Edgar Filing: VINTAGE PETROLEUM INC

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q

(Mark One)

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

For the quarterly period ended March 31, 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 (I.R.S. Employer
incorporation or organization) Identification No.)

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

(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 May 10, 2002
----------------------------- ---------------------------
Common Stock, $.005 Par Value 63,136,322

-1-

PART I

FINANCIAL INFORMATION

-2-

ITEM 1. FINANCIAL STATEMENTS
----------------------------

VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
----------------------------------------

CONSOLIDATED BALANCE SHEETS
---------------------------
(In thousands, except shares
and per share amounts)

ASSETS
------

March 31, December 31,
2002 2001
---------- ------------
(Unaudited)

CURRENT ASSETS:
Cash and cash equivalents .................................... $ 16,711 $ 15,454
Accounts receivable -
Oil and gas sales ......................................... 80,269 77,628
Joint operations .......................................... 11,176 9,354
Derivative financial instruments receivable .................. -- 4,701
Prepaids and other current assets ............................ 22,837 37,517
---------- ----------

Total current assets ................................... 130,993 144,654
---------- ----------

PROPERTY, PLANT AND EQUIPMENT, at cost:
Oil and gas properties, successful efforts method ............ 2,522,946 2,498,552
Oil and gas gathering systems and plants ..................... 19,515 20,508
Other ........................................................ 26,003 25,506
---------- ----------

2,568,464 2,544,566
Less accumulated depreciation, depletion and amortization .... 856,400 809,522
---------- ----------

1,712,064 1,735,044
---------- ----------

GOODWILL, net of amortization ................................... 156,929 156,990
---------- ----------

OTHER ASSETS, net ............................................... 54,970 60,100
---------- ----------

$2,054,956 $2,096,788
========== ==========

See notes to unaudited consolidated financial statements.

-3-

VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
----------------------------------------

LIABILITIES AND STOCKHOLDERS' EQUITY
------------------------------------

March 31, December 31,
2002 2001
---------- ------------
(Unaudited)

CURRENT LIABILITIES:
Revenue payable ........................................... $ 24,278 $ 25,625
Accounts payable - trade .................................. 44,914 62,362
Current income taxes payable .............................. 6,784 21,638
Short-term debt ........................................... 17,817 17,320
Derivative financial instruments payable .................. 9,895 --
Other payables and accrued liabilities .................... 55,164 45,200
---------- ----------

Total current liabilities .............................. 158,852 172,145
---------- ----------

LONG-TERM DEBT ............................................... 1,011,803 1,010,673
---------- ----------

DEFERRED INCOME TAXES ........................................ 161,352 166,319
---------- ----------

OTHER LONG-TERM LIABILITIES .................................. 10,549 18,208
---------- ----------

COMMITMENTS AND CONTINGENCIES (Note 5)

STOCKHOLDERS' EQUITY, per accompanying statements:
Preferred stock, $.01 par, 5,000,000 shares authorized,
zero shares issued and outstanding ..................... -- --
Common stock, $.005 par, 160,000,000 shares authorized,
63,104,322 and 63,081,322 shares issued and 63,079,322
and 63,081,322 outstanding ............................. 316 315
Capital in excess of par value ............................ 323,776 324,077
Retained earnings ......................................... 420,618 428,443
Accumulated other comprehensive loss ...................... (31,071) (21,632)
---------- ----------

713,639 731,203
Less unamortized cost of restricted stock awards .......... 1,239 1,760
---------- ----------

712,400 729,443
---------- ----------

$2,054,956 $2,096,788
========== ==========

See notes to unaudited consolidated financial statements.

-4-

VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
----------------------------------------

CONSOLIDATED STATEMENTS OF OPERATIONS
-------------------------------------
(In thousands, except per share amounts)
(Unaudited)

Three Months Ended
March 31,
-------------------
2002 2001
-------- --------

REVENUES:
Oil and gas sales ................................... $122,568 $206,879
Gas marketing ....................................... 12,328 59,323
Oil and gas gathering ............................... 1,385 8,109
Foreign currency exchange gain ...................... 2,892 147
Other income ........................................ 645 1,032
-------- --------
139,818 275,490
-------- --------
COSTS AND EXPENSES:
Lease operating, including production taxes ......... 48,919 47,856
Exploration costs ................................... 8,953 2,203
Gas marketing ....................................... 11,804 57,326
Oil and gas gathering ............................... 1,777 8,355
General and administrative .......................... 13,042 11,979
Depreciation, depletion and amortization ............ 49,773 27,591
Interest ............................................ 17,437 10,917
-------- --------
151,705 166,227
-------- --------
Income (loss) before income taxes ................ (11,887) 109,263
-------- --------
PROVISION (BENEFIT) FOR INCOME TAXES:
Current ............................................. 2,039 22,238
Deferred ............................................ (8,306) 16,327
-------- --------
(6,267) 38,565
-------- --------
NET INCOME (LOSS) ...................................... $ (5,620) $ 70,698
======== ========

BASIC INCOME (LOSS) PER SHARE .......................... $ (0.09) $ 1.12
======== ========

DILUTED INCOME (LOSS) PER SHARE ........................ $ (0.09) $ 1.10
======== ========

Weighted Average Common Shares Outstanding:
Basic ............................................... 63,083 62,898
======== ========
Diluted ............................................. 63,083 64,055
======== ========

See notes to unaudited consolidated financial statements.

-5-

VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
----------------------------------------

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS' EQUITY
---------------------------------------------------------

AND COMPREHENSIVE LOSS
----------------------

FOR THE THREE MONTHS ENDED MARCH 31, 2002
-----------------------------------------
(In thousands)
(Unaudited)

Capital Accumulated
Treasury In Unamortized Other
Common Stock Stock Excess Restricted Compre-
--------------- -------- of Par Stock Retained hensive
Shares Amount Shares Value Awards Earnings Loss Total
------ ------ -------- -------- ----------- ---------- ----------- --------

BALANCE AT DECEMBER 31, 2001 ....... 63,081 $315 -- $324,077 $(1,760) $428,443 $(21,632) $729,443

Comprehensive loss:
Net loss ..................... -- -- -- -- -- (5,620) -- (5,620)
Foreign currency
translation
adjustment ................ -- -- -- -- -- -- (500) (500)
Change in value of
derivatives................ -- -- -- -- -- -- (8,939) (8,939)
--------
Total comprehensive loss ..... (15,059)

Exercise of stock options and
resulting tax effects ........ 23 1 -- 205 -- -- -- 206
Amortization of restricted
stock awards ................. -- -- -- -- 170 -- -- 170
Forfeiture of restricted
stock ........................ (25) -- 25 (506) 351 -- -- (155)
Cash dividends declared
($.035 per share) ............ -- -- -- -- -- (2,205) -- (2,205)
------ ---- --- -------- ------- -------- -------- --------
BALANCE AT MARCH 31, 2002 .......... 63,079 $316 25 $323,776 $(1,239) $420,618 $(31,071) $712,400
====== ==== === ======== ======= ======== ======== ========

See notes to unaudited consolidated financial statements.

-6-

VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
----------------------------------------

CONSOLIDATED STATEMENTS OF CASH FLOWS
-------------------------------------
(In thousands)
(Unaudited)

Three Months Ended
March 31,
--------------------
2002 2001
-------- --------

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) ............................................. $ (5,620) $ 70,698
Adjustments to reconcile net income (loss) to cash
provided by operating activities -
Depreciation, depletion and amortization ................ 49,773 27,591
Exploration costs ....................................... 8,953 2,203
Provision (benefit) for deferred income taxes ........... (8,306) 16,327
Foreign currency exchange gain .......................... (2,892) (147)
Gain on disposition of assets ........................... (85) (26)
Other non-cash items .................................... (177) --
-------- --------
41,646 116,646

Increase (decrease) in receivables ............................ (4,479) 34,478
Decrease in payables and accrued liabilities .................. (13,671) (17,693)
Other working capital changes ................................. 6,484 (3,491)
-------- --------
Cash provided by operating activities ................ 29,980 129,940
-------- --------

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures -
Oil and gas properties ..................................... (34,271) (26,825)
Gathering systems and other ................................ 494 (1,745)
Proceeds from sales of oil and gas properties ................. 7,195 --
Other ......................................................... (2,014) (1,473)
-------- --------
Cash used by investing activities .................... (28,596) (30,043)
-------- --------

CASH FLOWS FROM FINANCING ACTIVITIES:
Issuance of common stock ...................................... 398 1,126
Advances on revolving credit facility and other borrowings .... 68,006 12,427
Payments on revolving credit facility and other borrowings .... (66,000) (66,965)
Dividends paid ................................................ (2,205) (1,884)
Other ......................................................... (332) (2,390)
-------- --------
Cash provided (used) by financing activities ......... (133) (57,686)
-------- --------

EFFECT OF EXCHANGE RATE CHANGE ON CASH ........................... 6 --
-------- --------

NET INCREASE IN CASH AND CASH EQUIVALENTS ........................ 1,257 42,211

CASH AND CASH EQUIVALENTS, beginning of period ................... 15,454 19,506
-------- --------
CASH AND CASH EQUIVALENTS, end of period ......................... $ 16,711 $ 61,717
======== ========

See notes to unaudited consolidated financial statements.

-7-

VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
----------------------------------------

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
----------------------------------------------------
March 31, 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
(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 restated to conform
with the 2002 presentation. 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 estimated 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, no Genesis activity is included in the Company's statement of operations
for the three months ended March 31, 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 gain or
loss on the sale of properties on a field basis.

Unproved leasehold costs are capitalized and are reviewed periodically for
impairment. Costs related to impaired prospects are charged to expense. An
impairment expense could result if oil and gas prices decline in the future, as
it may not be economic to develop some of these unproved properties.

-8-

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. The
liability will accrete over time with a charge to interest expense. The new
standard will apply to financial statements for years beginning after June 15,
2002. While the new standard will require that the Company change its accounting
for such abandonment obligations, the Company has not had an opportunity to
evaluate 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 methods used for acquisition
evaluations.

In estimating the future net revenues at March 31, 2002, to be used for
impairment testing, the Company assumed that oil and gas prices and operating
costs would escalate annually, beginning at current levels. Due to the
volatility of oil and gas prices, it is possible that the Company's assumptions
regarding oil and gas prices may change in the future and may result in future
impairment provisions. No impairment provision related to proved oil and gas
properties was required for the first three months of either 2002 or 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 establishes
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.

Goodwill

Goodwill represents the excess of the purchase price over the estimated
fair value of the net assets acquired in the purchase of Genesis. 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
March 31, 2002, and December 31, 2001.

-9-

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's May 2001 acquisition of Genesis was accounted for using the
purchase method of accounting. The Company adopted SFAS No. 142 effective
January 1, 2002, resulting in the elimination of goodwill amortization from
statements of operations in future periods. Management has not determined at
this time if the adoption of SFAS No. 142 will have any other impact on the
Company's financial position or results of operations.

Management is engaging an independent appraisal firm to perform an
assessment of the fair value of its Canadian reporting unit, which will be
compared with the carrying value of the reporting unit to determine whether any
indication of impairment existed on the date of adoption. Under the provisions
of SFAS No. 142, the Company has six months from the time of adoption to have
its appraisal completed. To the extent the Canadian reporting unit's carrying
amount exceeds its fair value, an indication exists that the reporting unit's
goodwill may be impaired and the Company must perform the second step of the
impairment test. In the second step, the Company must compare the implied fair
value of the Canadian reporting unit's goodwill, determined by allocating the
reporting unit's fair value to all of its assets (recognized and unrecognized)
and liabilities in a manner similar to a purchase price allocation in accordance
with SFAS No. 141, to its carrying amount, both of which would be measured as of
January 1, 2002. This second step is required to be completed as soon as
possible, but no later than the end of 2002. Any transitional impairment loss
will be recognized as the cumulative effect of a change in accounting principle
in the Company's 2002 statement of operations. Any previously issued financial
statements for 2002 are required to be restated at the time such impairment loss
is recognized.

Hedging

The Company periodically uses hedges (swap agreements) to reduce the impact
of oil and gas price fluctuations. Gains or losses on swap agreements are
recognized as an adjustment to sales revenue when the related transactions being
hedged are finalized. Gains or losses from swap agreements 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.

-10-

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 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 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 adjustment to accumulated other comprehensive income in the
Stockholders' Equity section of the balance sheet of approximately $14.9
million. The amount recorded to accumulated other comprehensive income was
relieved and taken to the statement of operations as the physical transactions
being hedged were finalized. A significant portion of the Company's cash flow
hedges in place at January 1, 2001, had settled as of March 31, 2001, with the
actual cash flow impact recorded in oil and gas sales in the Company's statement
of operations. At March 31, 2002, the Company had a derivative financial
instrument payable of $9.9 million related to 2002 cash flow hedges in place.
During the first three months of 2002 and 2001, there were no significant gains
or losses recognized in earnings for hedge ineffectiveness. 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 three months ended March 31, 2002 and 2001, the Company made
cash payments for interest totaling $8.6 million, and $6.3 million,
respectively. Cash payments made for U.S. income taxes of $6.2 million and
$41,000 were made during the first three months of 2002 and 2001, respectively.
The Company made cash payments of $1.6 million and $2.3 million during the first
three months of 2002 and 2001, respectively, for foreign income taxes, primarily
in Canada.

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 the first three months of 2001 were computed
assuming the exercise of all dilutive options, as determined by applying the
treasury stock method. For the three months ended March 31, 2002, the
computation of diluted loss per share was antidilutive; therefore, the amounts
reported for basic and diluted loss per share were the same. Had the Company
been in a net income position for this period, the Company's diluted weighted
average outstanding common shares would have been 63,532,680. In addition, for
the three months ended March 31, 2002 and 2001, the Company had outstanding
stock options for 3,138,850 and 638,000 additional shares of the Company's
common stock, respectively, with average exercise prices of $19.16 and $21.82,
respectively, which were antidilutive.

-11-

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 in
effect caused a devaluation of the peso in December 2001. Because
exchangeability of the peso was lacking from early December 2001 to January 11,
2002 (the first date subsequent to year end at which exchanges could be made),
the Company used the estimated exchange rate of 1.65 pesos to one U.S. dollar at
January 11, 2002, to translate peso-denominated balances at December 31, 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 March 31, 2002, was 2.90 pesos to one U.S.
dollar.

On February 3, 2002, Decree 214 required all contracts that were previously
payable in U.S. dollars to be payable in pesos. U.S. dollars in Argentine banks
on this date were converted to pesos at the government-imposed rate of 1.4 pesos
to one U.S. dollar and U.S. dollar obligations with banks were converted to
pesos at the government-imposed rate of one peso to one U.S. dollar. On January
10, 2002, all bank accounts above a certain amount were converted to fixed-term
deposits scheduled to be returned to deposit holders in pesos beginning in
January 2003. Pursuant to an emergency law passed on January 10, 2002, U.S.
dollar obligations between private parties due after January 6, 2002, are to be
liquidated in pesos at a negotiated rate of exchange which reflects a sharing of
the impact of the devaluation. This emergency law requires the obligor to make
an interim payment of one peso per U.S. dollar of the claim and provides a
period of 180 days for the parties to negotiate the final amount to settle the
U.S. dollar obligation. The settlements in pesos of the existing U.S.
dollar-denominated agreements were substantially completed by March 31, 2002,
thus, future quarters should not be impacted by this mandate. This
government-mandated "equitable sharing" of the impact of the devaluation
resulted in a reduction in first quarter 2002 oil revenues from domestic sales
in Argentina of approximately $8 million, or $2.73 per Argentine Bbl produced or
$1.46 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, and essentially offset the
negative impact on Argentine oil revenues.

-12-

Absent the January 10, 2002, emergency law, 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 this
involuntary conversion was recorded in January 2002 and is reflected in "Other
income" in the accompanying statement of operations. The translation of
peso-denominated balances at March 31, 2002, and peso-denominated transactions
during the three months ended March 31, 2002, resulted in a foreign currency
exchange gain of $2.9 million.

Lease Operating Expense

For the three months ended March 31, 2002 and 2001, the Company recorded in
lease operating expenses gross production taxes of $2.3 million and $5.1
million, respectively. For the three months ended March 31, 2002 and 2001, the
Company recorded in lease operating expenses, transportation and storage
expenses of approximately $3.2 million and $2.8 million, respectively.

Comprehensive Loss

The Company had foreign currency translation losses of approximately $0.5
million for the three months ended March 31, 2002, which are included in
accumulated other comprehensive loss in the Stockholders' Equity section of the
accompanying balance sheet.

During the three months ended March 31, 2002, the Company also recorded
under SFAS No. 133 an $8.9 million charge to other comprehensive loss (net of a
$5.8 million tax benefit) for changes in unrealized derivative gains and losses
related to oil and gas price swaps and gas basis swaps. This charge consists of
the removal of a $3.0 million unrealized gain (net of $1.9 million tax expense)
for derivative contracts in place at December 31, 2001, which settled in 2002
and the recording of unrealized losses of $5.9 million (net of $3.9 million tax
benefit) related to open derivative contracts at March 31, 2002, that will
settle later in 2002. The actual cash flow gain from settled oil swaps of $0.8
million has been reflected in "Oil and gas sales" on the Company's statement of
operations for the three months ended March 31, 2002.

-13-

3. LONG-TERM DEBT

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

March 31, December 31,
(In thousands) 2002 2001
---------- ------------

Revolving credit facility ................................ $ 412,500 $ 411,400
Senior subordinated notes:
9% Notes due 2005, less unamortized discount .......... 149,847 149,837
8 5/8% Notes due 2009, less unamortized discount ...... 99,521 99,503
9 3/4% Notes due 2009 ................................. 150,000 150,000
7 7/8% Notes due 2011, less unamortized discount ...... 199,935 199,933
---------- ----------
$1,011,803 $1,010,673
========== ==========

The Company had $17.3 million and $9.5 million of accrued interest payable
related to its long-term debt at March 31, 2002, and December 31, 2001,
respectively, included in other payables and accrued liabilities.

On May 2, 2002, the Company issued, through a Rule 144A offering, $350
million of its 8 1/4% Senior Notes due 2012 (the "8 1/4% 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 $150 million 9% Senior Subordinated Notes due 2005 (the "9% Notes"),
for which the Company has initiated a call for redemption. The 8 1/4% 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 8 1/4% Notes with the proceeds of certain underwritten
public offerings of the Company's common stock. The 8 1/4% 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 8 1/4% 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 8 1/4% 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 will be available
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 ($300 million at May 2, 2002) is based on the bank's
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.

-14-

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 bank's commitment.

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 will be
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 all of the Company's existing and future U.S. subsidiaries, if any, 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 will be required to expense certain associated deferred financing costs
and discounts. This $5.3 million non-cash charge, along with the $3.0 million
cash charge for the call premium on the 9% Notes, will result in a one-time
charge of approximately $8.3 million ($5.1 million net of tax) in the second
quarter of 2002.

4. 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.

-15-

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, Yemen and
Trinidad. Summarized financial information for the Company's reportable segments
for the first quarters of 2002 and 2001 is shown in the following table (in
thousands):

Exploration and Production
---------------------------------------------------------------
Other
U.S. Canada Argentina Bolivia Ecuador Foreign
-------- -------- --------- -------- ------- --------

2002 - 1/st/ Quarter
--------------------
Revenues from external customers .. $ 45,132 $ 24,851 $ 44,813 $ 3,612 $ 4,068 $ --
Intersegment revenues ............. -- -- -- -- -- --
Depreciation, depletion and
amortization expense ........... 15,561 18,884 12,658 1,173 518 --
Operating income (loss) ........... 3,351 (11,080) 20,849 1,286 1,484 (80)
Total assets ...................... 454,446 814,330 515,888 119,490 59,739 29,259
Capital investments ............... 7,236 19,351 7,961 99 636 288
Long-lived assets ................. 423,686 789,453 471,232 92,414 49,842 28,558

Gathering/ Gas
Plant Marketing Corporate Total
---------- --------- --------- ----------

2002 - 1/st/ Quarter
--------------------
Revenues from external customers .. $1,385 $12,328 $ 3,629 $ 139,818
Intersegment revenues ............. -- 171 -- 171
Depreciation, depletion and
amortization expense ........... 276 -- 703 49,773
Operating income (loss) ........... (667) 524 2,925 18,592
Total assets ...................... 8,348 6,877 46,579 2,054,956
Capital investments ............... -- -- 498 36,069
Long-lived assets ................. 6,010 -- 7,798 1,868,993

Exploration and Production
---------------------------------------------------------------
Other
U.S. Canada Argentina Bolivia Ecuador Foreign
-------- -------- --------- -------- ------- --------

2001 - 1/st/ Quarter
--------------------
Revenues from external customers .. $123,840 $ 5,621 $ 67,480 $ 4,386 $ 6,064 $ --
Intersegment revenues ............. -- -- -- -- -- --
Depreciation, depletion and
amortization expense ........... 13,911 1,658 9,558 1,006 562 --
Operating income (loss) ........... 78,416 2,046 44,057 2,495 3,405 217
Total assets ...................... 524,490 55,131 447,633 122,763 52,781 23,993
Capital investments ............... 11,876 1,658 13,974 536 2,137 228
Long-lived assets ................. 473,154 50,388 405,810 97,049 43,214 23,312

Gathering/ Gas
Plant Marketing Corporate Total
---------- --------- --------- ----------

2001 - 1/st/ Quarter
--------------------
Revenues from external customers .. $ 8,109 $ 59,323 $ 667 $ 275,490
Intersegment revenues ............. -- 783 -- 783
Depreciation, depletion and
amortization expense ........... 306 -- 590 27,591
Operating income (loss) ........... (553) 1,998 78 132,159
Total assets ...................... 12,084 24,653 91,149 1,354,677
Capital investments ............... 392 -- 1,352 32,153
Long-lived assets ................. 5,954 -- 5,702 1,104,583

-16-

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
are not allocated to segments.

5. COMMITMENTS AND CONTINGENCIES

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 approximately $4.2 million. The Company is also committed to
drill one well in the Chaco concession in Bolivia in 2003 at an estimated cost
of $6.3 million and to drill two wells on the Damis S-1 concession in Yemen
prior to October 2004 at an estimated cost of $6.0 million.

Through its December 2000 acquisition of Cometra Energy (Canada) Ltd.
("Cometra"), the Company assumed the drilling obligations of Cometra's
wholly-owned subsidiary, Cometra Trinidad Limited. These obligations require the
acquisition of 15 line kilometers of 2-D seismic, 40 square kilometers of 3-D
seismic and drilling of three exploratory wells. As of March 31, 2002, the
Company had fulfilled the seismic requirements and had drilled two of the three
exploratory wells.

The Company had $12.3 million in letters of credit outstanding at March 31,
2002 ($18.2 million at May 2, 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.

-17-

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
March 31,
--------------------------
2002 2001
------------- ----------
Production:
Oil (MBbls) -
U.S ....................................... 1,746 2,185
Canada .................................... 528 59
Argentina ................................. 2,993(a) 2,476(b)
Ecuador ................................... 264 337(b)
Bolivia ................................... 40(a) 23(b)
Total ................................. 5,571(a) 5,080(b)
Gas (MMcf) -
U.S ....................................... 5,952 8,561
Canada .................................... 7,155 830
Argentina ................................. 1,502 2,042
Bolivia ................................... 2,027 1,867
Total .................................. 16,636 13,300
Total MBOE ................................... 8,344 7,297

Average prices:
Oil (per Bbl) -
U.S ....................................... $ 18.22(c) $ 25.68(d)
Canada .................................... 17.71 26.39
Argentina ................................. 14.75(c)(e) 26.05(d)
Ecuador ................................... 15.42 17.98
Bolivia ................................... 18.17 30.66
Total .................................. 16.18(c)(e) 25.38(d)
Gas (per Mcf) -
U.S ....................................... $ 2.23 $ 7.85
Canada .................................... 2.19 4.89
Argentina ................................. 0.44 1.45
Bolivia ................................... 1.43 1.97
Total .................................. 1.95 5.86

------------------
(a) Total production for the three months ended March 31, 2002, before the
impact of changes in inventories was 5,412 MBbls (Argentina - 2,846
MBbls, Bolivia - 28 MBbls).
(b) Total production for the three months ended March 31, 2001, before the
impact of changes in inventories was 5,163 MBbls (Argentina - 2,544
MBbls, Ecuador - 350 MBbls, Bolivia - 25 MBbls).
(c) Reflects the impact of oil hedges which decreased the Company's first
quarter 2002 Argentina average oil price by $0.07 and increased the
Company's first quarter 2002 U.S. and total average oil prices per Bbl
by $0.57 and $0.14, respectively.
(d) Reflects the impact of oil hedges which increased the Company's first
quarter 2001 U.S., Argentina and total average oil prices per Bbl by
$0.62, $1.88 and $1.19, respectively.
(e) Average oil prices for the three months ended March 31, 2002, before
the impact of Argentine government mandated settlements, were $17.48
per Bbl for Argentina and $17.64 per Bbl for total company. No ongoing
impact from these settlements is expected.

-18-

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 36 percent decrease in
its average oil price, including the impact of hedging activities (34 percent
decrease excluding hedging impact), during the first quarter of 2002 as compared
to the same period of 2001. The Company's realized average oil price for the
first three months of 2002 (before hedges) was approximately 74 percent of the
NYMEX reference price (82 percent excluding the negative impact of the Argentine
government mandated settlements) compared to 84 percent for the same period of
2001.

As discussed elsewhere in this Form 10-Q, 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. The tax is limited by law
to a term of no more than five years. 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.

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 Company also believes the U.S. dollar
equivalent value for domestic Argentina oil sales (now paid in pesos) will move
over time to parity with the U.S. dollar-denominated export values, net of the
export tax, thus impacting domestic Argentina values by a like percentage to the
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 may be
further reduced by the Argentina income tax savings related to deducting such
impact.

The Company participated in oil hedges covering 1.15 MMBbls and 2.16 MMBbls
during the first three months of 2002 and 2001, respectively. The impact of the
2002 hedges increased the Company's U.S. average oil price for the first three
months of 2002 by $0.57 to $18.22 per Bbl, decreased its Argentina average oil
price by $0.07 to $14.75 per Bbl and increased its overall average oil price by
$0.14 to $16.18 per Bbl. The impact of the 2001 hedges increased the Company's
U.S. average oil price for the first three months of 2001 by $0.62 to $25.68 per
Bbl, its Argentina average oil price by $1.88 to $26.05 per Bbl and its overall
average oil price by $1.19 to $25.38 per Bbl.

-19-

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 market conditions improve. The Company's total average realized gas
price for the first three months of 2002 was 67 percent lower than the same
period of 2001.

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 1,055,000 Bbls of its
U.S. and Argentina oil production at a weighted average NYMEX reference price of
$23.82 per Bbl for the second quarter of 2002. The Company has also entered into
various gas price swap agreements covering approximately 40,000 MMBtu per day of
its gas production for the period April 1 through October 31, 2002. The Canadian
portion of the gas price swap agreements (approximately 20,000 MMBtu per day) is
at the 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 20,000 MMBtu per day) is at a NYMEX reference price of
$2.60 per MMBtu.

Additionally, the Company has entered into two costless price collar
arrangements for U.S. gas production. The first price collar covers production
of 6,500 MMBtu per day for the period from June 1 through October 31, 2002, with
a floor NYMEX reference price of $3.50 per MMBtu and a cap NYMEX reference price
of $4.00 per MMBtu. The second price collar covers production of 20,000 MMBtu
per day for the period November 1 through December 31, 2002, with a floor NYMEX
reference price of $3.50 per MMBtu and a cap NYMEX reference price of $5.10 per
MMBtu.

In conjunction with each of the 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 counterparties to the Company's swap agreements are commercial banks.
The Company has no derivative contracts with Enron Corp. or any of its
affiliates.

The Company continues to monitor oil and gas prices and may enter into
additional oil and gas hedges or swaps in the future.

-20-

Relatively modest changes in either oil or gas prices significantly impact
the Company's results of operations and cash flow. 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. Based on first quarter 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 loss and cash flow before income taxes on an annual
basis of approximately $3.5 million and $5.5 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 loss and cash flow before income taxes on an
annual basis of approximately $1.0 million and $1.6 million, respectively, based
on first quarter 2002 gas production.

Period to Period Comparison

Three Months ended March 31, 2002, Compared to Three Months ended March 31, 2001

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 three months ended March 31,
2002, compared to the three months ended March 31, 2001. The Company's
consolidated revenues and expenses for the three months ended March 31, 2001,
under the purchase method of accounting, include no activities of Genesis.

The Company reported a net loss of $5.6 million for the three months ended
March 31, 2002, compared to net income of $70.7 million for the same period in
2001. A 14 percent increase in production on a BOE basis was more than offset by
a 67 percent decrease in average gas prices and a 36 percent decrease in average
oil prices received by the Company.

Oil and gas sales decreased $84.3 million (41 percent), to $122.6 million
for the first three months of 2002 from $206.9 million for the same period in
2001. A 10 percent increase in oil production was more than offset by a 36
percent decrease in average oil prices received by the Company and accounted for
a $38.8 million decrease in oil sales for the first quarter of 2002 as compared
to the first quarter of 2001. In addition to the decline in market prices for
oil, the Company's realized oil price for the three months ended March 31, 2002,
was reduced by approximately $1.46 per barrel as a result of Argentine
government-mandated negotiated settlements of all U.S. dollar-denominated
domestic sales amounts in existence at January 6, 2002. The mandate required
these agreements to be settled in pesos with a negotiated, equitable sharing of
the impact of devaluation. These negotiations were substantially completed in
the first quarter of 2002 and no ongoing impact from these settlements is
expected. A 25 percent increase in gas production was also more than offset by a
67 percent decrease in average gas prices received by the Company and accounted
for a $45.5 million decrease in gas sales for the first quarter of 2002 as
compared to the first quarter of 2001. The 10 percent increase in oil production
and the 25 percent increase in gas production are primarily the result of the
acquisitions of Genesis and the LaVentana concession in Argentina and the
Company's exploitation and exploration activities, partially offset by natural
production declines and the reduced volumes resulting from U.S. property sales
in the fourth quarter of 2001.

-21-

As discussed in Note 2 to the Company's consolidated financial statements
included elsewhere in this Form 10-Q, the Argentine government took actions
which, in effect, caused the devaluation of the peso in early December 2001.
During the first three 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
2.90 pesos to one U.S. dollar at March 31, 2002. The translation of
peso-denominated balances at March 31, 2002, and peso-denominated transactions
during the three months ended March 31, 2002, resulted in a foreign currency
exchange gain of $2.9 million. The Company also recorded a gain of $0.9 million
in "Other income" for the first quarter 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 three months ended March 31, 2001.

Lease operating expenses, including production taxes, increased $1.0
million (two percent), to $48.9 million for the first three months of 2002 from
$47.9 million for the same period of 2001. General and administrative expenses
increased $1.0 million (eight percent), to $13.0 million for the three months
ended March 31, 2002, from $12.0 million for the same period in 2001. Lease
operating expenses per equivalent barrel produced decreased 11 percent to $5.86
for the three months ended March 31, 2002, from $6.56 for the same period in
2001. General and administrative expenses per equivalent barrel produced
decreased five percent to $1.56 for the three months ended March 31, 2002, from
$1.64 for the same period in 2001. These decreases per equivalent barrel
produced resulted from the impact of the Argentine peso devaluation on
peso-denominated costs and the government-mandated negotiated settlement of U.S.
dollar-denominated agreements affecting the Company's costs.

Exploration costs increased $6.8 million (309 percent), to $9.0 million for
the three months ended March 31, 2002 from $2.2 million for the same period in
2001. The Company's exploration costs for the first three months of 2002
included $5.5 million for unsuccessful exploratory drilling and lease
impairments, primarily in North America, and $3.5 million for seismic and other
geological and geophysical costs. Exploration costs for the first three months
of 2001 included $1.5 million for unsuccessful exploratory drilling and lease
impairments, primarily in the U.S. and $0.7 million for seismic and other
geological and geophysical costs.

Depreciation, depletion and amortization increased $22.2 million (80
percent), to $49.8 million for the first quarter of 2002 from $27.6 million for
the first quarter of 2001, due primarily to the 14 percent increase in
production on a BOE basis and the 60 percent increase in the average
amortization rate per equivalent barrel produced from $3.65 in the first three
months of 2001 to $5.84 in the first three months of 2002 primarily due to the
acquisition of Genesis and the impact of substantially lower commodity prices on
proved reserves used to determine the amortization rate.

Interest expense increased $6.5 million (60 percent), to $17.4 million for
the three months ended March 31, 2002, from $10.9 million for the same period in
2001, due primarily to higher outstanding borrowings resulting from the
acquisition of Genesis and other acquisitions made subsequent to the first
quarter of 2001.

-22-

Capital Expenditures

During the three months ended March 31, 2002, the Company's total oil and
gas capital expenditures were $35.6 million. In North America, the Company's
non-acquisition oil and gas capital expenditures totaled $26.6 million.
Exploitation activities accounted for $13.9 million of the North America capital
expenditures with exploration activities contributing $12.7 million. During the
first three months of 2002, the Company's international non-acquisition oil and
gas capital expenditures totaled $9.0 million, consisting of $8.0 million in
Argentina on exploitation activities, $0.6 million in Ecuador, principally on
exploitation, and $0.4 million on exploration projects primarily in Yemen.

As of March 31, 2002, the Company had total unproved oil and gas property
costs of approximately $104.1 million consisting of undeveloped leasehold costs
of $81.5 million, including $59.1 million in Canada, and exploratory drilling in
progress of $22.6 million. Approximately $20.9 million of the unproved costs are
associated with the Company's Yemen drilling program. Future exploration expense
and earnings may be impacted to the extent any of the exploratory drilling is
determined to be unsuccessful.

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 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, the borrowing capacity under its revolving
credit facility and its ability to adjust its level of capital expenditures 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 private debt offerings, which provided
the Company with aggregate net proceeds of $1.2 billion.

-23-

After giving effect to the use of the net proceeds from the offering of the
8 1/4% Notes and the partial redemption of the 9% Notes and taking into account
the Company's outstanding letters of credit of approximately $18.2 million, the
unused availability under the Company's new Bank Facility was approximately $105
million as of May 2, 2002. 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.

-24-

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 three months ended March 31, 2002, decreased by 36 percent as
compared to the same period in 2001. Realized gas prices for the first three
months of 2002, decreased by 67 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.

In conjunction with the elimination of the Company's previously existing
revolving credit facility and the partial redemption of the 9% Notes, the
Company will be required to expense certain deferred financing costs and
discounts. This $5.3 million non-cash charge, along with the $3.0 million
cash charge for the call premium on the 9% Notes, will result in a one-time
charge of approximately $8.3 million ($5.1 million net of tax) in the second
quarter of 2002.

Consistent with its stated goal of maintaining financial flexibility and
optimizing its portfolio of assets, the Company recently 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 had 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,
have been identified 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, the Company expects
inflationary pressures to build in Argentina. The Company anticipates that
peso-denominated costs will gradually increase, but the ultimate impact of such
increases when converted to U.S. dollars cannot be determined due to the
uncertainty of future currency exchange rates.

Income Taxes

The Company incurred a current provision for income taxes of approximately
$2.0 million and $22.2 million for the first three 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. No U.S. deferred tax liability will be recognized related
to the unremitted earnings of these foreign subsidiaries as it is the Company's
intention, generally, to reinvest such earnings permanently.

-25-

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 2 to the Company's consolidated financial
statements included elsewhere in this Form 10-Q, contains 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 by 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.

-26-

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 methods
used for acquisition evaluations.

Impairment of unproved oil and gas properties. Unproved leasehold costs are
capitalized and are reviewed periodically for impairment. Costs related to
impaired prospects are charged to expense. An impairment expense could result if
oil and gas prices decline in the future as it may not be economic to develop
some of these unproved properties.

Revenue recognition. Revenue is a key component of the Company's results of
operations and also determines the timing of certain expenses, such as severance
taxes and royalties. 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 some 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. The Argentina 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.

-27-

Change 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. The 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.

-28-

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 for
years beginning after June 15, 2002. While the new standard will require that
the Company change its accounting for such abandonment obligations, the Company
has not had an opportunity to evaluate 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.

-29-

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 realization
targets, 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 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; continued availability of capital and financing; general
economic, market or business conditions; acquisition opportunities (or lack
thereof); 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.

-30-

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 first quarter 2002 production levels. 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.

During 2001 and 2002, the Company entered into various oil price swap
agreements covering approximately 2.2 MMBbls of its U.S. and Argentina oil
production at a weighted average NYMEX reference price of $23.77 per Bbl for
various periods in the first half of 2002. As of March 31, 2002, swap agreements
remaining covered approximately 1,055,000 Bbls of future U.S. and Argentina oil
production at a weighted average NYMEX reference price of $23.82 per Bbl. The
Company has also entered into various gas price swap agreements covering
approximately 40,000 MMBtu per day of its gas production over the period April 1
through October 31, 2002. The Canadian portion of the gas price swap agreements
(approximately 20,000 MMBtu per day) is at the 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 20,000 MMBtu
per day) is at a NYMEX reference price of $2.60 per MMBtu.

The Company continues to monitor oil and gas prices and may enter into
additional oil and gas hedges or swaps in the future.

-31-

Interest Rate Risk

The Company's interest rate risk exposure results primarily from short-term
rates, mainly LIBOR based 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 March 31, 2002, the amount of the
Company's fixed rate debt was approximately 59 percent of total debt (83 percent
at May 2, 2002). 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 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
March 31, 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 $2.5 million and $4.2 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 as of March 31, 2002:

Fair
Value
There- at
2002 2003 2004 2005 2006 after Total 03/31/02
---- ---- ---- -------- ---- -------- -------- --------

Long-Term Debt:
Fixed rate (in thousands) ...... -- -- -- $149,847 -- $449,456 $599,303 $578,333
Average interest rate .......... -- -- -- 9.0% -- 8.7% 8.8% --
Variable rate (in thousands).... -- -- -- $412,500 -- -- $412,500 $412,500
Average interest rate .......... -- -- -- (a) -- -- (a) (a)

(a) LIBOR plus an increment, based on the level of outstanding senior debt
to the borrowing base, up to a maximum increment of 2.0 percent. The
increment above LIBOR at March 31, 2002, was 1.25 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, Yemen and
Trinidad. For the three months ended March 31, 2002, the Company's operations in
Argentina and Canada accounted for approximately 32 percent and 18 percent,
respectively, of the Company's revenues and, at March 31, 2002, the Company's
operations in Argentina and Canada accounted for approximately 25 percent and 40
percent, respectively, of the Company's total assets, including goodwill. During
the first three months of 2002 and at March 31, 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.

-32-

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 cash flows or investment returns so warrant.

The Company's international operations may be adversely affected by
political and economic instability, changes in the legal and regulatory
environment and other factors. The Company's foreign properties, operations or
investments in Canada, Argentina, Bolivia, Ecuador, Yemen and Trinidad may be
adversely affected by a number of 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 tax 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 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 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 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. The US$:C$ exchange rate at March 31, 2002, was US$1:C$1.59 as
compared to US$1:C$1.58 at March 31, 2001.

Argentina. Beginning in 1991, Peronist Carlos Menem, as newly-elected
President of Argentina, and Domingo Cavallo, as his economy minister, 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.

-33-

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 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.

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 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. Management also believes
that the U.S. dollar equivalent value for domestic Argentina oil sales (now paid
in pesos) will move over time to parity with the U.S. dollar-denominated export
values, net of the export tax, thus impacting domestic Argentina values by a
like percentage to the 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 may be further reduced by the Argentina income tax
savings related to deducting such impact.

-34-

The Company continues to monitor the political and economic environment in
Argentina. The Company's capital budgets have been adjusted to reflect a reduced
level of drilling in the country. In addition, the devaluation of the peso is
expected to result in a near-term reduction in revenues, substantially offset by
a reduction in peso-denominated operating, administrative and capital costs, and
the recognition of translation gains and losses, the impact of which cannot
currently be accurately estimated.

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.

The political environment in Bolivia has changed as President Hugo Banzer
resigned and handed over power to his Vice-President, Jorge Quiroga. Mr.
Quiroga, who is a U.S. educated industrial engineer, will run the country until
new elections are held, which are currently scheduled for June 30, 2002. He will
be barred from running in those elections due to term limits.

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 March 31, 2002, was US$1:Bs 7.03. 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.

Ecuador. In Ecuador, President Gustavo Noboa and Congress continue to
debate further tax, social, and customs reforms to strengthen economic growth.
The legal basis for many of the recent reforms is the Ley Fundamental para la
Transformacion Economica 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 International Monetary Fund ("IMF") to make a
disbursement of its stand-by loan in the second quarter of 2001. With the
presidential election approaching in the fourth quarter of 2002, the current
administration continues focusing on further fiscal reform and obtaining a one
year stand-by loan with the IMF. Fixed investments remain high as construction
of the new heavy oil pipeline (the "OCP") continues to progress on schedule.

-35-

PART II

OTHER INFORMATION

-36-

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
-----------------

not applicable

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

a) Exhibits

None

b) Reports on Form 8-K

None

-37-

Signatures
----------

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

VINTAGE PETROLEUM, INC.
-----------------------
(Registrant)

DATE: May 13, 2002 \s\ Michael F. Meimerstorf
------------ -------------------------------
Michael F. Meimerstorf
Vice President and Controller
(Principal Accounting Officer)

-38-