impairment charge of $60.5 million related to the goodwill of its Canadian operations as a cumulative effect of a change in accounting principle in its statement of operations (see Note 3). The Company will assess its Canadian operations’ goodwill as of December 31 each year and will perform interim tests for goodwill impairment should an event occur or circumstances change that would more likely than not reduce the fair value of the Canadian reporting unit below its carrying value.

Hedging

The Company periodically uses hedges to reduce the impact of oil and gas price fluctuations. All derivative financial instruments are carried at fair value on the balance sheet. For derivative instruments that qualify as cash flow hedges, the effective portion of the gain or loss on a derivative instrument is reported as a component of other comprehensive income and reclassified into sales revenue in the same period or periods during which the hedged forecasted transaction affects earnings. The effective portion is determined by comparing the cumulative change in fair value of the derivative to the cumulative change in the present value of the expected cash flows of the item being hedged. To the extent the cumulative change in the derivative exceeds the cumulative change in the present value of expected cash flows, the excess, if any, is recognized currently in earnings. If the cumulative change in present value of the expected cash flows exceeds the change in fair value of the derivative, the difference is ignored. Gains or losses from derivative financial instruments that do not qualify for accounting treatment as hedges are recognized currently as other income or expense. The cash flows from such agreements are included in operating activities in the consolidated statements of cash flows.

In June 1998, the FASB issued Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended in June 1999 by Statement No. 137, Accounting for Derivative Instruments and Hedging Activities—Deferral of the Effective Date of FASB Statement No. 133 and in June 2000 by Statement No. 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities—an amendment of FASB Statement No. 133 (“SFAS No. 133”). SFAS No. 133 established accounting and reporting standards requiring that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded in the balance sheet as either an asset or liability measured at its fair value. SFAS No. 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.

Upon adoption of SFAS No. 133 on January 1, 2001, the Company recorded a transition receivable of approximately $18.5 million related to cash flow hedges in place that are used to reduce the volatility in commodity prices for portions of the Company’s forecasted oil production. Additionally, the Company recorded, net of tax, an increase to accumulated other comprehensive income in the Stockholders’ Equity section of the balance sheet of approximately $14.9 million. During the first nine months of 2001, $13.3 million of the original amount recorded to accumulated other comprehensive income was taken to the statement of operations as the physical transactions being hedged were finalized. At September 30, 2002, the Company had a net derivative financial instrument payable of $11.5 million related to 2002 and 2003 cash flow hedges in place. The Company recorded losses related to the assessment of hedge effectiveness of $0.1 million and $0.3 million for the nine months and three months ended September 30, 2002, respectively, and $0.2 million and $0.2 million for the nine months and three months ended September 30, 2001, respectively. These losses are included in “Other income (expense)” in the accompanying consolidated statements of operations. During 2001 and 2002, the Company did not discontinue any hedges because of the probability that the original forecasted transaction would not occur.

Statements of Cash Flows

During the nine months ended September 30, 2002 and 2001, the Company made cash payments for interest totaling approximately $35.2 million, and $31.2 million, respectively. Cash payments made for U.S. income taxes of $6.3 million and $12.9 million were made during the first nine months of 2002 and 2001, respectively. The Company made cash payments of $9.3 million and $67.9 million during the first nine months of 2002 and 2001, respectively, for foreign income taxes, primarily in Argentina.

Earnings Per Share

Basic earnings per common share were computed by dividing net income by the weighted average number of shares outstanding during the period. Diluted earnings per common share for all periods presented were computed assuming the exercise of all dilutive options, as determined by applying the treasury stock method. In periods in which a loss from continuing operations occurs, no options are assumed to be exercised in computing diluted earnings per common share.

For the three month period ended September 30, 2002 and 2001, the Company had outstanding stock options for 3,367,200 and 2,620,000 additional shares of the Company’s common stock, respectively, with an average exercise price of $18.42 and $20.34, respectively, which were anti-dilutive. For the nine month period ended September 30, 2002 and 2001, the Company had outstanding stock options for 4,123,962 and 1,420,333 additional shares of the Company’s common stock, respectively, with an average exercise price of $16.40 and $20.76, respectively, which were anti-dilutive. These shares will dilute basic earnings per share in the future, if exercised, and may impact diluted earnings per share in the future, depending on the market price of the Company’s common stock.

General and Administrative Expense

The Company receives fees for the operation of jointly-owned oil and gas properties and records such reimbursements as reductions of general and administrative expense. Such fees totaled approximately $4.7 million and $5.2 million for the first nine months of 2002 and 2001, respectively, and approximately $1.9 million and $1.8 million for the third quarters of 2002 and 2001, respectively.

Lease Operating Expense

Included in lease operating expenses are the following items (in thousands):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2002		2001		2002		2001
Argentina oil export taxes	$	6,510	$	—	$	17,124	$	—
Transportation and storage expenses		3,142		4,329		9,287		10,744
Gross production taxes		2,433		3,723		7,566		13,384

On February 13, 2002, the Argentine government announced a 20 percent tax on oil exports, effective March 1, 2002, which is reflected in lease operating expenses. The tax is limited by law to a term of no more than five years. The tax of 20 percent is applied on the sales value after the tax, thus the net effect is 16.7 percent.

Foreign Currency

Foreign currency transactions and financial statements are translated in accordance with Statement of Financial Accounting Standards No. 52, Foreign Currency Translation. All of the Company’s subsidiaries use the U.S. dollar as their functional currency, except for the Company’s Canadian subsidiaries, which use the Canadian dollar. Adjustments arising from translation of the Canadian subsidiaries’ financial statements are reflected in accumulated other comprehensive income. Transaction gains and losses that arise from exchange rate fluctuations applicable to transactions denominated in a currency other than the Company’s or its subsidiaries’ functional currency are included in the results of operations as incurred.

Beginning in 1991, the Argentine peso (“peso”) was tied to the U.S. dollar at a rate of one peso to one U.S. dollar. As a result of economic instability and substantial withdrawals from the banking system, in early December 2001, the Argentine government instituted restrictions that prohibit foreign money transfers without Central Bank approval and only allow cash withdrawals from bank accounts for personal transactions in small amounts with certain limited exceptions. While the legal exchange rate remained at one peso to one U.S. dollar, financial institutions were allowed to conduct only limited activity due to these controls, and currency exchange activity was effectively halted except for personal transactions in small amounts. These actions by the government resulted in a devaluation of the peso in December 2001.

On January 6, 2002, the Argentine government abolished the one peso to one U.S. dollar legal exchange rate. On January 9, 2002, Decree 71 created a dual exchange market whereby foreign trade transactions were conducted at an official exchange rate of 1.4 pesos to one U.S. dollar and other transactions were conducted in a free floating exchange market. On February 8, 2002, Decree 260 unified the dual exchange markets and allowed the peso to float freely with the U.S. dollar. The exchange rate at September 30, 2002, was 3.75 pesos to one U.S. dollar.

On February 3, 2002, Decree 214 required certain contracts that were previously payable in U.S. dollars to be payable in pesos. Pursuant to an emergency law passed on January 10, 2002, U.S. dollar obligations between private parties due after January 6, 2002, were to be liquidated in pesos at a negotiated rate of exchange which reflects a sharing of the impact of the devaluation. The Company’s settlements in pesos of the existing U.S. dollar-denominated agreements have been completed, thus future periods will not be impacted by this mandate. This government-mandated “equitable sharing” of the impact of the devaluation resulted in a reduction in oil revenues from domestic sales in Argentina for the first nine months of 2002 of approximately $8 million, or $0.95 per Argentine Bbl or $0.50 per total Company Bbl. The Company’s Argentine lease operating costs were also reduced as a result of this mandate and the positive impact of devaluation on the Company’s peso-denominated costs essentially offset the negative impact on Argentine oil revenues.

Absent the emergency law that was enacted on January 10, 2002, the devaluation of the peso would have had no effect on the Company’s U.S. dollar-denominated payables and receivables at December 31, 2001. A $0.9 million gain resulting from the involuntary conversion was recorded in January 2002 and is reflected in “Other income (expense)” in the accompanying consolidated statement of operations. The translation of peso-denominated balances at September 30, 2002, and peso-denominated transactions during the nine months ended September 30, 2002, resulted in a foreign currency exchange gain of $3.4 million.

Comprehensive Income (Loss)

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2002			2001			2002			2001
Net income (loss)	$	31,695		$	6,242		$	(12,042	)	$	129,159
Foreign currency translation adjustments		(29,847	)		(26,493	)		1,585			(20,311	)
Changes in value of derivatives, net of tax		(6,132	)		(263	)		(9,379	)		(10,336	)

Comprehensive income (loss)	$	(4,284	)	$	(20,514	)	$	(19,836	)	$	98,512

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

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2002			2001			2002			2001
Reclassification of cumulative effect of adoption of SFAS No. 133 for (gains) losses included in net income (loss)	$	—		$	(103	)	$	—		$	(15,874	)
Unrealized gain (loss) during the period		(10,815	)		2,926			(18,841	)		6,174
Reclassification adjustment for (gains) losses included in net income (loss)		287			(2,900	)		3,048			(2,900	)

		(10,528	)		(77	)		(15,793	)		(12,600	)
Income tax expense (benefit)		(4,396	)		186			(6,414	)		(2,264	)

Changes in value of derivatives, net of tax	$	(6,132	)	$	(263	)	$	(9,379	)	$	(10,336	)

Other Recent Pronouncements

On April 30, 2002, the FASB issued Statement of Financial Accounting Standards No. 145, Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections (“SFAS No. 145”). SFAS No. 145 updates, clarifies and simplifies existing accounting pronouncements. Among other items, it rescinds previous accounting rules which required all gains and losses from extinguishment of debt to be aggregated and, if material, classified as an extraordinary item, net of related income tax effect. The Company has adopted the provisions of SFAS No. 145 and, accordingly, has classified an $8.2 million ($5.0 million net of tax) loss on the early extinguishment of debt (see Note 4) as a charge to income from continuing operations in its statements of operations for the nine months ended September 30, 2002. The adoption of SFAS No. 145 did not have any other material impact on the Company’s financial position or results of operations.

On July 30, 2002, the FASB issued Statement of Financial Accounting Standards No. 146, Accounting for Costs Associated with Exit or Disposal Activities. The standard requires companies to recognize costs associated with exit or disposal activities when they are incurred rather than at the date of a commitment to an exit or disposal plan. The provisions of this statement are to be applied prospectively to exit or disposal activities initiated after December 31, 2002. The Company does not expect the adoption of this standard to have a material impact on the Company’s financial position or results of operations.

3. GOODWILL

Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in the purchase of Genesis. All of the Company’s goodwill is related to the Company’s Canadian reporting unit, which is consistent with the Canadian segment identified in Note 7. Effective January 1, 2002, the Company adopted the provisions of SFAS No. 142. SFAS No. 142 changes the accounting for goodwill from an amortization method to an impairment assessment only method.

Under the new rule, the Company had a six-month transitional period from the effective date of the adoption to perform an initial assessment of whether there was an indication that the carrying value of goodwill was impaired. This assessment was made by comparing the fair value of the Canadian reporting unit, as determined in accordance with SFAS No. 142, to its book value. If the fair value was less than the book value, an impairment was indicated and the Company would be required to perform a second test no later than December 31, 2002, to measure the amount of the impairment. Any initial impairment is to be taken as a cumulative effect of change in accounting principle retroactive to January 1, 2002. In future years, this assessment must be conducted at least annually and any such impairment must be recorded as a charge to operating earnings.

The Company completed its initial assessment in the second quarter and recorded a non-cash charge of $60.5 million. Decreases in oil and gas price expectations from the May 2, 2001, acquisition of Genesis to January 1, 2002, and certain downward revisions recorded to the Company’s Canadian oil and gas reserves at December 31, 2001, were the primary factors that led to the goodwill impairment. The charge was recorded as a cumulative effect of change in accounting principle retroactive to January 1, 2002, in accordance with the provisions of SFAS No. 142.

The Company engaged an independent appraisal firm to determine the fair value of its Canadian reporting unit as of January 1, 2002. This fair value determination was made principally on the basis of present value of future after tax cash flows, although other valuation methods were considered. The book value of the Canadian reporting unit exceeded the fair value determined by the independent appraisal firm, indicating a possible impairment of goodwill. The Company then calculated the implied fair value of the goodwill by deducting the fair value of all tangible and intangible net assets of the Canadian reporting unit from the fair value of the Canadian reporting unit determined in step one of the assessment. The carrying value of the goodwill exceeded this calculated implied fair value of the goodwill at January 1, 2002, resulting in the impairment charge.

The Company has no intangible assets other than the goodwill of its Canadian reporting unit, which has a net book value (after the cumulative effect of change in accounting principle) of $96.9 million as of September 30, 2002. The changes in the carrying amount of goodwill for the nine months ended September 30, 2002 are as follows (in thousands):

Balance, December 31, 2001	$	156,990
Impairment		(60,547	)
Changes in foreign currency exchange rates		418

Balance, September 30, 2002	$	96,861

The unaudited results of operations presented below for the three months and nine months ended September 30, 2001, reflect the operations of the Company had the Company adopted the non-amortization provisions of SFAS No. 142 effective January 1, 2001 (in thousands, except per share amounts):

	Three Months Ended September 30, 2001		Nine Months Ended September 30, 2001
Reported net income	$	6,242	$	129,159
Goodwill amortization		4,417		7,191

Adjusted net income	$	10,659	$	136,350

Adjusted basic income per share	$	0.17	$	2.16

Adjusted diluted income per share	$	0.17	$	2.13

As noted above, SFAS No. 142 requires the cumulative effect of change in accounting principle be recorded retroactive to January 1, 2002. The following table reflects the impact of this accounting change on selected financial data for the three months ended March 31, 2002 (in thousands, except per share data):

	As Reported			As Adjusted
Loss before cumulative effect of change in accounting principle	$	(5,620	)	$	(5,620	)
Cumulative effect of change in accounting principle		—			(60,547	)

Net loss	$	(5,620	)	$	(66,167	)

Basic Loss Per Share:
Loss before cumulative effect of change in accounting principle	$	(.09	)	$	(.09	)
Cumulative effect of change in accounting principle		—			(.96	)

Net loss	$	(.09	)	$	(1.05	)

Diluted Loss Per Share:
Loss before cumulative effect of change in accounting principle	$	(.09	)	$	(.09	)
Cumulative effect of change in accounting principle		—			(.96	)

Net loss	$	(.09	)	$	(1.05	)

4. LONG-TERM DEBT

Long-term debt at September 30, 2002, and December 31, 2001, consisted of the following:

(In thousands)	September 30, 2002		December 31, 2001
Revolving credit facility	$	74,900	$	411,400
8¹/4% Senior Notes due 2012		350,000		—
Senior Subordinated Notes:
9% Notes due 2005, less unamortized discount		49,911		149,837
8⁵/8% Notes due 2009, less unamortized discount		99,467		99,503
9³/4% Notes due 2009		150,000		150,000
7⁷/8% Notes due 2011, less unamortized discount		199,937		199,933

	$	924,215	$	1,010,673

The Company had $25.8 million and $9.5 million of accrued interest payable related to its long-term debt at September 30, 2002, and December 31, 2001, respectively, included in other payables and accrued liabilities in the accompanying balance sheets.

On May 2, 2002, the Company issued, through a Rule 144A offering, $350 million of its 8¹/4% Senior Notes due 2012 (the “8¹/4% Notes”). All of the net proceeds were used to repay a portion of the outstanding balance under the Company’s revolving credit facility and to redeem $100 million of the Company’s outstanding 9% Senior Subordinated Notes due 2005 (the “9% Notes”). The 8¹/4% Notes are redeemable at the option of the Company, in whole or in part, at any time on or after May 1, 2007. In addition, on or before May 1, 2005, the Company may redeem up to 35 percent of the 8¹/4% Notes with the proceeds of certain underwritten public offerings of the Company’s common stock. The 8¹/4% Notes mature on May 1, 2012, with interest payable semi-annually on May 1 and November 1, commencing November 1, 2002.

Upon a change in control of the Company (as defined in the applicable indentures), holders of the 8¹/4% Notes and the Company’s senior subordinated notes (collectively, the “Notes”) may require the Company to repurchase all or a portion of the Notes at a purchase price equal to 101 percent of the principal amount thereof, plus accrued and unpaid interest. The indentures for the Notes contain limitations on, among other things, additional indebtedness and liens, the payment of dividends and other distributions, certain investments and transfers or sales of assets.

In conjunction with the offering of 8¹/4% Notes, the Company entered into a new $300 million revolving credit facility (the “Bank Facility”), which was used to refinance its previously existing credit facility and to provide funds for ongoing operating and general corporate needs. The Bank Facility consists of a three-year senior secured credit facility with availability governed by a borrowing base determination.

The borrowing base (currently $300 million) is based on the banks’ evaluation of the Company’s oil and gas reserves. The amount available to be borrowed under the Bank Facility is limited to the lesser of the borrowing base or the facility size, which is also currently set at $300 million. The next borrowing base redetermination will be in November 2002. At September 30, 2002, the unused availability under the Bank Facility was approximately $207 million.

Outstanding advances under the Bank Facility bear interest payable quarterly at a floating rate based on Bank of Montreal’s alternate base rate (as defined therein) or, at the Company’s option, at a fixed rate for up to six months based on the Eurodollar market rate (“LIBOR”). The Company’s interest rate increments above the alternate base rate and LIBOR vary based on the level of outstanding senior secured debt to the borrowing base. In addition, the Company must pay a commitment fee of 0.50 percent per annum on the unused portion of the banks’ commitment. Total outstanding advances at September 30, 2002, were $74.9 million at an average interest rate of 3.6 percent.

The Company’s borrowing base will be redetermined on a semiannual basis by the banks based upon their review of the Company’s oil and gas reserves. If the sum of outstanding senior secured debt exceeds the borrowing base, as redetermined, the Company must repay such excess. Any principal advances outstanding are due at maturity on May 2, 2005. The Bank Facility is secured by a first priority lien on the Company’s U.S. oil and gas properties constituting at least 80 percent of the present value of the Company’s U.S. proved reserves owned now or in the future. The Bank Facility will be guaranteed by any of the Company’s existing and future U.S. subsidiaries that grant a lien on oil and gas properties under the Bank Facility.

The terms of the Bank Facility impose certain restrictions on the Company regarding the pledging of assets and limitations on additional indebtedness. In addition, the Bank Facility requires the maintenance of a minimum current ratio (as defined therein) and tangible net worth (as defined therein) of not less than $425 million plus 75 percent of the net proceeds of any future equity offerings less any impairment write downs required by GAAP or by the Securities and Exchange Commission and excluding any impact related to SFAS No. 133.

In conjunction with the elimination of the Company’s previously existing revolving credit facility and the partial redemption of the 9% Notes, the Company was required to expense certain associated deferred financing costs and discounts. This $5.2 million non-cash charge, along with a $3.0 million cash charge for the call premium on the 9% Notes, resulted in a one-time charge of approximately $8.2 million ($5.0 million net of tax) in the second quarter of 2002.

5. CAPITAL STOCK

On March 16, 1999, the Company’s Board of Directors adopted a stockholder rights plan and declared a dividend distribution of one preferred share purchase right (a “Right”) for each outstanding share of the Company’s common stock, to stockholders of record on April 5, 1999 (the “Record Date”). Each common share issued after the Record Date has also been issued a Right. The description and terms of the Rights are set forth in a Rights Agreement, dated as of March 16, 1999, between the Company and the rights agent.

On April 3, 2002, the Company and the rights agent executed the First Amendment to Rights Agreement (the “Amendment”). The Amendment, among other things, amends the Rights Agreement to lower the threshold at which a person becomes an Acquiring Person (as defined in the Rights Agreement, as amended by the Amendment) and triggers the rights plan from 15 percent to 10 percent.

Stock Plans

In 2002, the Company granted 260,650 shares of restricted stock and 106,000 restricted stock rights to employees under the 1990 Stock Plan, as amended. All of the restricted stock and stock rights vest over a three-year period. The related compensation expense of $2.9 million (based on the stock price on the date of grant) is being amortized over the vesting periods. Compensation expense is reduced when non-vested restricted shares or restricted stock rights are forfeited. Net compensation expense related to restricted stock grants totaled $0.8 million and $0.3 million for the nine months ended September 30, 2002 and 2001, respectively, and $0.4 million and $0.2 million for the three months ended September 30, 2002 and 2001, respectively.

Dividends

The Company declared cash dividends of $0.115 and $0.10 per share for the nine months ended September 30, 2002 and 2001, respectively, and $0.04 and $0.035 per share for the three months ended September 30, 2002 and 2001, respectively.

6. INCOME TAXES

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

	Nine Months Ended September 30, 2002		Nine Months Ended September 30, 2001
U.S. federal statutory income tax rate	35.0	%	35.0	%
U.S. state income tax (net of federal tax benefit)	3.9		3.9
Foreign operations	(31.8	)	(3.1	)

	7.1	%	35.8	%

The beneficial impact of foreign operations in 2002 is primarily the result of losses reported for tax purposes in Canada, which are benefitted at a higher tax rate than in the U.S., taxable income in Argentina, which is taxed at a lower rate than in the U.S., and the utilization of net operating loss carryforwards in Argentina that were not previously benefitted.

7. SEGMENT 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 natural gas and crude oil. Revenues for the gathering/plant segment arise from the transportation, processing and sale of natural gas, crude oil and plant products. The gas marketing segment generates revenue by earning fees through the marketing of Company-produced gas volumes and the purchase and resale of third party-produced gas volumes. The Company evaluates the performance of its operating segments based on segment operating income.

Operations in the gathering/plant and gas marketing segments are in the United States. The Company operates in the oil and gas exploration and production segment in the United States, Canada, South America and Yemen. The financial information related to the Company’s discontinued operations in Trinidad has been excluded in all periods presented (see Note 9). Summarized financial information for the Company’s reportable segments for the nine month and three month periods ended September 30, 2002 and 2001, is shown in the following tables (in thousands):

	Exploration and Production
	U.S.			Canada			Argentina		Bolivia		Ecuador		Other Foreign
Nine Months Ended 9/30/02
Revenues from external customers	$	177,458		$	81,715		$	171,607	$	9,123	$	15,621	$	—
Intersegment revenues		—			—			—		—		—		—
Depreciation, depletion and amortization expense		40,232			56,400			35,765		2,770		1,667		—
Goodwill impairment		—			60,547			—		—		—		—
Segment operating income (loss)		64,935			(83,144	)		88,310		3,160		7,717		(1,671	)
Total assets		444,669			733,386			513,196		117,792		63,741		22,455
Capital investments		19,505			44,941			14,135		2,257		6,092		3,177
Long-lived assets		410,393			712,184			454,633		93,004		54,121		21,968
	Gathering/ Plant			Gas Marketing			Corporate		Total
Nine Months Ended 9/30/02
Revenues from external customers	$	4,524		$	45,215		$	4,082	$	509,345
Intersegment revenues		—			652			—		652
Depreciation, depletion and amortization expense		1,140			—			2,262		140,236
Goodwill impairment		—			—			—		60,547
Segment operating income (loss)		(1,692	)		1,277			1,821		80,713
Total assets		10,666			9,966			51,225		1,967,096
Capital investments		1,668			—			966		92,741
Long-lived assets		7,999			—			6,713		1,761,015
	Exploration and Production
	U.S.			Canada			Argentina		Bolivia		Ecuador		Other Foreign
Nine Months Ended 9/30/01
Revenues from external customers	$	307,188		$	60,130		$	189,145	$	12,724	$	19,658	$	—
Intersegment revenues		—			—			—		—		—		—
Depreciation, depletion and amortization expense		44,372			31,135			30,968		3,495		2,038		—
Impairment of oil and gas properties		9,096			1,610			—		—		—		—
Amortization of goodwill		—			7,191			—		—		—		—
Segment operating income (loss)		159,600			(3,882	)		114,284		6,224		10,813		(2,339	)
Total assets		510,480			842,411			527,870		120,902		58,306		21,930
Capital investments		50,254			658,303			92,537		871		9,348		2,349
Long-lived assets		463,784			822,290			462,309		94,948		48,811		20,637
	Gathering/ Plant			Gas Marketing			Corporate		Total
Nine Months Ended 9/30/01
Revenues from external customers	$	15,100		$	115,295		$	2,161	$	721,401
Intersegment revenues		—			1,714			—		1,714
Depreciation, depletion and amortization expense		1,942			—			2,110		116,060
Impairment of oil and gas properties		—			—			—		10,706
Amortization of goodwill		—			—			—		7,191
Segment operating income (loss)		(2,618	)		3,131			50		285,263
Total assets		16,227			8,488			54,610		2,161,224
Capital investments		9,773			—			4,524		827,959
Long-lived assets		13,349			—			7,309		1,933,437

	Exploration and Production
	U.S.			Canada			Argentina			Bolivia		Ecuador		Other Foreign
Three Months Ended 9/30/02
Revenues from external customers	$	55,177		$	26,423		$	66,475		$	2,947	$	5,665	$	—
Intersegment revenues		—			—			—			—		—		—
Depreciation, depletion and amortization expense		11,569			18,400			11,108			827		543		—
Segment operating income (loss)		21,140			(6,342	)		38,898			1,044		3,142		(1,510	)
Capital investments		5,277			10,659			1,670			1,145		4,235		2,132
	Gathering/ Plant			Gas Marketing			Corporate			Total
Three Months Ended 9/30/02
Revenues from external customers	$	1,671		$	15,482		$	(1,256	)	$	172,584
Intersegment revenues		—			197			—			197
Depreciation, depletion and amortization expense		551			—			769			43,767
Segment operating income (loss)		(674	)		290			(2,025	)		53,963
Capital investments		1,983			—			94			27,195
	Exploration and Production
	U.S.			Canada			Argentina			Bolivia		Ecuador		Other Foreign
Three Months Ended 9/30/01
Revenues from external customers	$	73,722		$	27,955		$	58,071		$	4,383	$	8,877	$	—
Intersegment revenues		—			—			—			—		—		—
Depreciation, depletion and amortization expense		15,755			17,445			10,733			1,358		1,063		—
Impairment of oil and gas properties		9,096			1,610			—			—		—		—
Amortization of goodwill		—			4,417			—			—		—		—
Segment operating income (loss)		17,095			(9,656	)		32,495			1,895		4,769		(2,897	)
Capital investments		18,221			26,702			62,458			118		3,073		3,193
	Gathering/ Plant			Gas Marketing			Corporate			Total
Three Months Ended 9/30/01
Revenues from external customers	$	794		$	20,481		$	(391	)	$	193,892
Intersegment revenues (losses)		—			336			—			336
Depreciation, depletion and amortization expense		888			—			830			48,072
Impairment of oil and gas properties		—			—			—			10,706
Amortization of goodwill		—			—			—			4,417
Segment operating income (loss)		(1,393	)		(60	)		(1,220	)		41,028
Capital investments		171			—			1,218			115,154

Intersegment sales are priced in accordance with terms of existing contracts and current market conditions. Capital investments include expensed exploratory costs. Corporate general and administrative costs and interest costs (including the loss on early extinguishment of debt) are not allocated to segments.

8. COMMITMENTS AND CONTINGENCIES

The Company is committed to perform a certain number of work units in the Chaco concession in Bolivia that it expects to complete by drilling one well in 2003 at an estimated cost of $6.3 million. The Company is also committed to drill two wells in the Damis S-1 concession in Yemen prior to October 2004 at an estimated total cost of $6.0 million. The Company has drilled one well under this commitment and drilling of the second well is underway. In Ecuador, the Company is committed to drill two wells in Block 14 and two wells in Block 17 at an aggregate estimated cost of approximately $14.8 million in 2002 and is committed to drill one well in the Shiripuno Block in 2003 at an estimated cost of $4.2 million. The Company has drilled one well in Block 17 under this commitment and the drilling of the second Block 17 well is in progress.

The Company had approximately $17.7 million in letters of credit outstanding at September 30, 2002. These letters of credit relate primarily to various obligations for exploration activities in South America and Yemen and 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 is a defendant in various lawsuits and is a party to governmental proceedings from time to time arising in the ordinary course of business. In the opinion of management, none of the various pending lawsuits and proceedings should have a material adverse impact on the Company’s financial position or results of operations.

9. SALES OF ASSETS

On July 30, 2002, the Company completed the sale of its operations in Trinidad. The Company received $40 million in cash and recorded a gain of approximately $31.9 million ($14.9 million after income taxes), subject to post-closing adjustments.

In accordance with the rules established by SFAS No. 144, the Company’s Trinidad operations, along with the gain on the sale, are accounted for as discontinued operations in the accompanying consolidated financial statements. Prior period statements have been restated to reflect the discontinued operations classifications. Summarized financial information for the Company’s Trinidad operations is as follows (in thousands):

	Three Months Ended September 30,						Nine Months Ended September 30,
	2002			2001			2002			2001
Loss from discontinued operations	$	(2	)	$	(240	)	$	(711	)	$	(538	)
Deferred tax benefit		—			(188	)		(253	)		(188	)

Net operating loss from discontinued operations		(2	)		(52	)		(458	)		(350	)
Gain on sale of Trinidad operations, net of $16,939 income tax expense		14,943			—			14,943			—

Income (loss) from discontinued operations, net of tax	$	14,941		$	(52	)	$	14,485		$	(350	)

	December 31, 2001
Current assets	$	1,274
Property, plant and equipment		7,898

		9,172
Current liabilities		(972	)

Net assets	$	8,200

In accordance with SFAS No. 144, the assets of the Company’s Trinidad operations were reclassified as “Assets to be sold” and the liabilities were reclassified into “Other payables and accrued liabilities” in the Company’s consolidated balance sheet as of December 31, 2001.

In June 2002, the Company sold its heavy oil properties in the Santa Maria area of southern California for approximately $9.5 million in cash and a note receivable for $6 million. The note was payable in monthly installments of $360,000, plus interest at a rate of 7.5% per annum, with final maturity in June 2003. In October 2002, the Company received a cash payment as final settlement of the note. The Company recorded a gain of approximately $17.8 million ($10.9 million after tax) on this transaction. Included in this gain is a reversal of the Company’s accrual for future abandonment costs related to these properties.

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS

OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Results of Operations

The Company’s results of operations have been significantly affected by its success in acquiring oil and gas properties and its ability to maintain or increase production through its exploitation and exploration activities. Fluctuations in oil and gas prices have also significantly affected the Company’s results. The following table reflects the Company’s oil and gas production and its average oil and gas sales prices for the periods presented:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2002			2001			2002			2001
Production:
Oil (MBbls)—
U.S.		1,618			2,108			5,193			6,438
Canada		449			575			1,429			1,010
Argentina		2,607	(a)		2,455	(b)		8,442	(a)		7,505	(b)
Ecuador		251	(a)		452	(b)		797	(a)		1,034	(b)
Bolivia		23	(a)		21	(b)		94	(a)		69	(b)
Total		4,948	(a)		5,611	(b)		15,955	(a)		16,056	(b)
Gas (MMcf)—
U.S.		6,260			8,533			18,740			26,137
Canada		7,404			7,604			22,810			13,407
Argentina		2,715			2,802			6,682			7,810
Bolivia		1,505			2,340			4,850			6,178
Total		17,884			21,279			53,082			53,532
Total MBOE		7,929			9,157			24,802			24,978
Average price (including impact of hedges):
Oil (per Bbl)—
U.S.	$	23.97		$	23.22		$	21.27		$	24.56
Canada		24.01			21.95			21.23			23.08
Argentina		25.13			22.11			20.03	(c)		23.76
Ecuador		22.60			19.63			19.61			19.01
Bolivia		22.11			21.35			20.37			24.04
Total		24.51			22.31			20.53	(c)		23.73
Gas (per Mcf)—
U.S.	$	2.69		$	2.92		$	2.65		$	5.69
Canada		2.11			2.03			2.25			2.75
Argentina		.35			1.35			.37			1.39
Bolivia		1.62			1.69			1.48			1.79
Total		2.01			2.26			2.09			3.88

	Three Months Ended September 30,				Nine Months Ended September 30,
	2002		2001		2002			2001
Average price (excluding impact of hedges):
Oil (per Bbl)—
U.S.	$	25.30	$	22.60	$	21.86		$	23.96
Canada		23.46		21.95		21.06			23.08
Argentina		25.13		20.93		20.13	(c)		22.56
Ecuador		22.60		19.63		19.61			19.01
Bolivia		22.11		21.35		20.37			24.04
Total		24.90		21.56		20.76	(c)		22.92
Gas (per Mcf)—
U.S.	$	2.80	$	2.92	$	2.75		$	5.69
Canada		1.96		2.03		2.24			2.75
Argentina		.35		1.35		.37			1.39
Bolivia		1.62		1.69		1.48			1.79
Total		1.98		2.26		2.12			3.88

(a)

Total production for the three months and nine months ended September 30, 2002, before the impact of changes in inventories was 4,968 MBbls (Argentina—2,602 MBbls, Ecuador—276 MBbls, Bolivia—23 MBbls) and 15,737 MBbls (Argentina—8,220 MBbls, Ecuador—822 MBbls, Bolivia—73 MBbls), respectively.

(b)

Total production for the three months and nine months ended September 30, 2001, before the impact of changes in inventories was 5,701 MBbls (Argentina—2,637 MBbls, Ecuador—349 MBbls, Bolivia—32 MBbls) and 16,316 MBbls (Argentina—7,732 MBbls, Ecuador—1,048 MBbls, Bolivia—88 MBbls), respectively.

(c)

Reflects the impact of the one-time government-mandated forced settlement of domestic Argentina oil sales which decreased the Argentina and total average oil prices per Bbl for the nine months ended September 30, 2002, per Bbl by $.95 and $.50, respectively.

Significant acquisitions and dispositions of producing oil and gas properties during 2001 and 2002 affect the comparability of operating data for the periods presented in the table above and on the previous page.

Oil Prices

Average U.S. and Canada oil prices received by the Company fluctuate generally with changes in the NYMEX reference price for oil. The Company’s Argentina oil production is sold at West Texas Intermediate spot prices as quoted on the Platt’s Crude Oil Marketwire (approximately equal to the NYMEX reference price) less a specified differential. The Company’s Ecuador production is sold to various third party purchasers at West Texas Intermediate spot prices less a specified differential. The Company experienced a 13 percent decrease in its average oil price, including the impact of hedging activities (nine percent decrease excluding hedging activities), during the first nine months of 2002 as compared to the same period of 2001. The Company’s realized average oil price for the first nine months of 2002 (before hedges) was approximately 82 percent of the NYMEX reference price (84 percent excluding the negative impact of the Argentine government mandated settlements) compared to 82 percent for the same period of 2001.

The Argentine government took actions which in effect caused the devaluation of the peso in early December 2001 and, in January 2002, enacted an emergency law that required certain contracts that were previously payable in U.S. dollars to be payable in pesos. Subsequently, on February 13, 2002, the Argentine government announced a 20 percent tax on oil exports, effective March 1, 2002, which is reflected in lease operating expenses. The tax is limited by law to a term of no more than five years. The tax of 20 percent is applied on the sales value after the tax, thus the net effect is 16.7 percent. For additional information, see “Item 3. Quantitative and Qualitative Disclosures About Market Risk—Foreign Currency and Operations Risk” included elsewhere in this Form 10-Q. The Company’s domestic Argentina oil sales are now being received locally in pesos, while its export oil sales continue to be received in U.S. bank accounts in U.S. dollars, with a requirement to repatriate 30 percent of such proceeds into Argentina.

The Company currently exports approximately 70 percent of its Argentina oil production. The Company believes that this export tax will have the effect of decreasing all future Argentina oil revenues (not only export revenues) by the tax rate for the duration of the tax. The U.S. dollar equivalent value for domestic Argentina oil sales (now paid in pesos) has generally moved to parity with the U.S. dollar-denominated export values, net of the export tax. The adverse impact of this tax will be partially offset by the net cost savings from the devaluation of the peso on peso-denominated costs and will be further reduced by the Argentina income tax savings related to deducting the impact of the export tax. The export tax is not deducted in the calculation of royalty payments.

The Company participated in oil hedges covering 3.5 MMBbls and 4.6 MMBbls during the first nine months of 2002 and 2001, respectively. The impact of the 2002 hedges reduced the Company’s U.S. average oil price for the first nine months of 2002 by 59 cents to $21.27 per Bbl, increased its Canada average oil price by 17 cents to $21.23 per Bbl, reduced its Argentina average oil price by 10 cents to $20.03 per Bbl and reduced its overall average oil price by 23 cents to $20.53 per Bbl. The impact of the 2001 hedges increased the Company’s U.S. average oil price for the first nine months of 2001 by 60 cents to $24.56 per Bbl, increased its Argentina average oil price by $1.20 to $23.76 per Bbl and increased its overall average oil price by 81 cents to $23.73 per Bbl.

Gas Prices

Average U.S. gas prices received by the Company fluctuate generally with changes in spot market prices, which may vary significantly by region as evidenced by the significantly higher gas prices in California during the first half of 2001 due to the localized power shortage. The Company’s Canada gas is generally sold at spot market prices as reflected by the AECO gas price index. The Company’s Bolivia average gas price is tied to a long-term contract under which the base price is adjusted for changes in specified fuel oil indexes. In Argentina, the Company’s average gas price was historically determined by the realized price of oil from its El Huemul concession under a gas for oil exchange arrangement which expired at the end of 2001. Beginning in 2002, the Company’s Argentina gas is sold under spot contracts of varying lengths and, as a result of the emergency laws enacted in 2002, must now be received locally in pesos. This has initially resulted in a decrease in Argentine gas sales revenue when converted to U.S. dollars due to the devaluation of the peso and current market conditions. This value may improve over time as domestic Argentina gas drilling declines and the government begins to lift price controls over public services tariffs. The Company’s total average realized gas price for the first nine months of 2002, including the impact of hedging activities, was 46 percent lower (45 percent lower excluding hedging activities) than the same period of 2001.

The Company participated in gas hedges covering 10.9 million MMBtu during the first nine months of 2002. The Company did not participate in any gas hedges in 2001. The impact of the 2002 hedges reduced the Company’s U.S. average gas price for the first nine months of 2002 by 10 cents to $2.65 per Mcf, increased its Canada average gas price by one cent to $2.25 per Mcf and reduced its overall average gas price by three cents to $2.09 per Mcf.

Future Period Hedges

The Company has previously engaged in oil and gas hedging activities and intends to continue to consider various hedging arrangements to realize commodity prices which it considers favorable. The Company has entered into various oil price swap agreements covering approximately 1.5 MMBbls of its U.S. and Canadian oil production for the last three months of 2002 at a weighted average NYMEX reference price of $26.04 per Bbl and covering approximately 3.0 MMBbls of its U.S. oil production for all of 2003 at a weighted average NYMEX reference price of $24.90 per Bbl.

Additionally, the Company has entered into various gas price swap agreements covering approximately 1.2 million MMBtu of its U.S. and Canadian gas production for the month of October 2002. The Canadian portion of the gas price swap agreements (approximately 0.6 million MMBtu) is at an average AECO gas price index reference price of 3.58 Canadian dollars per MMBtu and will be settled in Canadian dollars. The U.S. portion of the gas swap agreements (approximately 0.6 million MMBtu) is at an average NYMEX reference price of $2.60 per MMBtu. The Company has entered into gas price swap arrangements covering 11.0 million MMBtu of its U.S. gas production for calendar 2003 at a weighted average NYMEX reference price of $4.00 per MMBtu.

The Company also has costless price collar arrangements for 1.4 million MMBtu of it U.S. gas production for the last three months of 2002. The price collars have a floor NYMEX reference price of $3.50 per MMBtu for all three months and a cap NYMEX reference price of $4.00 per MMBtu for October 2002 and a cap NYMEX reference price of $5.10 per MMBtu for November and December 2002.

In conjunction with each of the 2002 U.S. gas price swaps and costless price collars discussed above, 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 entered into basis swap agreements covering 5.1 million MMBtu of its U.S. gas production for calendar 2003.

The counterparties to the Company’s hedging agreements are commercial or investment banks. The Company continues to monitor oil and gas prices and may enter into additional oil and gas hedges or swaps in the future.

Relatively modest changes in either oil or gas prices significantly impact the Company’s results of operations and cash flow. Based on the first nine months of 2002 oil production, a change in the average oil price realized, before hedges, by the Company of $1.00 per Bbl would result in a change in net income and cash flow before income taxes on an annual basis of approximately $11.1 million and $17.4 million, respectively. A 10 cent per Mcf change in the average price realized, before hedges, by the Company for gas would result in a change in net income and cash flow before income taxes on an annual basis of approximately $3.2 million and $5.2 million, respectively, based on gas production for the first nine months of 2002. However, the impact of changes in the market prices for oil and gas on the Company’s average realized prices may be reduced from time to time based on the level of the Company’s hedging activities.

Period to Period Comparison

In May 2001, the Company purchased 100 percent of the outstanding common stock of Genesis Exploration Ltd. (“Genesis”). This acquisition significantly impacts the period to period comparison for the first nine months of 2002 compared to the first nine months of 2001. The Company’s consolidated revenues and expenses for the first nine months of 2001 include, under the purchase method of accounting, five months of activities for Genesis.

Three months ended September 30, 2002, compared to three months ended September 30, 2001

The Company reported net income of $31.7 million for the quarter ended September 30, 2002, compared to net income of $6.2 million for the same period in 2001. The third quarter of 2002 included $14.9 million in income from discontinued operations due to the sale of the Company’s operations in Trinidad compared to a $0.1 million loss from discontinued operations in the third quarter of 2001. In the third quarter of 2001, the Company recorded a $9.1 million impairment charge to reduce certain domestic producing oil and gas properties that were for sale to fair market value and a $1.6 million impairment charge on certain Canadian oil and gas properties. Net income for the three months ended September 30, 2001, also included a charge of $4.4 million for amortization of goodwill. Amortization of goodwill was discontinued on January 1, 2002, in accordance with newly adopted accounting standards.

Oil and gas sales decreased $16.1 million (nine percent), to $157.1 million for the third quarter of 2002 from $173.2 million for the same period of 2001. A 16 percent decrease in gas production coupled with an 11 percent decrease in average gas prices, accounted for a $12.2 million decrease in gas revenues. A 12 percent decrease in oil production was offset by a 10 percent increase in average oil prices, accounting for a $3.9 million decrease in oil revenues. The Company’s 12 percent decrease in oil production and 16 percent decrease in gas production were primarily the result of U.S. property sales during the fourth quarter of 2001 and second quarter of 2002, combined with natural production declines, including declines in Argentina, where the Company curtailed its capital spending program earlier in 2002. The 2002 production declines in Argentina were partially offset by production from properties acquired in September 2001. The Company’s average realized price of gas fell 11 percent primarily from the impact of devaluation-induced lower prices in Argentina.

Lease operating expenses, including production and export taxes, decreased $6.1 million (11 percent), to $52.2 million for the third quarter of 2002 from $58.3 million for the same period of 2001. The decrease in lease operating expenses is due primarily to the beneficial impact of the Argentine peso devaluation on peso-denominated costs, which was partially offset by the new Argentine export tax for 2002 which totaled $6.5 million for the three months ended September 30, 2002, and by lower expenses in the U.S. as a result of property sales in the fourth quarter of 2001 and the second quarter of 2002. Lease operating expenses per equivalent barrel produced, before the effect of the export tax, decreased nine percent to $5.77 for the third quarter of 2002 from $6.37 for the same period of 2001.

Exploration costs decreased $3.9 million (41 percent), to $5.6 million for the third quarter of 2002 from $9.5 million for the same period of 2001. During the third quarter of 2002, the Company’s exploration costs included $4.2 million for unsuccessful exploratory drilling and leasehold impairments and $1.4 million for seismic and other geological and geophysical costs. Exploration expenses for the third quarter of 2001 consisted of $5.6 million for unsuccessful exploratory drilling and leasehold impairments and $3.9 million for seismic and other geological and geophysical costs.

General and administrative expenses decreased $0.6 million (five percent), to $12.3 million for the third quarter of 2002 from $12.9 million for the same period of 2001, due primarily to the beneficial impact of the Argentine peso devaluation on peso-denominated costs. The Company’s G&A per equivalent barrel produced for the third quarter of 2002 increased to $1.55 compared to $1.42 for the same period of 2001 primarily as a result of the 13 percent decrease in production on an equivalent barrel basis. However, the decline in total general and administrative expenses did not keep pace with the decline in production, resulting in a 10 percent increase on an equivalent barrel basis.

Depreciation, depletion and amortization decreased $4.3 million (nine percent), to $43.8 million for the third quarter of 2002 from $48.1 million for the same period of 2001, primarily due to the U.S. property sales in the fourth quarter of 2001 and second quarter of 2002. The Company’s average oil and gas DD&A rate per equivalent barrel produced increased from $5.05 in the third quarter of 2001 to $5.34 in the third quarter of 2002.

As part of the Company’s non-strategic producing oil and gas property divestiture program, certain domestic properties were sold at public auctions during the fourth quarter of 2001. In accordance with Statement of Financial Accounting Standards No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of (“SFAS No. 121”), the Company recorded a $9.1 million impairment charge in the third quarter of 2001 to reduce certain of these properties to the lower of cost or fair market value. These properties, along with other properties, were sold at a public auction in October 2001 and a gain of $6.7 million was recorded in the fourth quarter of 2001 related to the sale, thus resulting in a net loss on the disposition of $2.4 million. The Company also recorded a $1.6 million impairment charge during the third quarter of 2001 related to certain Canadian producing oil and gas properties. No impairment charges were recorded in the third quarter of 2002.

Interest expense increased $0.1 million (one percent), to $20.0 million for the third quarter of 2002 from $19.9 million for the same period of 2001. A slightly higher average interest rate resulting from a change in the Company’s fixed-to-floating rate debt mix offset the reduction in average debt outstanding during the quarter.

Nine months ended September 30, 2002, compared to nine months ended September 30, 2001

The Company reported a net loss of $12.0 million for the nine months ended September 30, 2002, compared to net income of $129.2 million for the year-earlier period. The first nine months of 2002 included a charge of $60.5 million for impairment of goodwill resulting from the cumulative effect of adopting Statement of Financial Accounting Standards No. 142, Goodwill and Other Intangible Assets (“SFAS No. 142”). Additionally, income from discontinued operations due to the sale of the Company’s operations in Trinidad was $14.5 million for the first nine months of 2002 compared to a loss of $0.3 million for the same period in 2001. Income before discontinued operations and the cumulative effect of adopting SFAS No. 142 decreased $95.5 million from $129.5 million to $34.0 million. The decrease in income before discontinued operations and the cumulative effect of change in accounting principle was primarily caused by lower average realized prices for oil and gas during the 2002 period and higher interest and DD&A expense resulting from 2001 acquisitions.

Oil and gas sales decreased $150.3 million (26 percent), to $438.3 million for the first nine months of 2002 from $588.6 million for the nine months of 2001. A 46 percent decrease in average gas prices coupled with a one percent decrease in gas production accounted for a $96.7 million decrease in gas sales for the first nine months of 2002 as compared to the year-earlier period. A one percent decrease in oil production coupled with a 14 percent decrease in average oil prices, accounted for a $53.6 million decrease in oil sales for the first nine months of 2002 as compared to the year-earlier period. Production increases that resulted from the acquisition of Genesis in May 2001 and the acquisition of the two concessions in Argentina in September 2001 were offset by production declines due primarily to the U.S. property sales in the fourth quarter of 2001 and the second quarter of 2002, combined with natural production declines, including declines in Argentina, where the Company curtailed its capital spending program throughout 2002.

A net gain on disposition of assets of $17.3 million ($10.5 million net of tax) was reflected in the first nine months of 2002 primarily as a result of the sale of the Company’s heavy oil properties in the Santa Maria area of southern California in June 2002. The Company recorded a gain of approximately $17.8 million ($10.9 million net of tax) on the Santa Maria transaction. Included in this gain is a reversal of the Company’s accrual for future abandonment costs related to these properties.

As discussed in Note 2 to the financial statements included elsewhere in this Form 10-Q, the Argentine peso was devalued in early December 2001. During the first nine months of 2002, the peso continued to decline in value, falling from a rate of 1.65 pesos to one U.S. dollar at January 11, 2002, to 3.75 pesos to one U.S. dollar at September 30, 2002. The translation of peso-denominated balances at September 30, 2002, and peso-denominated transactions during the nine months ended September 30, 2002, resulted in a foreign currency exchange gain of $3.4 million. The Company also recorded a gain of $0.9 million in “Other income (expense)” for the first nine months of 2002 related to the Argentine government-mandated negotiated settlements of U.S. dollar-denominated receivables and payables in existence at January 6, 2002. There were no similar gains related to Argentina in the nine months ended September 30, 2001.

Lease operating expenses, including production and export taxes, decreased $1.8 million (one percent), to $157.3 million for the first nine months of 2002 from $159.1 million for the first nine months of 2001 primarily due to the beneficial impact of the Argentine peso devaluation on peso- denominated costs, which was mostly offset by the new Argentine export tax of $17.1 million for the nine month period. The export tax was enacted March 1, 2002. Lease operating expenses per equivalent barrel produced, before the effect of the export tax, decreased 11 percent to $5.65 in the first nine months of 2002 from $6.37 for the same period in 2001. This decrease on an equivalent barrel basis was primarily due to the beneficial impact of the Argentine peso devaluation on peso-denominated costs.

General and administrative expenses increased $1.4 million (four percent), to $38.3 million for the first nine months of 2002 from $36.9 million for the first nine months of 2001 due primarily to the acquisition of Genesis which occurred on May 2, 2001. There are nine months of Genesis expenses in the current period compared to five months in the prior period. General and administrative expenses per equivalent barrel produced increased to $1.54 for the first nine months of 2002 from $1.48 in the year-earlier period.

Exploration costs increased $6.4 million (42 percent), to $21.6 million for the first nine months of 2002 from $15.2 million for same period of 2001. Exploration costs for the first nine months of 2002 included $15.2 million for unsuccessful exploratory drilling and leasehold impairments and $6.4 million for seismic and other geological and geophysical costs. During the first nine months of 2001, the Company’s exploration costs included $8.5 million for unsuccessful exploratory drilling and leasehold impairments and $6.7 million for seismic and other geological and geophysical costs.

Depreciation, depletion and amortization increased $24.1 million (21 percent), to $140.2 million for the first nine months of 2002 from $116.1 million for the first nine months of 2001, due primarily to the 23 percent increase in the average oil and gas amortization rate per equivalent barrel produced from $4.47 in the first nine months of 2001 to $5.51 for the same period of 2002. The amortization rate increase is primarily due to the acquisition of Genesis and the impact of lower commodity prices in 2002 on proved reserves used to determine the amortization rate.

Interest expense increased $11.5 million (25 percent), to $58.2 million for the first nine months of 2002 from $46.7 million for the first nine months of 2001, due primarily to higher outstanding borrowings (38 percent) resulting from the acquisition of Genesis in May 2001 and other acquisitions made in the third quarter of 2001. This increase was partially offset by a decrease in the Company’s average interest rate to 7.28 percent for the first nine months of 2002 from 8.01 percent in the same period of 2001.

In conjunction with the issuance of the Company’s 8¹/4% senior notes, the Company entered into a new revolving credit facility and redeemed a portion of the Company’s 9% senior subordinated notes. The Company was required to expense certain associated deferred financing costs and discounts. This $5.2 million non-cash charge, along with a $3.0 million cash charge for the call premium on the 9% senior subordinated notes, resulted in a one-time charge of approximately $8.2 million ($5.0 million net of tax) in the first nine months of 2002.

Effective January 1, 2002, the Company adopted the provisions of Statement of Financial Accounting Standards No. 142, Goodwill and Other Intangible Assets (“SFAS No. 142”). SFAS No. 142 changes the accounting for goodwill from an amortization method to an impairment-only method. Under SFAS No. 142, all goodwill amortization ceased effective January 1, 2002. Goodwill was tested for impairment in conjunction with a transitional goodwill impairment test in 2002 and will be tested at least annually thereafter. As a result of the transitional impairment test, the Company recorded a $60.5 million charge to “cumulative effect of change in accounting principle” retroactive to January 1, 2002, in accordance with the provisions of SFAS No. 142.

Capital Expenditures

During the first nine months of 2002, the Company’s total oil and gas capital expenditures were $91.4 million. In North America, the Company’s non-acquisition oil and gas capital expenditures totaled $65.0 million. Exploitation activities accounted for $31.4 million of the North America capital expenditures with exploration activities contributing $33.6 million. During the first nine months of 2002, the Company’s international non-acquisition oil and gas capital expenditures totaled $25.3 million, consisting of $14.1 million in Argentina on exploitation activities, $6.1 million in Ecuador principally on exploitation, $2.3 million in Bolivia on exploitation activities and $2.8 million primarily on exploration projects in Yemen.

As of September 30, 2002, the Company had unproved oil and gas property costs of approximately $102.9 million, consisting of undeveloped leasehold costs of $76.3 million, including $56.2 million in Canada, and unevaluated exploratory drilling costs of $26.6 million. Approximately $22.0 million of the total unevaluated costs are associated with the Company’s Yemen drilling program. Future exploration expense and earnings may be impacted to the extent any of the undeveloped leaseholds are determined to be impaired or exploratory drilling is determined to be unsuccessful.

Approximately $8.1 million of the Company’s unevaluated costs in Yemen is related to two wells drilled on the An Naeem prospect. These two wells found hydrocarbons, but their commerciality is dependent upon construction of production facilities, which will be justified if a third well in the prospect finds sufficient oil reserves. The third An Naeem well is planned to be drilled in late 2002. If this well is unsuccessful, the $8.1 million of costs currently capitalized will be expensed. The Company expects to make this determination in the fourth quarter of 2002.

The timing of most of the Company’s capital expenditures is discretionary with no material long-term capital expenditure commitments. Consequently, the Company has a significant degree of flexibility to adjust the level of such expenditures as circumstances warrant. The Company uses internally-generated cash flow to fund capital expenditures other than significant acquisitions. The Company’s total planned capital expenditures for 2002 are currently $144 million exclusive of acquisitions. The Company’s preliminary non-acquisition capital budget for 2003 is set at $180 million. The Company does not have a specific acquisition budget since the timing and size of acquisitions are difficult to forecast. The Company is actively pursuing additional acquisitions of oil and gas properties. In addition to internally-generated cash flow and advances under its revolving credit facility, the Company may seek additional sources of capital to fund any future significant acquisitions (see “Liquidity”); however, no assurance can be given that sufficient funds will be available to fund the Company’s desired acquisitions.

Liquidity

Internally generated cash flow and the borrowing capacity under its revolving credit facility are the Company’s major sources of liquidity. In addition, the Company may use other sources of capital, including the issuance of additional debt securities or equity securities, to fund any major acquisitions it might secure in the future and to maintain its financial flexibility.

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

On May 2, 2002, the Company issued, through a Rule 144A offering, $350 million of its 8¹/4% Senior Notes due 2012 (the “8¹/4% Notes”). All of the net proceeds were used to repay a portion of the outstanding balance under the Company’s revolving credit facility and to redeem $100 million of the Company’s outstanding 9% Senior Subordinated Notes due 2005. The 8¹/4% Notes are redeemable at the option of the Company, in whole or in part, at any time on or after May 1, 2007. In addition, prior to May 1, 2005, the Company may redeem up to 35 percent of the 8¹/4% Notes with the proceeds of certain underwritten public offerings of the Company’s common stock. The 8¹/4% Notes mature on May 1, 2012, with interest payable semi-annually on May 1 and November 1, commencing November 1, 2002.

At October 31, 2002, the outstanding borrowings under the Bank Facility were $47.6 million and unused availability under the Bank Facility was approximately $234.7 million (net of letters of credit of $17.7 million). The unused portion of the Bank Facility and the Company’s internally generated cash flow provide liquidity which may be used to finance future capital expenditures, including acquisitions. As additional acquisitions are made and such properties are added to the borrowing base, the banks’ determination of the borrowing base and their commitments may be increased. The next borrowing base redetermination will be in November 2002.

The Company’s internally generated cash flow, results of operations and financing for its operations are dependent on oil and gas prices. Realized oil prices for the nine months ended September 30, 2002, decreased by 14 percent as compared to the same period in 2001. Realized gas prices for the first nine months of 2002 decreased by 46 percent as compared to the same period in 2001. The Company believes that its cash flows and unused availability under the Bank Facility are sufficient to fund its planned capital expenditures for the foreseeable future. To the extent oil and gas prices continue to decline, the Company’s earnings and cash flow from operations may be adversely impacted. Continued low oil and gas prices could cause the Company to not be in compliance with maintenance covenants under its Bank Facility and could negatively affect its credit statistics and coverage ratios and thereby affect its liquidity.

Consistent with its stated goal of maintaining financial flexibility and optimizing its portfolio of assets, the Company announced plans to reduce debt by $200 million in 2002 through a combination of asset sales and cash flow in excess of planned capital expenditures. The Company determined that the level of investment and time horizon required to continue the development of its interests in Ecuador and Trinidad are inconsistent with the timing of its desire to reduce leverage. These assets, along with the Company’s remaining heavy oil properties in the Santa Maria area of southern California, were identified for sale. The Company’s heavy oil properties in the Santa Maria area of southern California were sold in June 2002 for $9.5 million in cash and a note receivable for $6 million bearing monthly payments of $360,000, plus interest, with final maturity in June 2003. The Company received a cash payment as final settlement of this note in October 2002. The Company’s interest in Trinidad was sold in July 2002 for $40 million in cash. The Company’s interests in Ecuador are currently being marketed for sale. The Company is currently reviewing its portfolio and is considering additional asset sales or possible capital market transactions, if necessary, to achieve its $200 million debt reduction target for 2002.

Inflation

In recent years, inflation has not had a significant impact on the Company’s operations or financial condition. However, industry specific inflationary pressures built up in late 2000 and in 2001 due to favorable conditions in the industry. While oil and gas prices have declined from the levels seen in late 2000 and early 2001, the cost of services in the oil and gas industry have not declined by a similar percentage. Any increases in product prices could cause inflationary pressures specific to the industry to also increase.

As a result of the recent devaluation of the peso in Argentina, 2002 year-to-date inflation through October is approximately 40 percent. However, in recent months, the Argentine inflation rate has slowed significantly, with the inflation rate for the month of October at less than one percent.

Income Taxes

The Company incurred a current provision for income taxes of approximately $19.0 million and $56.6 million for the first nine months of 2002 and 2001, 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 the Company’s foreign subsidiaries are subject to foreign income taxes. Additional U.S. deferred tax liabilities are generally not recognized related to the unremitted earnings of these foreign subsidiaries as it is the Company’s intention, generally, to reinvest such earnings permanently.

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

	Nine Months Ended September 30, 2002		Nine Months Ended September 30, 2001
U.S. federal statutory income tax rate	35.0	%	35.0	%
U.S. state income tax (net of federal tax benefit)	3.9		3.9
Foreign operations	(31.8	)	(3.1	)

	7.1	%	35.8	%

Critical Accounting Policies and Estimates

Management’s discussion and analysis of its financial condition and results of operations are based upon the Company’s consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”). The preparation of these consolidated financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. The Company bases its estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances. Actual results could differ from these estimates under different assumptions or conditions. Note 1 to the Company’s 2001 audited consolidated financial statements included in its 2001 Annual Report on Form 10-K and Note 2 to the Company’s consolidated financial statements included elsewhere in this Form 10-Q, contain a comprehensive summary of the Company’s significant accounting policies. The following is a discussion of the Company’s most critical accounting policies, judgments and uncertainties that are inherent in the Company’s application of GAAP:

Proved reserve estimates. Estimates of the Company’s proved reserves included in its consolidated financial statements are prepared in accordance with guidelines established by GAAP and the SEC. The accuracy of a reserve estimate is a function of: (i) the quality and quantity of available data; (ii) the interpretation of that data; (iii) the accuracy of various mandated economic assumptions; and (iv) the judgment of the persons preparing the estimate.

The Company’s proved reserve information is based on estimates prepared by its independent petroleum consultants. Estimates prepared by others may be higher or lower than these estimates. Because these estimates depend on many assumptions, all of which may substantially differ from actual results, reserve estimates may be different from the quantities of oil and gas that are ultimately recovered. In addition, results of drilling, testing and production after the date of an estimate may justify material revisions to the estimate.

The present value of future net cash flows should not be assumed to be the current market value of the Company’s estimated proved reserves. In accordance with SEC requirements, the estimated discounted future net cash flows from proved reserves are based on prices and costs on the date of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of the estimate.

The estimates of proved reserves materially impact depletion, depreciation and amortization expense. If the estimates of proved reserves decline, the rate at which the Company records depletion, depreciation and amortization expense increases, reducing net income. Such a decline may result from lower market prices, which may make it uneconomic to drill for and produce higher cost reserves. In addition, the decline in proved reserve estimates may impact the outcome of the Company’s assessment of its oil and gas producing properties for impairment.

Impairment 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. 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.

Impairment of unproved oil and gas properties. Unproved leasehold costs are capitalized and reviewed periodically for impairment on a property-by-property basis, considering factors such as future drilling and exploitation plans and lease terms. Costs related to impaired prospects are charged to expense. An impairment expense could result if oil and gas prices decline in the future or if downward reserve revisions are recorded, as it may not be economic to develop some of these unproved properties.

Impairment of goodwill. The Company’s goodwill is entirely related to its Canadian operations. The Company must assess its goodwill for impairment at least annually. The Company must perform an initial assessment of whether there is an indication that the carrying value of goodwill is impaired. This assessment is made by comparing the fair value of the Canadian reporting unit, as determined in accordance with SFAS No. 142, to its book value. If the fair value is less than the book value, an impairment is indicated and the Company must perform a second test to measure the amount of the impairment. In the second test, the Company must then calculate the implied fair value of the goodwill by deducting the fair value of all tangible and intangible net assets of the Canadian reporting unit from the fair value of the Canadian reporting unit determined in step one of the assessment. If the carrying value of the goodwill exceeds this calculated implied fair value of the goodwill an impairment charge is recorded.

Revenue recognition. The Company follows a very specific and detailed guideline of recognizing revenues when oil and gas are delivered to the purchaser. However, certain judgments affect the application of the Company’s revenue recognition policy. Revenue results are difficult to predict, and any shortfall in revenue or delay in recognizing revenue could cause the Company’s operating results to vary significantly from quarter to quarter and could result in future operating losses.

Income taxes. The Company provides deferred income taxes on transactions which are recognized in different periods for financial and tax reporting purposes. The Company has not recognized a U.S. deferred tax liability related to the unremitted earnings of any of its foreign subsidiaries as it is the Company’s intention, generally, to reinvest such earnings permanently. The Company has also recorded deferred tax assets related to operating loss and tax credit carryforwards. Management periodically assesses the probability of recovery of recorded deferred tax assets based on its assessment of future earnings outlooks by tax jurisdiction. Such estimates are inherently imprecise since many assumptions are utilized in the assessments that may prove to be incorrect in the future.

Assessments of functional currencies. All of the Company’s subsidiaries use the U.S. dollar as their functional currency, except for the Company’s Canadian subsidiaries, which use the Canadian dollar. Management determines the functional currencies of the Company’s subsidiaries based on an assessment of the currency of the economic environment in which a subsidiary primarily realizes and expends its operating revenues, costs and expenses. The assessment of functional currencies can have a significant impact on periodic results of operations and financial position.

Argentina economic and currency measures. The accounting for and translation of the Company’s Argentina financial statements reflects management’s assumptions regarding uncertainties unique to Argentina’s current economic situation. See Notes 1 and 2 to the Company’s consolidated financial statements included elsewhere in this Form 10-Q for a description of the assumptions utilized in the preparation of its consolidated financial statements. Argentina’s economic and political situation evolves continuously and the Argentine government has adopted numerous decrees, is considering implementing various alternatives and may enact future regulations or policies that may materially impact, among other items, (i) the realized prices the Company receives for oil and gas it produces and sells; (ii) the timing and amount of repatriations of cash to the U.S.; (iii) the amount of permitted export sales; (iv) the Argentine banking system; (v) the Company’s asset valuations; and (vi) peso-denominated monetary assets and liabilities. For further information, see “Item 3. Quantitative and Qualitative Disclosures About Market Risk-Foreign Currency and Operations Risk” included elsewhere in this Form 10-Q.

Changes in Accounting Principles

In June 1998, the Financial Accounting Standards Board (the “FASB”) issued Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended in June 1999 by Statement No. 137, Accounting for Derivative Instruments and Hedging Activities—Deferral of the Effective Date of FASB Statement No. 133 and in June 2000 by Statement No. 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities—an amendment of FASB Statement No. 133 (“SFAS No. 133”). SFAS No. 133 establishes accounting and reporting standards requiring that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded in the balance sheet as either an asset or liability measured at its fair value. SFAS No. 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.

Upon adoption of SFAS No. 133 on January 1, 2001, the Company recorded a transition receivable of $18.5 million related to cash flow hedges in place that are used to reduce the volatility in commodity prices for portions of the Company’s forecasted oil production. Additionally, the Company recorded, net of tax, an increase to accumulated other comprehensive income in the Stockholders’ Equity section of the balance sheet of approximately $14.9 million. During the first nine months of 2001, $13.3 million of the original amount recorded to accumulated other comprehensive income was taken to the statement of operations as the physical transactions being hedged were finalized. All of the Company’s cash flow hedges in place at January 1, 2001, settled in 2001, with the actual cash flow impact recorded in oil and gas sales in the Company’s statement of operations.

On July 20, 2001, the FASB issued Statement of Financial Accounting Standards No. 141, Business Combinations (“SFAS No. 141”), and Statement of Financial Accounting Standards No. 142, Goodwill and Other Intangible Assets (“SFAS No. 142”). SFAS No. 141 requires all business combinations initiated after June 30, 2001, to be accounted for using the purchase method of accounting. Under SFAS No. 142, goodwill is no longer subject to amortization. Rather, goodwill will be subject to at least an annual assessment for impairment by applying a fair-value based test. Additionally, an acquired intangible asset should be separately recognized if the benefit of the intangible asset is obtained through contractual or other legal rights, or if the intangible asset can be sold, transferred, licensed, rented or exchanged, regardless of the acquirer’s intent to do so.

The Company adopted SFAS No. 141 and SFAS No. 142 effective January 1, 2002, resulting in the elimination of goodwill amortization from statements of operations in future periods. As discussed in Note 3 to the Company’s consolidated financial statements included elsewhere in this Form 10-Q, the Company recorded an impairment charge of $60.5 million related to the goodwill of its Canadian operations as a cumulative effect of a change in accounting principle in its statement of operations.

New Accounting Pronouncements

In August 2001, the FASB issued Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations. Currently, the Company accrues future abandonment costs of wells and related facilities through its depreciation calculation and includes the cumulative accrual in accumulated depreciation. The new standard will require that the Company record the discounted fair value of the retirement obligation as a liability at the time a well is drilled or acquired. The liability will accrete over time with a charge to interest expense. The new standard will apply to financial statements of the Company beginning January 1, 2003. While the new standard will require that the Company change its accounting for such abandonment obligations, the Company has not completed its evaluation of the impact of the new standard on its financial statements.

Foreign Operations

For information on the Company’s 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 certain statements that may be deemed to be “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. All statements in this Form 10-Q, other than statements of historical facts, that address activities, events or developments that the Company expects, believes or anticipates will or may occur in the future, including production, operating costs and product price realizations, future capital expenditures (including the amount and nature thereof), the drilling of wells, reserve estimates, future production of oil and gas, future cash flows, future reserve activity, planned asset sales or dispositions, events or developments in Argentina, including estimates of oil export levels, and other such matters are forward-looking statements. Although the Company believes the expectations expressed in such forward-looking statements are based on reasonable assumptions within the bounds of its knowledge of its business, such statements are not guarantees of future performance and actual results or developments may differ materially from those in the forward-looking statements.

Factors that could cause actual results to differ materially from those in forward-looking statements include: oil and gas prices; exploitation and exploration successes; actions taken and to be taken by Argentina as a result of its economic instability; continued availability of capital and financing; general economic, market or business conditions; acquisition and other business opportunities (or lack thereof) that may be presented to the Company; changes in laws or regulations; risk factors listed from time to time in the Company’s reports and other documents filed with the Securities and Exchange Commission; and other factors. The Company assumes no obligation to publicly update any forward-looking statements, whether as a result of new information, future events or otherwise.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

Commodity Price Risk

The Company produces, purchases and sells crude oil, natural gas, condensate, natural gas liquids and sulfur. As a result, the Company’s financial results can be significantly impacted as these commodity prices fluctuate widely in response to changing market forces. See Management’s Discussion and Analysis of Financial Condition and Results of Operations for a discussion of the impact of commodity price changes based on production levels for the first nine months of 2002. The Company has previously engaged in oil and gas hedging activities and intends to continue to consider various hedging arrangements to realize commodity prices which it considers favorable.

The Company has entered into various oil price swap agreements covering approximately 1.5 MMBbls of its U.S. and Canadian oil production for the last three months of 2002 at a weighted average NYMEX reference price of $26.04 per Bbl and covering approximately 3.0 MMBbls of its U.S. oil production for all of 2003 at a weighted average NYMEX reference price of $24.90 per Bbl.

Interest Rate Risk

The Company’s interest rate risk exposure results primarily from short-term rates, mainly LIBOR-based, on borrowings from its commercial banks. To reduce the impact of fluctuations in interest rates, the Company maintains a portion of its total debt portfolio in fixed-rate debt. At September 30, 2002, the amount of the Company’s fixed-rate debt was 92 percent of its total. In the past, the Company has not entered into financial instruments such as interest rate swaps or interest rate lock agreements. However, it may consider these instruments to manage the portfolio mix between fixed and floating rate debt and to mitigate the impact of changes in interest rates based on management’s assessment of future interest rates, volatility of the yield curve and the Company’s ability to access the capital markets in a timely manner.

Based on the outstanding borrowings under variable rate debt instruments at September 30, 2002, a change in the average interest rate of 100 basis points would result in a change in net income and cash flow before income taxes on an annual basis of approximately $0.5 million and $0.8 million, respectively.

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

	2002	2003	2004	2005			2006	There- after			Total			Fair Value at 9/30/02
Long-Term Debt:
Fixed rate (in thousands)	—	—	—	$	49,911		—	$	799,404		$	849,315		$	855,309
Average interest rate	—	—	—		9.0	%	—		8.5	%		8.5	%		—
Variable rate (in thousands)	—	—	—	$	74,900		—		—		$	74,900		$	74,900
Average interest rate	—	—	—		(a	)	—		—			(a	)		(a	)

(a)

LIBOR plus an increment, based on the level of outstanding senior secured debt to the borrowing base, up to a maximum of 2.25 percent. The increment above LIBOR at September 30, 2002, was 1.50 percent.

Foreign Currency and Operations Risk

International investments represent, and are expected to continue to represent, a significant portion of the Company’s total assets. The Company has international operations in Canada, Argentina, Bolivia, Ecuador and Yemen. For the nine months ended September 30, 2002, the Company’s operations in Argentina and Canada accounted for approximately 34 percent and 16 percent, respectively, of the Company’s revenues and, at September 30, 2002, the Company’s operations in Argentina and Canada accounted for approximately 26 percent and 37 percent, respectively, of the Company’s total assets, including goodwill. During the first nine months of 2002 and at September 30, 2002, the Company’s operations in Argentina and Canada represented its only foreign operations accounting for more than 10 percent of its revenues or total assets, including goodwill. The Company continues to identify and evaluate international opportunities, but currently has no binding agreements or commitments to make any material international investment. As a result of such significant foreign operations, the Company’s financial results could be affected by factors such as changes in foreign currency exchange rates, weak economic conditions or changes in the political climate in these foreign countries.

Historically, the Company has not used derivatives or other financial instruments to hedge the risk associated with the movement in foreign currencies. However, the Company evaluates currency fluctuations and will consider the use of derivative financial instruments or employment of other investment alternatives if it deems cash flows or investment returns so warrant.

The Company’s international operations, properties or investments 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 could restrict or increase the cost of the Company’s foreign operations;

•

exchange controls and currency fluctuations could result in financial losses;

•

royalty and tax increases and retroactive claims could increase costs of the Company’s foreign operations;

•

expropriation of the Company’s property could result in loss of revenue, property and equipment;

•

civil uprisings, riots and war could make it impractical to continue operations, adversely affect both budgets and schedules and expose the Company to losses;

•

import and export regulations, including repatriation levels for oil export revenues, and other foreign laws or policies could result in loss of revenues; and

•

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

The Company does not currently maintain political risk insurance. However, the Company will consider obtaining such coverage in the future if it deems conditions so warrant.

Canada. With the acquisition of Cometra Energy (Canada), Ltd. in December 2000 and the acquisition of Genesis in May 2001, the Company now has significant producing operations in Canada. The Company views the operating environment in Canada as stable and the economic stability as good. All of the Company’s Canadian revenues and costs are denominated in Canadian dollars. While the value of the Canadian dollar does fluctuate in relation to the U.S. dollar, the Company believes that any currency risk associated with its Canadian operations would not have a material impact on the Company’s financial position or results of operations.

Argentina. Beginning in 1991, Peronist Carlos Menem, as newly-elected President of Argentina, and Domingo Cavallo, as his Minister of Economy, set out to reverse economic decline through free-market reforms such as open trade. The key to their plan was the “Law of Convertibility” under which the peso was tied to the U.S. dollar at a rate of one peso to one U.S. dollar. Between 1991 and 1997 the plan succeeded. With the risk of devaluation apparently removed, capital came in from abroad and much of Argentina’s state-owned assets were privatized. During this period, the economy grew at an annual average rate of 6.1 percent, the highest in the region.

However, the “convertibility” plan left Argentina with few monetary policy tools to respond to outside events. A series of external shocks began in 1998: prices for Argentina’s commodities stopped rising; the dollar appreciated against other currencies; and Brazil, Argentina’s main trading partner, devalued its currency. Argentina began a period of economic deflation, but failed to respond by reforming government spending. During 2001, Argentina’s budget deficit exceeded $9 billion and its sovereign debt reached $140 billion.

As a result of economic instability and substantial withdrawals from the banking system, in early December 2001, the Argentine government, with Fernando de la Rua as President and Domingo Cavallo as Minister of Economy, instituted restrictions that prohibit foreign money transfers without Central Bank approval and limit cash withdrawals from bank accounts to personal transactions in small amounts with certain limited exceptions. While the legal exchange rate remained at one peso to one U.S. dollar, financial institutions were allowed to conduct only limited activity due to these controls, and currency exchange activity was effectively halted except for personal transactions in small amounts.

On February 3, 2002, Decree 214 required all contracts that were previously payable in U.S. dollars to be payable in pesos. Pursuant to an emergency law passed on January 10, 2002, U.S. dollar obligations between private parties due after January 6, 2002, were liquidated in pesos at a negotiated rate of exchange which reflected a sharing of the impact of the devaluation. The Company’s settlements in pesos of the existing U.S. dollar-denominated agreements have been completed, thus future periods will not be impacted by this mandate. This government-mandated “equitable sharing” of the impact of the devaluation resulted in a reduction in oil revenues from domestic sales for the first nine months of 2002 of approximately $8 million, or $0.95 per Argentina Bbl produced or $0.50 per total Company Bbl produced. The Company’s Argentine lease operating costs were also reduced as a result of this mandate and the positive impact of devaluation on the Company’s peso-denominated costs, which essentially offset the negative impact on Argentine oil revenues.

On February 13, 2002, the Argentine government announced a 20 percent tax on oil exports, effective March 1, 2002. The tax is limited by law to a term of no more than five years. The tax of 20 percent is applied on the sales value after the tax, thus the net effect is 16.7 percent. The Company currently exports approximately 70 percent of its Argentina oil production. Management believes that this export tax will have the effect of decreasing all future Argentina oil revenues (not only export revenues) by the tax rate for the duration of the tax. The U.S. dollar equivalent value for domestic Argentina oil sales (now paid in pesos) has generally moved to parity with the U.S. dollar-denominated export values, net of the export tax. The adverse impact of this tax will be partially offset by the net cost savings resulting from the devaluation of the peso on peso-denominated costs and will be further reduced by the Argentina income tax savings related to deducting the impact of the export tax. The export tax is not deducted in the calculation of royalty payments.

On May 24, 2002, Decree 867 declared the domestic supply of hydrocarbons to be in a state of emergency. This was largely due to the high seasonal demand for diesel in the agricultural sector coupled with lower activity in refineries. On May 30, 2002, the Secretary of Energy with Resolution 140 limited oil exports to 36 percent of monthly production beginning June 2002 for a period of four months. Subsequently on June 21, 2002, the Secretary of Energy with Resolution 166 relaxed the limits, declaring the 36 percent export limit applicable to the entire four month period rather than the individual months. On July 26, 2002, the Secretary of Energy with Resolution 341 completely eliminated the four month export limit. These temporary measures did not adversely impact the Company. However, future export restrictions could impair the Company’s ability to retain its Argentine excess cash flow outside of Argentina.

Since May 2002, many of Argentina’s important economic indicators have shown stability. The Central Bank’s foreign currency reserves have risen from a low of $8.9 billion earlier this year to a recent high on October 31, 2002, of $9.9 billion. The exchange rate has remained stable at approximately 3.60 pesos to one U.S. dollar and the October 31, 2002, exchange rate was 3.52 pesos to one U.S. dollar. Monthly inflation has decreased from a high of 10 percent for the month of April 2002 to an average of 2.6 percent per month from May to September 2002 with October 2002 inflation less than one percent. Year-to-date inflation through October 2002 is approximately 40 percent.

Discussion are underway between the Argentine government and the International Monetary Fund (“IMF”) regarding the refinancing of upcoming maturities of multilateral debt obligations. This refinancing is critical for the Argentine government to manage up to $13 billion in debt obligations with its multilateral lenders through December 31, 2003, without drawing on Central Bank reserves. However, these discussion have recently reached an impasse over IMF positions concerning exchange controls, tax increases and increasing public service tariffs by 30 percent.

The plan set in motion by current President Eduardo Duhalde to transition the government back into the hands of an elected president remains in place. Elections are scheduled for March 2003.

The Company’s capital budget for 2002 was adjusted to reflect a reduced level of drilling in the country. The Company’s activities in Argentina in the third quarter of 2002 were limited to workover rigs operating in the San Jorge basin. The recent stabilization in Argentina’s currency exchange rate and a reduction in the rate of inflation, combined with the attractive drilling economics, have resulted in the Company’s decision to re-initiate its drilling program in the fourth quarter of 2002. The program will begin with one rig with additions to the activity level in 2003 conditioned upon satisfactory stability in the Argentina political and economic environment.

Bolivia. Since the mid-1980’s, Bolivia has been undergoing major economic reform, including the establishment of a free-market economy and the encouragement of foreign private investment. Economic activities that had been reserved for government corporations were opened to foreign and domestic Bolivian private investments. Barriers to international trade have been reduced and tariffs lowered. A new investment law and revised codes for mining and the petroleum industry, intended to attract foreign investment, have been introduced.

Bolivia held national elections in June 2002 that resulted in the election of a new President in August. This marked the sixth consecutive election since 1982, representing the longest period of constitutional democratic government in the country’s history. Coalitions formed among the two leading parties allowing Gonzalo Sanchez de Lozada to win the vote in the runoff election held within Congress. Gonzalo Sanchez de Lozada took office on August 6, 2002. He was President from 1993 until 1997 when significant privatization activity along with encouragement of private investment occurred in the country.

In 1987, the Boliviano (“Bs”) replaced the peso at the rate of one million pesos to one Boliviano. 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 US$:Bs exchange rate at September 30, 2002, was US$1:Bs7.35. The Company believes that any currency risk associated with its Bolivian operations would not have a material impact on the Company’s financial position or results of operations since its gas revenues are received in U.S. dollars.

Ecuador. In Ecuador, President Gustavo Noboa and Congress have debated tax, social, and customs reforms necessary to strengthen economic growth. The legal basis for many of the recent reforms is the Ley Fundamental para la Transformación Económica del Ecuador (the “economic transformation law”) enacted in March 2000, which mandated dollarization of the economy. As a result of this reform, all of the Company’s Ecuadorian revenues and costs are U.S. dollar based. Even though the second phase of the economic transformation law (known as Trole II), which was intended to bring significant tax and labor reform and a defined privatization program to increase inflows of foreign direct investment, was rejected by Congress, President Noboa used his veto powers to pass a tax reform package which allowed the IMF to make a disbursement of its stand-by loan in the second quarter of 2001.

No significant additional policy making or structural reforms are expected for the remainder of 2002, pending a change of government in January 2003. On October 20, 2002, Ecuador held national elections for President. No candidate received the majority vote needed to become President. The second round of elections will be held on November 24, 2002, between Alvaro Noboa and Lucio Gutierrez. Both candidates have proposed plans to renegotiate Ecuador’s external debt and to negotiate a new accord with the IMF.

ITEM 4. CONTROLS AND PROCEDURES

Within the 90 days prior to the filing date of this Form 10-Q, the Company carried out an evaluation, under the supervision and with the participation of the Company’s management, including the Company’s Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures, as defined in Rule 13a-14(c) of the Securities Exchange Act of 1934, as amended. Based upon that evaluation, the Company’s Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures are effective to ensure that information required to be disclosed by the Company in its 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. Subsequent to the date of their evaluation, there have been no significant changes in the Company’s internal controls or in other factors that could significantly affect these controls.

PART II

OTHER INFORMATION

Item 1. Legal Proceedings

For information regarding legal proceedings, see the Company’s Form 10-K for the year ended December 31, 2001.

Item 2. Changes in 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

Copies of the Company’s press releases each dated October 30, 2002, announcing third quarter 2002 earnings results and revisions to 2002 capital budget and growth targets and its preliminary 2003 capital budget and growth targets are attached as exhibits hereto and incorporated herein by reference.

Item 6. Exhibits and Reports on Form 8-K

a) Exhibits

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


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

99.1		Press release dated October 30, 2002, issued by the Company announcing third quarter 2002 earnings results and revised 2002 targets.

99.2		Press release dated October 30, 2002, issued by the Company announcing its preliminary 2003 capital budget and growth targets.

99.3		Certificate pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.


99.4		Certificate pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

b) Reports on Form 8-K

Form 8-K dated June 27, 2002, was filed on July 1, 2002, to report under Item 4 the Company’s dismissal of Arthur Andersen LLP as the Company’s independent auditors effective June 27, 2002, and the appointment of Ernst & Young LLP as its independent auditors for 2002.

Form 8-K dated June 27, 2002, was filed on July 1, 2002, by the Vintage Petroleum, Inc. 401(k) Plan (the “Plan”) to report under Item 4 the dismissal of Arthur Andersen LLP as the independent auditor of the Plan effective June 27, 2002, and the appointment of Ernst & Young LLP as the independent auditors of the Plan for 2002.

Signatures

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

								VINTAGE PETROLEUM, INC. (Registrant)

DATE: November 13, 2002								/s/ MICHAEL F. MEIMERSTORF Michael F. Meimerstorf
								Vice President and Controller (Principal Accounting Officer)

Certifications

I, S. Craig George, certify that:

I have reviewed this quarterly report on Form 10-Q of Vintage Petroleum, Inc.;

Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report;

Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report;

The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;

evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the “Evaluation Date”); and

presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):

all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and

any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

The registrant’s other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.


Dated: November 13, 2002								/s/ S. CRAIG GEORGE
								S. Craig George Chief Executive Officer

I, William C. Barnes, certify that:

I have reviewed this quarterly report on Form 10-Q of Vintage Petroleum, Inc.;

evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the “Evaluation Date”); and

presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and


Dated: November 13, 2002								/s/ WILLIAM C. BARNES
								William C. Barnes Chief Financial Officer

Exhibit Index

Exhibit Number		Description

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

99.1		Press release dated October 30, 2002, issued by the Company announcing third quarter 2002 earnings results and revised 2002 targets.

99.2		Press release dated October 30, 2002, issued by the Company announcing its preliminary 2003 capital budget and growth targets.

99.3		Certificate pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

99.4		Certificate pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.