UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2002
OR
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 executive offices) (Zip Code)
(918) 592-0101
---------------------------
(Registrant's telephone number, including area code)
NOT APPLICABLE
--------------------------------------------------------------------------
(Former name, former address and former fiscal year, if changed since last
report)
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
Yes X No _____
-----
Indicate the number of shares outstanding of each of the registrant's classes of
common stock, as of the latest practicable date.
Class Outstanding at August 9, 2002
----------------------------- -----------------------------
Common Stock, $.005 Par Value 63,344,972
-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
------
June 30, December 31,
2002 2001
------------ -------------
(Unaudited)
CURRENT ASSETS:
Cash and cash equivalents ................................................. $ 32,678 $ 15,454
Accounts receivable -
Oil and gas sales .................................................... 79,729 77,628
Joint operations ..................................................... 12,596 9,354
Derivative financial instruments receivable ............................... 947 4,701
Prepaids and other current assets ......................................... 29,367 37,517
----------- ----------
Total current assets ................................................ 155,317 144,654
----------- ----------
PROPERTY, PLANT AND EQUIPMENT, at cost:
Oil and gas properties, successful efforts method ......................... 2,561,334 2,498,552
Oil and gas gathering systems and plants .................................. 20,192 20,508
Other ..................................................................... 26,378 25,506
----------- ----------
2,607,904 2,544,566
Less accumulated depreciation, depletion and amortization ................. 884,550 809,522
----------- ----------
1,723,354 1,735,044
----------- ----------
GOODWILL, net .................................................................. 104,455 156,990
----------- ----------
OTHER ASSETS, net .............................................................. 54,220 60,100
----------- ----------
$ 2,037,346 $2,096,788
=========== ==========
See notes to unaudited consolidated financial statements.
-3-
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
----------------------------------------
LIABILITIES AND STOCKHOLDERS' EQUITY
------------------------------------
June 30, December 31,
2002 2001
------------ --------------
(Unaudited)
CURRENT LIABILITIES:
Revenue payable ......................................................... $ 29,028 $ 25,625
Accounts payable - trade ................................................ 34,207 62,362
Current income taxes payable ............................................ 11,751 21,638
Short-term debt ......................................................... 5,660 17,320
Derivative financial instruments payable ................................ 1,317 -
Other payables and accrued liabilities .................................. 53,533 45,200
----------- -----------
Total current liabilities ............................................ 135,496 172,145
----------- -----------
LONG-TERM DEBT ............................................................... 1,016,428 1,010,673
----------- -----------
DEFERRED INCOME TAXES ........................................................ 166,841 166,319
----------- -----------
OTHER LONG-TERM LIABILITIES .................................................. 8,540 18,208
----------- -----------
COMMITMENTS AND CONTINGENCIES (Note 8)
STOCKHOLDERS' EQUITY per accompanying statement:
Preferred stock, $.01 par, 5,000,000 shares authorized,
zero shares issued and outstanding ................................... - -
Common stock, $.005 par, 160,000,000 shares authorized,
63,404,972 and 63,081,322 shares issued and
63,344,972 and 63,081,322 outstanding, respectively .................. 317 315
Capital in excess of par value .......................................... 326,256 324,077
Retained earnings ....................................................... 379,964 428,443
Accumulated other comprehensive income (loss) ........................... 6,554 (21,632)
----------- -----------
713,091 731,203
Less unamortized cost of restricted stock awards ........................ 3,050 1,760
----------- -----------
710,041 729,443
----------- -----------
$ 2,037,346 $ 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 Six Months Ended
June 30, June 30,
------------------- --------------------
2002 2001 2002 2001
--------- --------- --------- ---------
REVENUES:
Oil and gas sales ......................................................... $ 158,560 $ 208,504 $ 281,128 $ 415,383
Gas marketing ............................................................. 17,405 35,491 29,733 94,814
Oil and gas gathering and processing ...................................... 1,468 6,197 2,853 14,306
Gain (loss) on disposition of assets ...................................... 17,624 (2) 17,709 24
Foreign currency exchange gain ............................................ 1,244 97 4,136 244
Other income .............................................................. 469 1,627 1,030 2,633
--------- --------- --------- ---------
196,770 251,914 336,589 527,404
--------- --------- --------- ---------
COSTS AND EXPENSES:
Lease operating, including production and export taxes .................... 56,121 52,893 105,040 100,749
Exploration costs ......................................................... 6,975 3,489 15,928 5,692
Gas marketing ............................................................. 16,941 34,297 28,745 91,623
Oil and gas gathering and processing ...................................... 1,505 6,122 3,282 14,477
General and administrative ................................................ 13,495 12,113 26,537 24,092
Depreciation, depletion and amortization .................................. 46,696 40,397 96,469 67,988
Amortization of goodwill .................................................. - 2,774 - 2,774
Interest .................................................................. 20,741 15,874 38,178 26,791
Loss on early extinguishment of debt ...................................... 8,154 - 8,154 -
--------- --------- --------- ---------
170,628 167,959 322,333 334,186
--------- --------- --------- ---------
Income before income taxes and cumulative effect of change
in accounting principle ................................................ 26,142 83,955 14,256 193,218
PROVISION (BENEFIT) FOR INCOME TAXES:
Current ................................................................... 9,755 27,957 11,794 50,195
Deferred .................................................................. (6,042) 3,779 (14,347) 20,106
--------- --------- --------- ---------
3,713 31,736 (2,553) 70,301
--------- --------- --------- ---------
Income before cumulative effect of change in accounting principle ......... 22,429 52,219 16,809 122,917
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING
PRINCIPLE ................................................................. - - (60,547) -
--------- --------- --------- ---------
NET INCOME (LOSS) .............................................................. $ 22,429 $ 52,219 $ (43,738) $ 122,917
========= ========= ========= =========
BASIC INCOME (LOSS) PER SHARE:
Income before cumulative effect of change in accounting principle ......... $ 0.36 $ 0.83 $ 0.27 $ 1.95
Cumulative effect of change in accounting principle ....................... - - (0.96) -
--------- --------- --------- ---------
Net income (loss) ......................................................... $ 0.36 $ 0.83 $ (0.69) $ 1.95
========= ========= ========= =========
DILUTED INCOME (LOSS) PER SHARE:
Income before cumulative effect of change in accounting principle ......... $ 0.35 $ 0.81 $ 0.27 $ 1.92
Cumulative effect of change in accounting principle ....................... - - (0.95) -
--------- --------- --------- ---------
Net income (loss) ......................................................... $ 0.35 $ 0.81 $ (0.68) $ 1.92
========= ========= ========= =========
Weighted average common shares outstanding:
Basic ..................................................................... 63,128 63,031 63,102 62,964
========= ========= ========= =========
Diluted ................................................................... 63,925 64,153 63,858 64,104
========= ========= ========= =========
See notes to unaudited consolidated financial statements.
-5-
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS' EQUITY
AND COMPREHENSIVE INCOME (LOSS)
FOR THE SIX MONTHS ENDED JUNE 30, 2002
(In thousands)
(Unaudited)
Accumulated
Capital Other
In Unamortized Compre-
Treasury Excess Restricted hensive
Common Stock Stock of Par Stock Retained Income
------------- --------
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 income (loss):
Net loss ........................... - - - - - (43,738) - (43,738)
Foreign currency translation
adjustment ...................... - - - - - - 31,432 31,432
Change in value of derivatives ..... - - - - - - (3,246) (3,246)
----------
Total comprehensive loss ........... (15,552)
Exercise of stock options and
resulting tax effects .............. 63 1 - 513 - - - 514
Issuance of restricted stock ......... 261 1 - 2,879 (2,880) - - -
Amortization of restricted
stock awards ....................... - - - - 796 - - 796
Forfeiture of restricted stock ....... (60) - 60 (1,213) 794 - - (419)
Cash dividends declared
($.075 per share) .................. - - - - - (4,741) - (4,741)
------ ----- ------- --------- -------- --------- --------- ----------
BALANCE AT JUNE 30, 2002 ................ 63,345 $ 317 60 $ 326,256 $ (3,050) $ 379,964 $ 6,554 $ 710,041
====== ===== ======= ========= ======== ========= ========= ==========
See notes to unaudited consolidated financial statements.
-6-
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
(Unaudited)
Six Months Ended
June 30,
--------------------------
2002 2001
------------ -----------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) ......................................................... $ (43,738) $122,917
Adjustments to reconcile net income (loss) to cash provided by
operating activities -
Cumulative effect of change in accounting principle ................. 60,547 -
Depreciation, depletion and amortization ............................ 96,469 67,988
Amortization of goodwill ............................................ - 2,774
Exploration costs ................................................... 15,928 5,692
Provision (benefit) for deferred income taxes ....................... (14,347) 20,106
Foreign currency exchange gain ...................................... (4,136) (244)
Gain on disposition of assets ....................................... (17,709) (24)
Loss on early extinguishment of debt ................................ 8,154 -
Other non-cash items ................................................ 435 334
----------- --------
101,603 219,543
Decrease (increase) in receivables ........................................ (14,821) 44,744
Increase (decrease) in payables and accrued liabilities ................... (8,067) (41,543)
Other working capital changes ............................................. 10,529 (15,191)
----------- --------
Cash provided by operating activities ............................... 89,244 207,553
----------- --------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures -
Oil and gas properties ................................................. (60,691) (107,170)
Gathering systems and other ............................................ (2,059) (2,828)
Proceeds from sale of oil and gas properties .............................. 22,755 24
Purchase of company, net of cash acquired ................................. - (462,815)
Other ..................................................................... 2,033 (1,653)
----------- ---------
Cash used by investing activities ................................... (37,962) (574,442)
----------- --------
CASH FLOWS FROM FINANCING ACTIVITIES:
Issuance of common stock .................................................. 514 1,216
Issuance of 8 1/4% Senior Notes Due 2012 .................................. 350,000 -
Partial redemption of 9% Senior Subordinated Notes Due 2005 ............... (103,000) -
Advances on revolving credit facility and other borrowings ................ 153,433 455,537
Payments on revolving credit facility and other borrowings ................ (409,492) (75,629)
Dividends paid ............................................................ (6,949) (3,773)
Other ..................................................................... (9,875) 6,182
----------- --------
Cash provided (used) by financing activities ........................ (25,369) 383,533
----------- --------
EFFECT OF EXCHANGE RATE CHANGE ON CASH ......................................... (8,689) -
NET INCREASE IN CASH AND CASH EQUIVALENTS ...................................... 17,224 16,644
CASH AND CASH EQUIVALENTS, beginning of period ................................. 15,454 19,506
----------- --------
CASH AND CASH EQUIVALENTS, end of period ....................................... $ 32,678 $ 36,150
=========== ========
See notes to unaudited consolidated financial statements.
-7-
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2002 and 2001
1. GENERAL
The accompanying financial statements are unaudited. The consolidated
financial statements include the accounts of Vintage Petroleum, Inc. and its
wholly- and majority-owned subsidiaries and its proportionately consolidated
general partner and limited partner interests in various joint ventures and
partnerships (collectively, the "Company"). Management believes that all
material adjustments (consisting of only normal recurring adjustments) necessary
for a fair presentation have been made. Certain 2001 amounts have been
reclassified to conform with the 2002 presentation. All significant intercompany
accounts and transactions have been eliminated in consolidation.
On May 2, 2001, the Company completed the acquisition of Canadian-based
Genesis Exploration Ltd. ("Genesis") for total consideration of $617 million,
including transaction costs and the assumption of the net indebtedness of
Genesis at closing. The cash portion of the acquisition price was paid through
advances under the Company's revolving credit facility and cash on hand. The
acquisition of Genesis was accounted for using purchase accounting and, as such,
only two months of Genesis activity is included in the Company's statement of
operations for the three months and six months ended June 30, 2001.
The preparation of financial statements in conformity with accounting
principles generally accepted in the United States ("GAAP") requires management
to make estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities, if any, at the
date of the financial statements, and the reported amounts of revenues and
expenses during the reporting period. Actual results could differ from those
estimates. These financial statements and notes should be read in conjunction
with the 2001 audited financial statements and related notes included in the
Company's 2001 Annual Report on Form 10-K, Item 8, Financial Statements and
Supplementary Data.
2. SIGNIFICANT ACCOUNTING POLICIES
Oil and Gas Properties
Under the successful efforts method of accounting, the Company capitalizes
all costs related to property acquisitions and successful exploratory wells, all
development costs and the costs of support equipment and facilities. All costs
related to unsuccessful exploratory wells are expensed when such wells are
determined to be non-productive; other exploration costs, including geological
and geophysical costs, are expensed as incurred. The Company recognizes gain or
loss on the sale of properties on a field basis.
-8-
Unproved leasehold costs are capitalized and are reviewed periodically for
impairment on a property-by-property basis, considering factors such as future
drilling and exploitation plans and lease terms. Costs related to impaired
prospects are charged to expense. An impairment expense could result if oil and
gas prices decline in the future or if downward reserve revisions are recorded,
as it may not be economic to develop some of these unproved properties.
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 the financial statements of the Company beginning January
1, 2003. While the new standard will require that the Company change its
accounting for such abandonment obligations, the Company has not completed its
evaluation of the impact of the new standard on its financial statements.
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 the methods used for acquisition
evaluations. No impairment provision related to proved oil and gas properties
was required for the first six months or the second quarter 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 creates accounting
and reporting standards to establish a single accounting model, based on the
framework established in Statement of Financial Accounting Standards No. 121,
Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to
Be Disposed Of, for long-lived assets to be disposed of by sale. The adoption of
SFAS No. 144 did not have a material impact on the Company's financial position
or results of operations.
Goodwill
Goodwill represents the excess of the purchase price over the estimated
fair value of the net assets acquired in the purchase of Genesis, which was
accounted for using the purchase method of accounting. In 2001, goodwill was
amortized using the unit-of-production basis over the total proved reserves
acquired. Accumulated amortization was approximately $11.9 million at December
31, 2001.
-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 adopted SFAS No. 141 and SFAS No. 142 effective January 1,
2002, resulting in the elimination of goodwill amortization from statements of
operations in future periods. The Company recorded an impairment charge of $60.5
million related to the goodwill of its Canadian operations as a cumulative
effect of a change in accounting principle in its statement of operations (see
Note 3).
Hedging
The Company periodically uses hedges to reduce the impact of oil and gas
price fluctuations. Gains or losses on hedges are recognized as an adjustment to
sales revenue when the related transactions being hedged are finalized. Gains or
losses from derivative financial instruments that do not qualify for accounting
treatment as hedges are recognized currently as other income or expense. The
cash flows from such agreements are included in operating activities in the
consolidated statements of cash flows.
In June 1998, the FASB issued Statement of Financial Accounting Standards
No. 133, Accounting for Derivative Instruments and Hedging Activities, as
amended in June 1999 by Statement No. 137, Accounting for Derivative Instruments
and Hedging Activities - Deferral of the Effective Date of FASB Statement No.
133 and in June 2000 by Statement No. 138, Accounting for Certain Derivative
Instruments and Certain Hedging Activities - an amendment of FASB Statement No.
133 ("SFAS No. 133"). SFAS No. 133 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.
-10-
Upon adoption of SFAS No. 133 on January 1, 2001, the Company recorded a
transition receivable of approximately $18.5 million related to cash flow hedges
in place that are used to reduce the volatility in commodity prices for portions
of the Company's forecasted oil production. Additionally, the Company recorded,
net of tax, an increase to accumulated other comprehensive income in the
Stockholders' Equity section of the balance sheet of approximately $14.9
million. During the first half of 2001, $13.2 million of the original amount
recorded to accumulated other comprehensive income was taken to the statement of
operations as the physical transactions being hedged were finalized. At June 30,
2002, the Company had a net derivative financial instrument payable of $0.4
million related to 2002 cash flow hedges in place. During the first six 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 six months ended June 30, 2002 and 2001, the Company made cash
payments for interest totaling approximately $35.2 million, and $16.7 million,
respectively. Cash payments made for U.S. income taxes of $6.2 million and $12.9
million were made during the first six months of 2002 and 2001, respectively.
The Company made cash payments of $4.7 million and $56.7 million during the
first six months of 2002 and 2001, respectively, for foreign income taxes,
primarily in Argentina and 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 all periods presented were computed assuming the
exercise of all dilutive options, as determined by applying the treasury stock
method. In periods in which a loss from continuing operations occurs, no options
are assumed to be exercised in computing diluted earnings per common share.
For the three month period ended June 30, 2002 and 2001, the Company had
outstanding stock options for 3,125,000 and 1,003,000 additional shares of the
Company's common stock, respectively, with an average exercise price of $19.18
and $21.17, respectively, which were anti-dilutive. For the six month period
ended June 30, 2002 and 2001, the Company had outstanding stock options for
3,152,000 and 648,000 additional shares of the Company's common stock,
respectively, with an average exercise price of $19.12 and $21.80, respectively,
which were anti-dilutive.
General and Administrative Expense
The Company receives fees for the operation of jointly-owned oil and gas
properties and records such reimbursements as reductions of general and
administrative expense. Such fees totaled approximately $2.8 million and $3.4
million for the first six months of 2002 and 2001, respectively, and
approximately $1.4 million and $2.0 million for the second quarters of 2002 and
2001, respectively.
-11-
Lease Operating Expense
Included in lease operating expenses are the following items (in
thousands):
Three Months Ended Six Months Ended
June 30, June 30,
------------------ ------------------
2002 2001 2002 2001
------ ------ ------ ------
Gross production taxes ................ $2,858 $4,561 $5,133 $9,661
Argentina oil export taxes ............ 10,093 - 10,614 -
Transportation and storage expenses ... 2,922 3,415 6,145 6,415
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.
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 June 30, 2002, was 3.82 pesos to one U.S.
dollar.
-12-
On February 3, 2002, Decree 214 required all contracts that were previously
payable in U.S. dollars to be payable in pesos. Pursuant to an emergency law
passed on January 10, 2002, U.S. dollar obligations between private parties due
after January 6, 2002, were to be liquidated in pesos at a negotiated rate of
exchange which reflects a sharing of the impact of the devaluation. The
Company's settlements in pesos of the existing U.S. dollar-denominated
agreements were substantially completed by March 31, 2002, thus, future periods
should not be impacted by this mandate. This government-mandated "equitable
sharing" of the impact of the devaluation resulted in a reduction in oil
revenues from domestic sales in Argentina for the first six months of 2002 of
approximately $8 million, or $1.37 per Argentina Bbl produced or $0.73 per total
Company Bbl produced. The Company's Argentine lease operating costs were also
reduced as a result of this mandate and the positive impact of devaluation on
the Company's peso-denominated costs, which essentially offset the negative
impact on Argentine oil revenues.
Absent the emergency law that was enacted on January 10, 2002, the
devaluation of the peso would have had no effect on the Company's U.S.
dollar-denominated payables and receivables at December 31, 2001. A $0.9 million
gain resulting from the involuntary conversion was recorded in January 2002 and
is reflected in "Other income" in the accompanying statement of operations. The
translation of peso-denominated balances at June 30, 2002, and peso-denominated
transactions during the six months ended June 30, 2002, resulted in a foreign
currency exchange gain of $3.7 million.
Comprehensive Income (Loss)
Comprehensive income (loss) consists of the following (in thousands):
Three Months Ended Six Months Ended
June 30, June 30,
---------------------- ----------------------
2002 2001 2002 2001
-------- -------- ---------- ---------
Net income (loss) ......................... $ 22,429 $ 52,219 $ (43,738) $ 122,917
Foreign currency translation adjustment ... 31,932 8,572 31,432 6,182
Change in value of derivatives ............ 5,693 2,005 (3,246) (10,073)
-------- -------- ---------- ---------
Comprehensive income (loss) ............. $ 60,054 $ 62,796 $ (15,552) $ 119,026
======== ======== ========== =========
The Company had a foreign currency translation gain of approximately $31.4
million for the six months ended June 30, 2002, which is included in accumulated
other comprehensive income (loss) in the Stockholders' Equity section of the
accompanying balance sheet. The gain is the result of a strengthening of the
Canadian dollar against the U.S. dollar from December 31, 2001, to June 30,
2002. The US$:C$ exchange rate at June 30, 2002, was US$1:C$1.52 as compared to
US$1:C$1.59 at December 31, 2001.
-13-
During the six months ended June 30, 2002, the Company also recorded under
SFAS No. 133 a $3.2 million charge to other comprehensive income (loss) (net of
a $1.9 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 $0.2 million related
to open derivative contracts at June 30, 2002, that will settle later in 2002.
The actual cash flow losses from settled oil swaps recorded in oil and gas sales
in the Company's statement of operations were $1.8 million and $2.6 million for
the six months and three months ended June 30, 2002, respectively. The actual
cash flow losses from settled gas swaps of $2.1 million have been reflected in
oil and gas sales in the Company's statement of operations for the three months
ended June 30, 2002. There were no gas swaps in place for the first quarter of
2002.
Other Recent Pronouncements
On April 30, 2002, the FASB issued Statement of Financial Accounting
Standards No. 145, Rescission of FASB Statements No. 4, 44, and 64, Amendment of
FASB Statement No. 13, and Technical Corrections ("SFAS No. 145"). SFAS No. 145
updates, clarifies and simplifies existing accounting pronouncements. Among
other items, it rescinds previous accounting rules which required all gains and
losses from extinguishment of debt to be aggregated and, if material, classified
as an extraordinary item, net of related income tax effect. The Company has
adopted the provisions of SFAS No. 145 and, accordingly, has classified an $8.2
million ($4.3 million net of tax) loss on the early extinguishment of debt (see
Note 4) as a charge to income from continuing operations in its statements of
operations for the three months and six months ended June 30, 2002. The adoption
of SFAS No. 145 did not have any other material impact on the Company's
financial position or results of operations.
On July 30, 2002, the FASB issued Statement of Financial Accounting
Standards No. 146, Accounting for Costs Associated with Exit or Disposal
Activities. The standard requires companies to recognize costs associated with
exit or disposal activities when they are incurred rather than at the date of a
commitment to an exit or disposal plan. The provisions of this statement are to
be applied prospectively to exit or disposal activities initiated after December
31, 2002. The Company does not expect the adoption of this standard to have a
material impact on the Company's financial position or results of operations.
3. GOODWILL
Goodwill represents the excess of the purchase price over the estimated
fair value of the net assets acquired in the purchase of Genesis. All of the
Company's goodwill is related to the Company's Canadian reporting unit, which is
consistent with the Canadian segment identified in Note 7. Effective January 1,
2002, the Company adopted the provisions of SFAS No. 142. SFAS No. 142 changes
the accounting for goodwill from an amortization method to an impairment
assessment only method.
-14-
Under the new rule, the Company had a six-month transitional period from
the effective date of the adoption to perform an initial assessment of whether
there was an indication that the carrying value of goodwill was impaired. This
assessment was made by comparing the fair value of the Canadian reporting unit,
as determined in accordance with SFAS No. 142, to its book value. If the fair
value was less than the book value, an impairment was indicated and the Company
would be required to perform a second test no later than December 31, 2002, to
measure the amount of the impairment. Any initial impairment is to be taken as a
cumulative effect of change in accounting principle retroactive to January 1,
2002. In future years, this assessment must be conducted at least annually and
any such impairment must be recorded as a charge to operating earnings.
The Company has completed its initial assessment and has recorded a
non-cash charge of $60.5 million. Decreases in oil and gas price expectations
from the May 2, 2001, acquisition of Genesis to January 1, 2002, and certain
downward revisions recorded to the Company's Canadian oil and gas reserves at
December 31, 2001, were the primary factors that led to the goodwill impairment.
The charge was recorded as a cumulative effect of change in accounting principle
retroactive to January 1, 2002, in accordance with the provisions of SFAS No.
142.
The Company engaged an independent appraisal firm to determine the fair
value of its Canadian reporting unit as of January 1, 2002. This fair value
determination was made principally on the basis of present value of future after
tax cash flows, although other valuation methods were considered. The book value
of the Canadian reporting unit exceeded the fair value determined by the
independent appraisal firm, indicating a possible impairment of goodwill. The
Company then calculated the implied fair value of the goodwill by deducting the
fair value of all tangible and intangible net assets of the Canadian reporting
unit from the fair value of the Canadian reporting unit determined in step one
of the assessment. The carrying value of the goodwill exceeded this calculated
implied fair value of the goodwill at January 1, 2002, resulting in the
impairment charge.
The Company has no intangible assets other than the goodwill of its
Canadian reporting unit, which has a net book value (after the cumulative effect
of change in accounting principle) of $104.5 million as of June 30, 2002. The
changes in the carrying amount of goodwill for the six months ended June 30,
2002 are as follows (in thousands):
Balance, December 31, 2001 ..................... $156,990
Impairment ..................................... (60,547)
Changes in foreign currency exchange rates ..... 8,012
---------
Balance, June 30, 2002 ......................... $104,455
=========
-15-
The unaudited results of operations presented below for the three months
and six months ended June 30, 2001 reflect the operations of the Company had the
Company adopted the non-amortization provisions of SFAS No. 142 effective
January 1, 2001 (in thousands, except per share amounts):
Three Months Six Months
Ended Ended
June 30, 2001 June 30, 2001
------------- -------------
Reported net income .................... $ 52,219 $ 122,917
Goodwill amortization .................. 2,774 2,774
------------- -------------
Adjusted net income .................... $ 54,993 $ 125,691
============= =============
Adjusted basic income per share ........ $ 0.87 $ 2.00
============= =============
Adjusted diluted income per share ...... $ 0.86 $ 1.96
============= =============
As noted above, SFAS No. 142 requires the cumulative effect of change in
accounting principle be recorded retroactive to January 1, 2002. The following
table reflects the impact of this accounting change on selected financial data
for the three months ended March 31, 2002 (in thousands, except per share data):
As Reported As Adjusted
----------- -----------
Loss before cumulative effect of change in accounting principle ....... $ (5,620) $ (5,620)
Cumulative effect of change in accounting principle ................... - (60,547)
----------- -----------
Net Loss .............................................................. $ (5,620) $ (66,167)
=========== ===========
Basic Loss Per Share:
Loss before cumulative effect of change in accounting principle ..... $ (0.09) $ (0.09)
Cumulative effect of change in accounting principle ................. - (0.96)
----------- -----------
Net Loss ............................................................ $ (0.09) $ (1.05)
=========== ===========
Diluted Loss Per Share:
Loss before cumulative effect of change in accounting principle ..... $ (0.09) $ (0.09)
Cumulative effect of change in accounting principle ................. - (0.96)
----------- -----------
Net Loss ............................................................ $ (0.09) $ (1.05)
=========== ===========
-16-
4. LONG-TERM DEBT
Long-term debt at June 30, 2002, and December 31, 2001, consisted of the
following:
June 30, December 31,
(In thousands) 2002 2001
----------- ------------
Revolving credit facility ................................ $ 167,000 $ 411,400
8 1/4% Senior Notes due 2012 ............................. 350,000 -
Senior Subordinated Notes:
9% Notes due 2005, less unamortized discount ........... 49,953 149,837
8 5/8% Notes due 2009, less unamortized discount ....... 99,538 99,503
9 3/4% Notes due 2009 .................................. 150,000 150,000
7 7/8% Notes due 2011, less unamortized discount ....... 199,937 199,933
----------- ------------
$ 1,016,428 $ 1,010,673
=========== ============
The Company had $11.1 million and $9.5 million of accrued interest payable
related to its long-term debt at June 30, 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 9% Senior Subordinated Notes due 2005 (the "9% Notes"). 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, on or before 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 (currently $300 million) 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. At June 30, 2002, the
unused availability under the Bank Facility was approximately $115 million.
-17-
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. Total outstanding advances at June 30, 2002,
were $167 million at an average interest rate of 4.10 percent.
The Company's borrowing base will be redetermined on a semiannual basis by
the banks based upon their review of the Company's oil and gas reserves. If the
sum of outstanding senior secured debt exceeds the borrowing base, as
redetermined, the Company must repay such excess. Any principal advances
outstanding are due at maturity on May 2, 2005. The Bank Facility is secured by
a first priority lien on the Company's U.S. oil and gas properties constituting
at least 80 percent of the present value of the Company's U.S. proved reserves
owned now or in the future. The Bank Facility will be guaranteed by any of the
Company's existing and future U.S. subsidiaries that grant a lien on oil and gas
properties under the Bank Facility.
The terms of the Bank Facility impose certain restrictions on the Company
regarding the pledging of assets and limitations on additional indebtedness. In
addition, the Bank Facility requires the maintenance of a minimum current ratio
(as defined therein) and tangible net worth (as defined therein) of not less
than $425 million plus 75 percent of the net proceeds of any future equity
offerings less any impairment write downs required by GAAP or by the Securities
and Exchange Commission and excluding any impact related to SFAS No. 133.
In conjunction with the elimination of the Company's previously existing
revolving credit facility and the partial redemption of the 9% Notes, the
Company was required to expense certain associated deferred financing costs and
discounts. This $5.2 million non-cash charge, along with a $3.0 million cash
charge for the call premium on the 9% Notes, resulted in a one-time charge of
approximately $8.2 million ($4.3 million net of tax) in the second quarter of
2002.
5. CAPITAL STOCK
On March 16, 1999, the Company's Board of Directors adopted a stockholder
rights plan and declared a dividend distribution of one preferred share purchase
right (a "Right") for each outstanding share of the Company's common stock, to
stockholders of record on April 5, 1999 (the "Record Date"). Each common share
issued after the Record Date has also been issued a Right. The description and
terms of the Rights are set forth in a Rights Agreement, dated as of March 16,
1999, between the Company and the rights agent.
On April 3, 2002, the Company and the rights agent executed the First
Amendment to Rights Agreement (the "Amendment"). As more fully set forth in the
Amendment, the Amendment, among other things, amends the Rights Agreement to
lower the threshold at which a person becomes an Acquiring Person (as defined in
the Rights Agreement, as amended by the Amendment) and lowers the percentage at
which the rights plan is triggered from 15 percent to 10 percent.
-18-
Stock Plans
On June 14, 2002, the Company granted 260,650 shares of restricted stock to
employees under the 1990 Stock Plan, as amended. All of the shares vest over a
three-year period. The related compensation expense of $2.9 million (based on
the stock price on the date of grant) is being amortized over the vesting
periods. Compensation expense related to restricted stock grants totaled
$400,000 and $100,000 for the six months ended June 30, 2002 and 2001,
respectively.
Dividends
The Company declared cash dividends of $0.075 and $0.065 per share for the
six months ended June 30, 2002 and 2001, respectively and $0.04 and $0.035 per
share for the three months ended June 30, 2002 and 2001, respectively.
6. INCOME TAXES
A reconciliation of the U.S. federal statutory income tax rate to the
effective rate is as follows:
Six Months Ended Six Months Ended
June 30, 2002 June 30, 2001
---------------- ----------------
U.S. federal statutory income tax rate ...... 35.0% 35.0%
U.S. state income tax (net of federal
tax benefit)............................ 3.9 3.9
Foreign operations .......................... (53.5) (2.5)
Other ....................................... (3.3) -
---------------- ----------------
(17.9)% 36.4%
================ ================
7. SEGMENT INFORMATION
The Company's reportable business segments have been identified based on
the differences in products or services provided. Revenues for the exploration
and production segment are derived from the production and sale of natural gas
and crude oil. Revenues for the gathering/plant segment arise from the
transportation, processing and sale of natural gas, crude oil and plant
products. The gas marketing segment generates revenue by earning fees through
the marketing of Company-produced gas volumes and the purchase and resale of
third party-produced gas volumes. The Company evaluates the performance of its
operating segments based on segment operating income.
-19-
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 six month and three month periods ended June 30, 2002 and 2001, is shown
in the following tables (in thousands):
Exploration and Production
--------------------------------------------------------------------------------
Other
U.S. Canada Argentina Bolivia Ecuador Foreign
----------- --------- --------- --------- ------- -------
Six Months Ended June 30, 2002
------------------------------
Revenues from external customers ............ $ 122,282 $ 55,291 $ 105,132 $ 6,176 $ 9,955 $ -
Intersegment revenues ....................... - - - - - -
Depreciation, depletion and
amortization expense ................... 28,662 38,000 24,657 1,944 1,124 -
Segment operating income (loss) ............. 43,794 (16,255) 49,411 2,116 4,576 (161)
Total assets ................................ 454,826 782,381 508,931 116,361 60,524 29,075
Capital investments ......................... 14,229 34,282 12,466 1,112 1,857 743
Long-lived assets ........................... 417,859 760,065 464,057 92,685 50,480 28,930
Gathering/ Gas
Plant Marketing Corporate Total
------------- ----------- --------- ---------
Six Months Ended June 30, 2002
------------------------------
Revenues from external customers ............ $ 2,853 $ 29,733 $ 5,167 $ 336,589
Intersegment revenues ....................... - 454 - 454
Depreciation, depletion and
amortization expense ................... 589 - 1,493 96,469
Segment operating income (loss) ............. (1,018) 988 3,674 87,125
Total assets ................................ 8,907 9,428 66,913 2,037,346
Capital investments ......................... - - 872 65,561
Long-lived assets ........................... 6,375 - 7,358 1,827,809
Exploration and Production
--------------------------------------------------------------------------------
Other
U.S. Canada Argentina Bolivia Ecuador Foreign
---------- -------- --------- -------- ------- -------
Six Months Ended June 30, 2001
------------------------------
Revenues from external customers ............ $ 233,466 $ 32,175 $ 131,074 $ 8,341 $ 10,781 $ -
Intersegment revenues ....................... - - - - - -
Depreciation, depletion and
amortization expense ................... 28,617 13,690 20,235 2,137 975 -
Segment operating income (loss) ............. 142,505 8,548 81,789 4,329 6,044 527
Total assets ................................ 529,698 701,994 452,432 121,505 54,765 25,458
Capital investments ......................... 32,033 631,601 30,079 753 6,275 1,152
Long-lived assets ........................... 475,496 854,510 411,289 96,119 46,639 24,538
Gathering/ Gas
Plant Marketing Corporate Total
----------- --------- --------- ---------
Six Months Ended June 30, 2001
------------------------------
Revenues from external customers ............ $ 14,306 $ 94,814 $ 2,447 $ 527,404
Intersegment revenues ....................... - 1,378 - 1,378
Depreciation, depletion and
amortization expense ................... 1,054 - 4,054 70,762
Segment operating income (loss) ............. (1,225) 3,191 (1,607) 244,101
Total assets ................................ 20,209 22,074 245,883 2,174,018
Capital investments ......................... 9,602 - 3,328 714,823
Long-lived assets ........................... 14,412 - 6,987 1,929,990
-20-
Exploration and Production
----------------------------------------------------------------------
Other
U.S. Canada Argentina Bolivia Ecuador Foreign
---------- --------- ---------- --------- ------- -------
Three Months Ended June 30, 2002
--------------------------------
Revenues from external customers ............. $ 77,150 $ 30,440 $ 60,319 $ 2,564 $ 5,888 $ -
Intersegment revenues ........................ - - - - - -
Depreciation, depletion and
amortization expense .................... 13,101 19,116 11,999 770 606 -
Segment operating income (loss) .............. 40,443 (5,175) 28,562 831 3,092 (81)
Capital investments .......................... 6,993 14,931 4,505 1,013 1,221 455
Gathering/ Gas
Plant Marketing Corporate Total
---------- ----------- ---------- ---------
Three Months Ended June 30, 2002
--------------------------------
Revenues from external customers ............. $ 1,468 $ 17,404 $ 1,537 $ 196,770
Intersegment revenues ........................ - 283 - 283
Depreciation, depletion and
amortization expense .................... 314 - 790 46,696
Segment operating income (loss) .............. (350) 463 747 68,532
Capital investments .......................... 678 - 374 30,170
Exploration and Production
------------------------------------------------------------------------
Other
U.S. Canada Argentina Bolivia Ecuador Foreign
--------- --------- ---------- ---------- ------- -------
Three Months Ended June 30, 2001
--------------------------------
Revenues from external customers ............. $ 109,626 $ 26,554 $ 63,594 $ 3,956 $ 4,717 $ -
Intersegment revenues ........................ - - - - - -
Depreciation, depletion and
amortization expense .................... 14,706 12,033 10,676 1,130 414 -
Segment operating income (loss) .............. 64,088 6,502 37,732 1,834 2,639 310
Capital investments .......................... 20,157 629,943 16,105 217 4,138 924
Gathering/ Gas
Plant Marketing Corporate Total
------------ ------------ --------- ----------
Three Months Ended June 30, 2001
--------------------------------
Revenues from external customers ............. $ 6,197 $ 35,491 $ 1,779 $ 251,914
Intersegment revenues ........................ - 595 - 595
Depreciation, depletion and
amortization expense .................... 748 - 3,464 43,171
Segment operating income (loss) .............. (672) 1,194 (1,685) 111,942
Capital investments .......................... 9,210 - 1,976 682,670
Intersegment sales are priced in accordance with terms of existing
contracts and current market conditions. Capital investments include expensed
exploratory costs. Corporate general and administrative costs and interest costs
(including the loss on early extinguishment of debt) are not allocated to
segments.
-21-
8. COMMITMENTS AND CONTINGENCIES
The Company is 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 total
cost of $6.0 million. 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.
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 June 30, 2002, the
Company had fulfilled the seismic requirements and had drilled two of the three
exploratory wells. As discussed in Note 9, the Company has sold its operations
in Trinidad subsequent to June 30, 2002 and has no remaining commitment in
Trinidad.
The Company had approximately $18.1 million in letters of credit
outstanding at June 30, 2002. These letters of credit relate primarily to
various obligations for acquisition and exploration activities in South America
and Yemen and bonding requirements of various state regulatory agencies in the
U.S. for oil and gas operations. The Company's availability under its revolving
credit facility is reduced by the outstanding letters of credit.
The Company is a defendant in various lawsuits and is a party to
governmental proceedings from time to time arising in the ordinary course of
business. In the opinion of management, none of the various pending lawsuits and
proceedings should have a material adverse impact on the Company's financial
position or results of operations.
9. SALES OF ASSETS
In June 2002, the Company sold its heavy oil properties in the Santa Maria
area of southern California for approximately $9.5 million in cash and a note
receivable for $6 million. The note is payable in monthly installments of
$360,000, plus interest at a rate of 7.5% per annum, with final maturity in June
2003. The Company recorded a gain of approximately $18.3 million ($9.6 million
after tax) on this transaction, subject to post-closing adjustments. Included in
this the gain is a reversal of the Company's accrual for future abandonment
costs related to these properties.
On July 30, 2002, the Company completed the sale of its operations in
Trinidad. The Company received $40 million in cash and will record a gain of
approximately $30.7 million ($13.8 million after deferred taxes), subject to
post-closing adjustments.
-22-
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 June 30, Six Months Ended June 30,
--------------------------- --------------------------
2002 2001 2002 2001
------------- ------------ ------------- ------------
Production:
Oil (MBbls) -
U.S. ......................... 1,829 2,145 3,575 4,330
Canada ....................... 452 376 980 435
Argentina .................... 2,842(a) 2,574(b) 5,835(a) 5,050(b)
Ecuador ...................... 282 245(b) 546 582(b)
Bolivia ...................... 32(a) 25(b) 71(a) 48(b)
Total ..................... 5,437(a) 5,365(b) 11,007(a) 10,445(b)
Gas (MMcf) -
U.S. ......................... 6,527 9,043 12,480 17,604
Canada ....................... 8,250 4,973 15,406 5,803
Argentina .................... 2,466 2,966 3,967 5,008
Bolivia ...................... 1,319 1,971 3,345 3,838
Total .................... 18,562 18,953 35,198 32,253
Total MBOE ........................ 8,531 8,524 16,873 15,821
Average prices:
Oil (per Bbl) -
U.S. ......................... $ 21.80(c) $ 24.75(d) $ 20.05(c) $ 25.22(d)
Canada ....................... 22.60 24.30 19.96 24.59
Argentina .................... 20.92(c) 23.12(d) 17.76(c)(f) 24.56(d)
Ecuador ...................... 20.88 19.30 18.24 18.53
Bolivia ...................... 21.87 20.32 19.81 25.16
Total .................... 21.36(c) 23.67(d) 18.74(c)(f) 24.50(d)
Gas (per Mcf) -
U.S. ......................... $ 3.01(e) $ 6.25 $ 2.64(e) $ 7.03
Canada ....................... 2.43(e) 3.51 2.32(e) 3.71
Argentina .................... 0.35 1.38 0.38 1.41
Bolivia ...................... 1.42 1.74 1.42 1.85
Total .................... 2.29(e) 4.30 2.13(e) 4.94
____________
(a) Total production for the three months and six months ended June 30,
2002, before the impact of changes in inventories was 5,357 MBbls
(Argentina - 2,772 MBbls, Bolivia - 22 MBbls) and 10,769 MBbls
(Argentina - 5,618 MBbls, Bolivia - 50 MBbls), respectively.
(b) Total production for the three months and six months ended June 30,
2001, before the impact of changes in inventories was 5,452 MBbls
(Argentina - 2,551 MBbls, Ecuador - 349 MBbls, Bolivia - 31 MBbls) and
10,615 MBbls (Argentina - 5,095 MBbls, Ecuador - 699 MBbls, Bolivia -
56 MBbls), respectively.
(c) Reflects the impact of oil hedges which decreased the three months and
six months ended June 30, 2002, U.S., Argentina and total average oil
prices per Bbl by $1.05, $0.23 and $0.47, and $0.26, $0.15 and $0.16,
respectively.
(d) Reflects the impact of oil hedges which increased the three months and
six months ended June 30, 2001, U.S., Argentina and total average oil
prices per Bbl by $0.57, $0.57, and $0.50, and $0.60, $1.22 and $0.84,
respectively.
Continued on next page.
-23-
(e) Reflects the impact of gas hedges which decreased the three and six
months ended June 30, 2002, U.S., Canada and total average gas prices
per Mcf by $0.18, $0.12 and $0.11, and $0.09, $0.06 and $0.06,
respectively.
(f) Reflects the impact of the one-time government-mandated forced
settlement of domestic Argentina oil sales which decreased the
Argentina and total average oil prices per Bbl by $1.37 and $0.73,
respectively.
Significant acquisitions and dispositions of producing oil and gas
properties during 2001 affect the comparability of operating data for the
periods presented in the table on the previous page.
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 24 percent decrease in
its average oil price, including the impact of hedging activities (20 percent
decrease excluding hedging activities), during the first six months of 2002 as
compared to the same period of 2001. The Company's realized average oil price
for the first six months of 2002 (before hedges) was approximately 79 percent of
the NYMEX reference price (82 percent excluding the negative impact of the
Argentine government mandated settlements) compared to 83 percent for the same
period of 2001.
The Argentine government took actions which in effect caused the
devaluation of the peso in early December 2001 and, in January 2002, enacted an
emergency law that required certain contracts that were previously payable in
U.S. dollars to be payable in pesos. Subsequently, on February 13, 2002, the
Argentine government announced a 20 percent tax on oil exports, effective March
1, 2002. 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, with a requirement to repatriate 30 percent
of such proceeds into Argentina.
The Company currently exports approximately 70 percent of its Argentina oil
production. The Company believes that this export tax will have the effect of
decreasing all future Argentina oil revenues (not only export revenues) by the
tax rate for the duration of the tax. The Company 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 2.21 MMBbls and 3.22 MMBbls
during the first six months of 2002 and 2001, respectively. The impact of the
2002 hedges reduced the Company's U.S. average oil price for the first six
months of 2002 by 26 cents to $20.05 per Bbl, its Argentina average oil price by
15 cents to $17.76 per Bbl and its overall average oil price by 16 cents to
$18.74 per Bbl. The impact of the 2001 hedges increased the Company's U.S.
average oil price for the first six months of 2001 by 60 cents to $25.22 per
Bbl, its Argentina average oil price by $1.22 to $24.56 per Bbl and its overall
average oil price by 84 cents to $24.50 per Bbl.
-24-
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 six months of 2002, including the impact of hedging
activities, was 57 percent lower (56 percent lower excluding hedging activities)
than the same period of 2001.
The Company participated in gas hedges covering 3.84 million MMBtu during
the first six months of 2002. The Company did not participate in any gas hedges
in the first six months of 2001. The impact of the 2002 hedges reduced the
Company's U.S. average gas price for the first six months of 2002 by nine cents
to $2.64 per Mcf, its Canada average gas price by six cents to $2.32 per Mcf and
its overall average gas price by six cents to $2.13 per Mcf.
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 2.64 million Bbls of
its U.S. and Canadian oil production at a weighted average NYMEX reference price
of $26.28 per Bbl for the last half of 2002. The Company has also entered into
oil price swap agreements covering approximately 2.74 million Bbls of its U.S.
oil production at a weighted average NYMEX reference price of $24.58 per Bbl for
calendar year 2003.
Additionally, the Company has entered into various gas price swap
agreements covering approximately 7.7 million MMBtu of its U.S. and Canadian gas
production from July 1, 2002, and expiring at various times through October 31,
2002. The Canadian portion of the gas price swap agreements (approximately 4.3
million MMBtu) is at an average AECO gas price index reference price of 3.71
Canadian dollars per MMBtu and will be settled in Canadian dollars. The U.S.
portion of the gas swap agreements (approximately 3.4 million MMBtu) is at an
average NYMEX reference price of $2.79 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 July 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.
-25-
The counterparty to the Company's hedging agreements is a commercial bank.
The Company continues to monitor oil and gas prices and may enter into
additional oil and gas hedges or swaps in the future.
Relatively modest changes in either oil or gas prices significantly impact
the Company's results of operations and cash flow. Based on the first six months
of 2002 oil production, a change in the average oil price realized, before
hedges, by the Company of $1.00 per Bbl would result in a change in net income
and cash flow before income taxes on an annual basis of approximately $8.1
million and $12.0 million, respectively. A 10 cent per Mcf change in the average
price realized, before hedges, by the Company for gas would result in a change
in net income and cash flow before income taxes on an annual basis of
approximately $2.3 million and $3.5 million, respectively, based on gas
production for the first six months of 2002. However, the impact of changes in
the market prices for oil and gas on the Company's average realized prices may
be reduced from time to time based on the level of the Company's hedging
activities.
Period to Period Comparison
In May 2001, the Company purchased 100 percent of the outstanding common
stock of Genesis Exploration Ltd. ("Genesis"). This acquisition significantly
impacts the period to period comparison for the second quarter and the first six
months of 2002 compared to the second quarter and first six months of 2001. The
Company's consolidated revenues and expenses for the second quarter and first
six months of 2001 include, under the purchase method of accounting, two months
of activities for Genesis.
Three months ended June 30, 2002, compared to three months ended June 30, 2001
The Company reported net income of $22.4 million for the quarter ended June
30, 2002, compared to net income of $52.2 million for the same period in 2001.
The second quarter of 2002 included a $17.6 million ($9.2 million net of tax)
gain on the sale of oil and gas properties and an $8.2 million ($4.3 million net
of tax) loss on the early extinguishment of debt. A 47 percent decrease in
average gas prices and a 10 percent decrease in average oil prices were the
other primary factors resulting in the 57 percent decrease in net income.
Oil and gas sales decreased $49.9 million (24 percent), to $158.6 million
for the second quarter of 2002 from $208.5 million for the same period of 2001.
A 47 percent decrease in average gas prices coupled with a two percent decrease
in gas production, accounted for a decrease of $39.1 million. A 10 percent
decrease in oil prices partially offset by a one percent increase in average oil
production, accounted for an additional decrease of $10.8 million. Increases in
oil and gas production resulting from the acquisitions of Genesis and the La
Ventana concession in Argentina and the Company's exploitation and exploration
activities were offset by natural production declines and the reduced production
volumes resulting from U.S. property sales in the fourth quarter of 2001.
-26-
A net gain on disposition of assets of $17.6 million ($9.2 million net of
tax) was reflected in the second quarter of 2002 primarily as a result of the
sale of the Company's heavy oil properties in the Santa Maria area of southern
California in June 2002. The Company recorded a gain of approximately $18.3
million ($9.6 million net of tax) on this transaction, subject to post-closing
adjustments. Included in the gain is a reversal of the Company's accrual for
future abandonment costs related to these properties. Other than the gain
recorded, this disposition did not significantly affect the Company's results of
operations for the second quarter of 2002 as the sale occurred at the end of the
quarter.
As discussed elsewhere in this Form 10-Q, the Argentine peso was devalued
in early December 2001. During the second quarter of 2002, the peso continued to
decline in value, falling from a rate of 2.90 pesos to one U.S. dollar at March
31, 2002, to 3.82 pesos to one U.S. dollar at June 30, 2002. The translation of
peso-denominated balances at June 30, 2002, and peso-denominated transactions
for the three months ended June 30, 2002, resulted in a foreign currency
exchange gain of $0.8 million.
Lease operating expenses, including production and export taxes, increased
$3.2 million (six percent), to $56.1 million for the second quarter of 2002 from
$52.9 million for the same period of 2001. The new export taxes in Argentina
increased lease operating expenses for the second quarter of 2002 by $10.1
million. This increase was partially offset by lower direct lease operating
expenses in Argentina resulting from the devaluation of the peso and by lower
expenses in the U.S. as a result of the property sales in the fourth quarter of
2001. Lease operating expenses per equivalent barrel produced, before the effect
of the export tax, decreased 13 percent to $5.40 for the second quarter of 2002
from $6.21 for the same period in 2001.
Exploration costs increased $3.5 million (100 percent), to $7.0 million for
the second quarter of 2002 from $3.5 million for the same period of 2001. During
the second quarter of 2002, the Company's exploration costs included $1.4
million for seismic and other geological and geophysical costs and $5.6 million
for unsuccessful exploratory drilling and leasehold impairments. Exploration
expenses for the second quarter of 2001 consisted of $2.0 million for seismic
and other geological and geophysical costs and $1.5 million for unsuccessful
exploratory drilling.
General and administrative expenses increased $1.4 million (12 percent), to
$13.5 million for the second quarter of 2002, from $12.1 million for the same
period in 2001. This increase primarily relates to the addition of Genesis.
Since the acquisition of Genesis occurred on May 2, 2001, only two months of
Genesis expenses are included for the second quarter of 2001. General and
administrative expenses per equivalent barrel produced increased 11 percent to
$1.58 for the second quarter of 2002 from $1.42 for the same period in 2001.
Depreciation, depletion and amortization increased $6.3 million (16
percent), to $46.7 million for the second quarter of 2002 from $40.4 million for
the same period of 2001, primarily due to the increase in the Company's average
oil and gas DD&A rate per equivalent barrel produced from $4.56 in the second
quarter of 2001 to $5.34 in the second quarter of 2002. This increase in the
average amortization rate per equivalent barrel produced primarily resulted from
the acquisition of Genesis and the impact of substantially lower commodity
prices on proved reserve volumes used to determine the amortization rate.
-27-
Interest expense increased $4.8 million (30 percent), to $20.7 million for
the second quarter of 2002 from $15.9 million for the same period of 2001. The
increase in interest expense is due to a 38 percent increase in the Company's
total average outstanding debt, partially offset by a decrease in the Company's
average interest rate to 7.48 percent for the second quarter of 2002 from 7.86
percent in the same period of 2001.
In conjunction with the issuance of the Company's 8 1/4% senior notes, the
Company entered into a new revolving credit facility and redeemed a portion of
the Company's 9% senior subordinated notes. The Company was required to expense
certain associated deferred financing costs and discounts. This $5.2 million
non-cash charge, along with a $3.0 million cash charge for the call premium on
the 9% senior subordinated notes, resulted in a one-time charge of approximately
$8.2 million ($4.3 million net of tax) in the second quarter of 2002.
Six months ended June 30, 2002, compared to six months ended June 30, 2001
The Company reported a net loss of $43.7 million for the six months ended
June 30, 2002, compared to net income of $122.9 million for the year-earlier
period. The first half of 2002 included a charge of $60.5 million for impairment
of goodwill resulting from the cumulative effect of adopting Statement of
Financial Accounting Standards No. 142, Goodwill and Other Intangible Assets
("SFAS No. 142"). Income before the cumulative effect of adopting SFAS No. 142
decreased $106.1 million to $16.8 million. This decrease was caused by a 57
percent decrease in average gas prices and a 24 percent decrease in average oil
prices received, partially offset by a seven percent increase in production on a
BOE basis.
Oil and gas sales decreased $134.3 million (32 percent), to $281.1 million
for the first six months of 2002 from $415.4 million for the six months of 2001.
A nine percent increase in gas production was also more than offset by a 57
percent decrease in average gas prices received by the Company and accounted for
the $84.6 million decrease in gas sales for the first six months of 2002
compared to the year-earlier period. A five percent increase in oil production
was more than offset by a 24 percent decrease in average oil prices received by
the Company and accounted for a $49.7 million decrease in oil sales for the
first six months of 2002 as compared to the year-earlier period. In addition to
the decline in market prices for oil, the Company's related oil price for the
six months ended June 30, 2002, was reduced by approximately $0.73 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. The five percent increase in oil production and
nine percent increase in gas production are primarily the result of the
acquisitions of Genesis and the La Ventana 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.
-28-
A net gain on disposition of assets of $17.7 million ($9.3 million net of
tax) was reflected in the first six months of 2002 primarily as a result of the
sale of the Company's heavy oil properties in the Santa Maria area of southern
California in June 2002. The Company recorded a gain of approximately $18.3
million ($9.6 million net of tax) on this transaction, subject to post-closing
adjustments. Included in this the gain is a reversal of the Company's accrual
for future abandonment costs related to these properties. Other than the gain
recorded, this disposition did not significantly affect the Company's results of
operations for the first half of 2002 as the sale occurred at the end of the
period.
As discussed elsewhere in this Form 10-Q, the Argentine peso was devalued
in early December 2001. During the first six months of 2002, the peso continued
to decline in value, falling from a rate of 1.65 pesos to one U.S. dollar at
January 11, 2002, to 3.82 pesos to one U.S. dollar at June 30, 2002. The
translation of peso-denominated balances at June 30, 2002, and peso-denominated
transactions during the six months ended June 30, 2002, resulted in a foreign
currency exchange gain of $3.7 million. The Company also recorded a gain of $0.9
million in "Other income" for the first six months of 2002 related to the
Argentine government-mandated negotiated settlements of U.S. dollar-denominated
receivables and payables in existence at January 6, 2002. There were no similar
gains related to Argentina in the six months ended June 30, 2001.
Lease operating expenses, including production and export taxes, increased
$4.3 million (four percent), to $105.0 million for the first six months of 2002
from $100.7 million for the first six months of 2001. The new export taxes in
Argentina increased lease operating expenses for the first half of 2002 by $10.6
million. Lease operating expenses also increased due to the acquisition of
Genesis in May 2001 and the acquisition of the La Ventana concession in
Argentina in September 2001. These increases were partially offset by lower
direct lease operating expenses in Argentina resulting from the devaluation of
the peso and by lower expenses in the U.S. as a result of the property sales in
the fourth quarter of 2001. Lease operating expenses per equivalent barrel
produced decreased two percent to $6.23 for the six months ended June 30, 2002,
from $6.37 for the same period in 2001. The decrease in lease operating expenses
per equivalent barrel produced primarily 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, partially offset by the new export tax.
General and administrative expenses increased $2.4 million (10 percent), to
$26.5 million for the six months ended June 30, 2002, from $24.1 million for the
first six months in 2001. This increase primarily relates to the addition of
Genesis. Since the acquisition of Genesis occurred on May 2, 2001, only two
months of Genesis expenses are included for the first half of 2001. General and
administrative expenses per equivalent barrel produced increased three percent
to $1.57 for the six months ended June 30, 2002, from $1.52 for the same period
in 2001.
Exploration costs increased $10.2 million (179 percent), to $15.9 million
for the first six months of 2002 from $5.7 million for same period of 2001.
During the first six months of 2002, the Company's exploration costs included
$11.0 million for unsuccessful exploratory drilling and lease impairments and
$4.9 million for other geological and geophysical costs. Exploration costs for
the first six months of 2001 included $2.9 million for unsuccessful exploratory
drilling and lease impairments and $2.8 million for other geological and
geophysical costs.
-29-
Depreciation, depletion and amortization increased $28.5 million (42
percent), to $96.5 million for the first six months of 2002 from $68.0 million
for the first six months of 2001, due primarily to the seven percent increase in
production on a BOE basis and the 35 percent increase in the average
amortization rate per equivalent barrel produced from $4.14 in the first six
months of 2001 to $5.59 for the same period of 2002. This increase in the
average amortization rate per equivalent barrel produced primarily resulted from
the acquisition of Genesis and the impact of substantially lower commodity
prices on proved reserve volumes used to determine the amortization rate.
Interest expense increased $11.4 million (43 percent), to $38.2 million for
the first six months of 2002 from $26.8 million for the first six months of
2001, due primarily to higher outstanding borrowings (73 percent) resulting from
the acquisition of Genesis in May 2001 and other acquisitions made subsequent to
the second quarter of 2001. This increase was partially offset by a decrease in
the Company's average interest rate to 6.99 percent for the first six months of
2002 from 8.30 percent in the same period of 2001.
In conjunction with the issuance of the Company's 8 1/4% senior notes, the
Company entered into a new revolving credit facility and redeemed a portion of
the Company's 9% senior subordinated notes. The Company was required to expense
certain associated deferred financing costs and discounts. This $5.2 million
non-cash charge, along with a $3.0 million cash charge for the call premium on
the 9% senior subordinated notes, resulted in a one-time charge of approximately
$8.2 million ($4.3 million net of tax) in the second quarter of 2002.
Effective January 1, 2002, the Company adopted the provisions of Statement
of Financial Accounting Standards No. 142, Goodwill and Other Intangible Assets
("SFAS No. 142"). SFAS No. 142 changes the accounting for goodwill from an
amortization method to an impairment-only method. Under SFAS No. 142, all
goodwill amortization ceased effective January 1, 2002. Goodwill was tested for
impairment in conjunction with a transitional goodwill impairment test in 2002
and will be tested at least annually thereafter. As a result of the transitional
impairment test, the Company recorded a $60.5 million charge to cumulative
effect of change in accounting retroactive to January 1, 2002, in accordance
with the provisions of SFAS No. 142.
Capital Expenditures
During the first six months of 2002, the Company's total oil and gas
capital expenditures were $64.7 million. In North America, the Company's
non-acquisition oil and gas capital expenditures totaled $47.9 million.
Exploration activities accounted for $29.0 million of the North America capital
expenditures with exploitation activities contributing $18.9 million. During the
first six months of 2002, the Company's international non-acquisition oil and
gas capital expenditures totaled $16.2 million, consisting of $12.5 million in
Argentina on exploitation activities, $1.9 million in Ecuador principally on
exploitation, $1.1 million in Bolivia on exploitation, and $0.7 million on
exploration projects primarily in Yemen.
As of June 30, 2002, the Company had unproved oil and gas property costs of
approximately $105.7 million consisting of undeveloped leasehold costs of $80.2
million, including $59.8 million in Canada, and unevaluated exploratory drilling
costs of $25.5 million. Approximately $21.4 million of the total unevaluated
costs are associated with the Company's Yemen drilling program. Future
exploration expense and earnings may be impacted to the extent any of the
exploratory drilling is determined to be unsuccessful.
-30-
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 completed five public equity offerings as well as two public
debt offerings and three Rule 144A debt offerings, which provided the Company
with aggregate net proceeds of approximately $1.2 billion.
On May 2, 2002, the Company issued, through a Rule 144A offering, $350
million of its 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 9% Senior Subordinated Notes due 2005. 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.
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 (currently $300 million) 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.
-31-
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 is secured by
a first priority lien on the Company's U.S. oil and gas properties constituting
at least 80 percent of the present value of the Company's U.S. proved reserves
owned now or in the future. The Bank Facility will be guaranteed by any of the
Company's existing and future U.S. subsidiaries that grant a lien on oil and gas
properties under the Bank Facility.
At July 31, 2002, the outstanding borrowings under the Bank Facility were
$101.5 million and unused availability under the Bank Facility was approximately
$180.4 million (net of letters of credit of $18.1 million). The unused portion
of the Bank Facility and the Company's internally generated cash flow provide
liquidity which may be used to finance future capital expenditures, including
acquisitions. As additional acquisitions are made and such properties are added
to the borrowing base, the banks' determination of the borrowing base and their
commitments may be increased. The next borrowing base redetermination will be in
November 2002.
The Company's internally generated cash flow, results of operations and
financing for its operations are dependent on oil and gas prices. Realized oil
prices for the six months ended June 30, 2002, decreased by 24 percent as
compared to the same period in 2001. Realized gas prices for the first six
months of 2002 decreased by 57 percent as compared to the same period in 2001.
The Company believes that its cash flows and unused availability under the Bank
Facility are sufficient to fund its planned capital expenditures for the
foreseeable future. To the extent oil and gas prices continue to decline, the
Company's earnings and cash flow from operations may be adversely impacted.
Continued low oil and gas prices could cause the Company to not be in compliance
with maintenance covenants under its Bank Facility and could negatively affect
its credit statistics and coverage ratios and thereby affect its liquidity.
Consistent with its stated goal of maintaining financial flexibility and
optimizing its portfolio of assets, the Company announced plans to reduce debt
by $200 million in 2002 through a combination of asset sales and cash flow in
excess of planned capital expenditures. The Company determined that the level of
investment and time horizon required to continue the development of its
interests in Ecuador and Trinidad are inconsistent with the timing of its desire
to reduce leverage. These assets, along with the Company's remaining heavy oil
properties in the Santa Maria area of southern California, were identified for
sale. The Company's heavy oil properties in the Santa Maria area of southern
California were sold in June 2002 for $9.5 million in cash and a note receivable
for $6 million bearing monthly payments of $360,000, plus interest, with final
maturity in June 2003. The Company's interest in Trinidad was sold in July 2002
for $40 million in cash. The Company's interests in Ecuador are currently being
marketed for sale. The Company is currently reviewing its portfolio and is
considering additional asset sales or possible capital market transactions, if
necessary, to achieve its $200 million debt reduction target for 2002.
-32-
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
$11.8 million and $50.2 million for the first six 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.
A reconciliation of the U.S. federal statutory income tax rate to the
effective rate is as follows:
Six Months Ended Six Months Ended
June 30, 2002 June 30, 2001
---------------- ----------------
U.S. federal statutory income tax rate ................. 35.0% 35.0%
U.S. state income tax (net of federal tax benefit) ..... 3.9 3.9
Foreign operations ..................................... (53.5) (2.5)
Other .................................................. (3.3) -
---------------- ----------------
(17.9)% 36.4%
================ ================
-33-
Critical Accounting Policies and Estimates
Management's discussion and analysis of its financial condition and results
of operations are based upon the Company's consolidated financial statements,
which have been prepared in accordance with accounting principles generally
accepted in the United States ("GAAP"). The preparation of these consolidated
financial statements requires management to make estimates and assumptions that
affect the reported amounts of assets and liabilities and disclosure of
contingent assets and liabilities, if any, at the date of the financial
statements, and the reported amounts of revenues and expenses during the
reporting period. The Company bases its estimates on historical experience and
various other assumptions that are believed to be reasonable under the
circumstances. Actual results could differ from these estimates under different
assumptions or conditions. Note 1 to the Company's 2001 audited consolidated
financial statements included in its 2001 Annual Report on Form 10-K and Note 2
to the Company's consolidated financial statements included elsewhere in this
Form 10-Q, contain a comprehensive summary of the Company's significant
accounting policies. The following is a discussion of the Company's most
critical accounting policies, judgments and uncertainties that are inherent in
the Company's application of GAAP:
Proved reserve estimates. Estimates of the Company's proved reserves
included in its consolidated financial statements are prepared in accordance
with guidelines established by GAAP and 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.
-34-
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 on a
property-by-property basis, considering factors such as future drilling and
exploitation plans and lease terms. Costs related to impaired prospects are
charged to expense. An impairment expense could result if oil and gas prices
decline in the future or if downward reserve revisions are recorded, as it may
not be economic to develop some of these unproved properties.
Impairment of goodwill. The Company's goodwill is entirely related to its
Canadian operations. The Company must assess its goodwill for impairment at
least annually. The Company must perform an initial assessment of whether there
is an indication that the carrying value of goodwill is impaired. This
assessment is made by comparing the fair value of the Canadian reporting unit,
as determined in accordance SFAS No. 142, to its book value. If the fair value
is less than the book value, an impairment is indicated and the Company must
perform a second test to measure the amount of the impairment. In the second
test, the Company must then calculate the implied fair value of the goodwill by
deducting the fair value of all tangible and intangible net assets of the
Canadian reporting unit from the fair value of the Canadian reporting unit
determined in step one of the assessment. If the carrying value of the goodwill
exceeds this calculated implied fair value of the goodwill an impairment charge
is recorded.
Revenue recognition. 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.
-35-
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. For
further information, see "Item 3. Quantitative and Qualitative Disclosures About
Market Risk-Foreign Currency and Operations Risk" included elsewhere in this
Form 10-Q.
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. During the
first half of 2001, $13.2 million of the original amount recorded to accumulated
other comprehensive income was taken to the statement of operations as the
physical transactions being hedged were finalized. All of the Company's cash
flow hedges in place at January 1, 2001, settled in 2001, with the actual cash
flow impact recorded in oil and gas sales in the Company's statement of
operations.
-36-
On July 20, 2001, the FASB issued Statement of Financial Accounting
Standards No. 141, Business Combinations ("SFAS No. 141"), and Statement of
Financial Accounting Standards No. 142, Goodwill and Other Intangible Assets
("SFAS No. 142"). SFAS No. 141 requires all business combinations initiated
after June 30, 2001, to be accounted for using the purchase method of
accounting. Under SFAS No. 142, goodwill is no longer subject to amortization.
Rather, goodwill will be subject to at least an annual assessment for impairment
by applying a fair-value based test. Additionally, an acquired intangible asset
should be separately recognized if the benefit of the intangible asset is
obtained through contractual or other legal rights, or if the intangible asset
can be sold, transferred, licensed, rented or exchanged, regardless of the
acquirer's intent to do so.
The Company adopted SFAS No. 141 and SFAS No. 142 effective January 1,
2002, resulting in the elimination of goodwill amortization from statements of
operations in future periods. As discussed in Note 3 to the Company's
consolidated financial statements included elsewhere in this Form 10-Q, the
Company recorded an impairment charge of $60.5 million related to the goodwill
of its Canadian operations as a cumulative effect of a change in accounting
principle in its statement of operations.
On January 1, 2002, the Company adopted the provisions of Statement of
Financial Accounting Standards No. 144, Accounting for the Impairment or
Disposal of Long-Lived Assets ("SFAS No. 144"). SFAS No. 144 creates accounting
and reporting standards to establish a single accounting model, based on the
framework established in Statement of Financial Accounting Standards No. 121,
Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to
Be Disposed Of, for long-lived assets to be disposed of by sale. The adoption of
SFAS No. 144 did not have a material impact on the Company's financial position
or results of operations.
On April 30, 2002, the FASB issued Statement of Financial Accounting
Standards No. 145, Rescission of FASB Statements No. 4, 44, and 64, Amendment of
FASB Statement No. 13, and Technical Corrections ("SFAS No. 145"). SFAS No. 145
updates, clarifies and simplifies existing accounting pronouncements. Among
other items, it rescinds previous accounting rules which required all gains and
losses from extinguishment of debt to be aggregated and, if material, classified
as an extraordinary item, net of related income tax effect. The Company has
adopted the provisions of SFAS No. 145 and, accordingly, has classified an $8.2
million ($4.3 million net of tax) loss on the early extinguishment of debt (see
Note 4) as a charge to income from continuing operations in its statements of
operations for the three months and six months ended June 30, 2002. The adoption
of SFAS No. 145 did not have any other material impact on the Company's
financial position or results of operations.
New Accounting Pronouncements
In August 2001, the FASB issued Statement of Financial Accounting Standards
No. 143, Accounting for Asset Retirement Obligations. Currently, the Company
accrues future abandonment costs of wells and related facilities through its
depreciation calculation and includes the cumulative accrual in accumulated
depreciation. The new standard will require that the Company record the
discounted fair value of the retirement obligation as a liability at the time a
well is drilled or acquired. The liability will accrete over time with a charge
to interest expense. The new standard will apply to financial statements of the
Company beginning January 1, 2003. While the new standard will require that the
Company change its accounting for such abandonment obligations, the Company has
not completed its evaluation of the impact of the new standard on its financial
statements.
-37-
On July 30, 2002, the FASB issued Statement of Financial Accounting
Standards No. 146, Accounting for Costs Associated with Exit or Disposal
Activities. The standard requires companies to recognize costs associated with
exit or disposal activities when they are incurred rather than at the date of a
commitment to an exit or disposal plan. The provisions of this statement are to
be applied prospectively to exit or disposal activities initiated after December
31, 2002. The Company does not expect the adoption of this standard to have a
material impact on the Company's financial position or results of operations.
Foreign Operations
For information on the Company's foreign operations, see "Item 3.
Quantitative and Qualitative Disclosures About Market Risk - Foreign Currency
and Operations Risk" included elsewhere in this Form 10-Q.
Forward-Looking Statements
This Form 10-Q includes certain statements that may be deemed to be
"forward-looking statements" within the meaning of the Private Securities
Litigation Reform Act of 1995. All statements in this Form 10-Q, other than
statements of historical facts, that address activities, events or developments
that the Company expects, believes or anticipates will or may occur in the
future, including production, operating costs and product price 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, planned asset sales or dispositions
and other such matters are forward-looking statements. Although the Company
believes the expectations expressed in such forward-looking statements are based
on reasonable assumptions within the bounds of its knowledge of its business,
such statements are not guarantees of future performance and actual results or
developments may differ materially from those in the forward-looking statements.
Factors that could cause actual results to differ materially from those in
forward-looking statements include: oil and gas prices; exploitation and
exploration successes; actions taken and to be taken by Argentina as a result of
its economic instability; continued availability of capital and financing;
general economic, market or business conditions; acquisition and other business
opportunities (or lack thereof) that may be presented to the Company; changes in
laws or regulations; risk factors listed from time to time in the Company's
reports and other documents filed with the Securities and Exchange Commission;
and other factors. The Company assumes no obligation to publicly update any
forward-looking statements, whether as a result of new information, future
events or otherwise.
-38-
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company's operations are exposed to market risks primarily as a result
of changes in commodity prices, interest rates and foreign currency exchange
rates. The Company does not use derivative financial instruments for speculative
or trading purposes.
Commodity Price Risk
The Company produces, purchases and sells crude oil, natural gas,
condensate, natural gas liquids and sulfur. As a result, the Company's financial
results can be significantly impacted as these commodity prices fluctuate widely
in response to changing market forces. See Management's Discussion and Analysis
of Financial Condition and Results of Operations for a discussion of the impact
of commodity price changes based on production levels for the first half of
2002. The Company has previously engaged in oil and gas hedging activities and
intends to continue to consider various hedging arrangements to realize
commodity prices which it considers favorable.
The Company has entered into various oil price swap agreements covering
approximately 2.64 million Bbls of its U.S. and Canadian oil production at a
weighted average NYMEX reference price of $26.28 per Bbl for the last half of
2002. The Company has also entered into oil price swap agreements covering
approximately 2.74 million Bbls of its U.S. oil production at a weighted average
NYMEX reference price of $24.58 per Bbl for calendar year 2003.
Additionally, the Company has entered into various gas price swap
agreements covering approximately 7.7 million MMBtu of its U.S. and Canadian gas
production expiring at various times through October 31, 2002. The Canadian
portion of the gas price swap agreements (approximately 4.3 million MMBtu) is at
an average AECO gas price index reference price of 3.71 Canadian dollars per
MMBtu and will be settled in Canadian dollars. The U.S. portion of the gas swap
agreements (approximately 3.4 million MMBtu) is at an average NYMEX reference
price of $2.79 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 July 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 counterparty to the Company's hedging agreements is a commercial bank.
The Company continues to monitor oil and gas prices and may enter into
additional oil and gas hedges or swaps in the future.
-39-
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 June 30, 2002, the amount of the
Company's fixed-rate debt was 84 percent of its total. In the past, the Company
has not entered into financial instruments such as interest rate swaps or
interest rate lock agreements. However, it may consider these instruments to
manage the portfolio mix between fixed and floating rate debt and to mitigate
the impact of changes in interest rates based on management's assessment of
future interest rates, volatility of the yield curve and the Company's ability
to access the capital markets in a timely manner.
Based on the outstanding borrowings under variable rate debt instruments at
June 30, 2002, a change in the average interest rate of 100 basis points would
result in a change in net income and cash flow before income taxes on an annual
basis of approximately $1.0 million and $1.7 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:
Fair
Value
There- at
Long-Term Debt: 2002 2003 2004 2005 2006 after Total 6/30/02
------- ------ ------ --------- ------ -------- -------- ---------
Fixed rate (in thousands) ........... - - - $ 49,952 - $799,475 $849,427 $803,652
Average interest rate ............... - - - 9.0% - 8.5% 8.5% -
Variable rate (in thousands) ........ - - - $167,000 - - $167,000 $167,000
Average interest rate ............... - - - (a) - - (a) (a)
(a) LIBOR plus an increment, based on level of outstanding senior debt to
the borrowing base, up to a maximum of 2.25 percent. The increment
above LIBOR at June 30, 2002, was 1.75 percent.
Foreign Currency and Operations Risk
International investments represent, and are expected to continue to
represent, a significant portion of the Company's total assets. The Company has
international operations in Canada, Argentina, Bolivia, Ecuador and Yemen. For
the six months ended June 30, 2002, the Company's operations in Argentina and
Canada accounted for approximately 31 percent and 16 percent, respectively, of
the Company's revenues and, at June 30, 2002, the Company's operations in
Argentina and Canada accounted for approximately 25 percent and 38 percent,
respectively, of the Company's total assets, including goodwill. During the
first six months of 2002 and at June 30, 2002, the Company's operations in
Argentina and Canada represented its only foreign operations accounting for more
than 10 percent of its revenues or total assets, including goodwill. The Company
continues to identify and evaluate international opportunities, but currently
has no binding agreements or commitments to make any material international
investment. As a result of such significant foreign operations, the Company's
financial results could be affected by factors such as changes in foreign
currency exchange rates, weak economic conditions or changes in the political
climate in these foreign countries.
-40-
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 and Yemen 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 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 both June 30, 2002 and June 30, 2001,
was US$1:C$1.52.
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.
-41-
However, the "convertibility" plan left Argentina with few monetary policy
tools to respond to outside events. A series of external shocks began in 1998:
prices for Argentina's commodities stopped rising; the dollar appreciated
against other currencies; and Brazil, Argentina's main trading partner, devalued
its currency. Argentina began a period of economic deflation, but failed to
respond by reforming government spending. During 2001, Argentina's budget
deficit exceeded $9 billion and its sovereign debt reached $140 billion.
As a result of economic instability and substantial withdrawals from the
banking system, in early December 2001, the Argentine government, with Fernando
de la Rua as president and Domingo Cavallo as minister of economy, instituted
restrictions that prohibit foreign money transfers without Central Bank approval
and limit cash withdrawals from bank accounts to personal transactions in small
amounts with certain limited exceptions. While the legal exchange rate remained
at one peso to one U.S. dollar, financial institutions were allowed to conduct
only limited activity due to these controls, and currency exchange activity was
effectively halted except for personal transactions in small amounts.
On 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 June 30, 2002, was 3.82 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. Pursuant to an emergency law
passed on January 10, 2002, U.S. dollar obligations between private parties due
after January 6, 2002, were to be liquidated in pesos at a negotiated rate of
exchange which reflects a sharing of the impact of the devaluation. The
Company's settlements in pesos of the existing U.S. dollar-denominated
agreements were substantially completed by March 31, 2002, thus, future periods
should not be impacted by this mandate. This government-mandated "equitable
sharing" of the impact of the devaluation resulted in a reduction in oil
revenues from domestic sales for the first six months of 2002 of approximately
$8 million, or $1.37 per Argentina Bbl produced or $0.73 per total Company Bbl
produced. The Company's Argentine lease operating costs were also reduced as a
result of this mandate and the positive impact of devaluation on the Company's
peso-denominated costs, which essentially offset the negative impact on
Argentine oil revenues.
On February 13, 2002, the Argentine government announced a 20 percent tax
on oil exports, effective March 1, 2002. The tax is limited by law to a term of
no more than five years. The 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.
-42-
On May 24, 2002, Decree 867 declared the domestic supply of hydrocarbons to
be in a state of emergency. This was largely due to the high seasonal demand for
diesel in the agricultural sector coupled with lower activity in refineries. On
May 30, 2002, the Secretary of Energy with Resolution #140 established limits on
oil exports to 36 percent of monthly production beginning June 2002 for a period
of four months. Subsequently on June 21, 2002, the Secretary of Energy with
Resolution #166 relaxed the limits, declaring the 36 percent export limit
applicable to the entire four month period rather than the individual months. On
July 26, 2002, the Secretary of Energy with Resolution #341 completely
eliminated the four month export limit.
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.
On June 30, 2002, Bolivia held national elections for President, Vice
President, and the Congress. This marked the sixth consecutive election since
1982, representing the longest period of constitutional democratic government in
the country's history. Since no candidate for President won the required
majority vote, the election was decided by Congress on August 4, 2002.
Coalitions formed among the two leading parties allowing Gonzalo Sanchez de
Lozada to win the vote. Gonzalo Sanchez de Lozada took office on August 6, 2002.
He was President from 1993 until 1997 when significant privatization activity
along with encouragement of private investment occurred in the country.
In 1987, the Boliviano ("Bs") replaced the peso at the rate of one million
pesos to one Boliviano. The exchange rate is set daily by the government's
exchange house, the Bolsin, which is under the supervision of the Bolivian
Central Bank. Foreign exchange transactions are not subject to any controls. The
US$:Bs exchange rate at June 30, 2002, was US$1:Bs 7.42. 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 Naboa 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 Naboa 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.
-43-
Recently, the Ecuadorian Minister of Finance resigned amidst a corruption
scandal, which has interrupted the government's negotiations with the IMF for a
new stand-by loan. President Gustavo Naboa and his new Minister of Finance
continue to aim for fiscal and debt goals necessary to satisfy IMF requirements
and obtain the loan this year. However, no significant policymaking or
structural reforms are expected for the remainder of the year as Ecuador
prepares for elections during the fourth quarter of 2002.
Fixed investments in Ecuador by certain oil and gas companies remain high
as construction of the new heavy oil pipeline (the "OCP") continues to progress
on schedule.
-44-
PART II
OTHER INFORMATION
-45-
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
The Annual Meeting of Stockholders of the Company (the "Annual
Meeting") was held on May 14, 2002, in Tulsa, Oklahoma. At the
Annual Meeting, the stockholders of the Company elected S. Craig
George, Charles C. Stephenson, Jr. and Joseph D. Mahaffey as Class
III Directors.
There were present at the Annual Meeting, in person or by proxy,
stockholders holding 56,293,475 shares of the Common Stock of the
Company, or 89 percent of the total stock outstanding and entitled
to vote at the Annual Meeting. The table below describes the
results of voting at the Annual Meeting.
Votes Broker
Votes Against or Non-
For Withheld Abstentions Votes
---------- ----------- ----------- ------
Election of Directors:
S. Craig George 42,980,168 13,313,307 -0- -0-
Charles C. Stephenson, Jr. 42,723,972 13,569,503 -0- -0-
Joseph E. Mahaffey 50,297,706 5,995,769 -0- -0-
Item 5. Other Information
A copy of the Company's press release dated August 7, 2002,
announcing second quarter 2002 earnings results and revisions to
2002 capital budget and growth targets is attached as an exhibit
hereto and incorporated herein by reference.
Item 6. Exhibits and Reports on Form 8-K
a) Exhibits
The following documents are included as exhibits to this
Form 10-Q. Those exhibits below incorporated by reference
herein are indicated as such by the information supplied in
the parenthetical thereafter. If no parenthetical appears
after an exhibit, such exhibit is filed herewith.
-46-
4.1 Indenture dated as of May 2, 2002, between JP Morgan
Chase Bank, as Trustee, and the Company (filed as
Exhibit 4.1 to the Company's Registration Statement
on Form S-4, Registration No. 333-89182).
10.1 Credit Agreement dated as of May 2, 2002, among the
Company, as Borrower, and certain commercial lending
institutions, as lenders, Bank of Montreal, as
agent, and the Syndication Agent and
Co-Documentation Agents party thereto.
10.2 First Amendment to Credit Agreement dated as of May
24, 2002, among the Company, as Borrower, the
Lenders party thereto, Bank of Montreal, as
administrative agent, Deutsche Bank Trust Company
Americas, as syndication agent, and Fleet National
Bank, Societe Generale and The Bank of New York, as
co-documentation agents.
10.3 Form of Restricted Stock Award Agreement under the
Vintage Petroleum, Inc. 1990 Stock Plan.
99.1 Press release dated August 7, 2002, issued by the
Company announcing second quarter 2002 earnings
results and revisions to 2002 capital budget and
growth targets.
99.2 Certificate pursuant to 18 U.S.C. Section 1350, as
adopted pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.
99.3 Certificate pursuant to 18 U.S.C. Section 1350, as
adopted pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.
b) Reports on Form 8-K
Form 8-K dated April 3, 2002, was filed on April 4, 2002, to
report under Item 5 the execution of the first amendment to
the Company's preferred share purchase rights agreement.
Form 8-K dated April 17, 2002, was filed on April 17, 2002,
to report under Item 5 the pro forma combined statement of
operations of the Company for the year ended December 31,
2001.
Form 8-K dated April 17, 2002, was filed on April 18, 2002,
to report under Item 5 the Company's press release dated
April 17, 2002, announcing the offering of $250 million of
senior notes to be sold through a Rule 144A ofering.
Form 8-K dated April 26, 2002, was filed on April 26, 2002,
to report under Item 5 the Company's press release dated
April 26, 2002, announcing the sale of $350 million of
senior notes.
-47-
Form 8-K dated June 17, 2002, was filed on June 17, 2002, to
report under Item 5 the Company's press release dated June
17, 2002, announcing the signing of a definitive agreement
to sell all of the Company's holdings in Trinidad and Tobago
to Vermilion Resources Ltd. and the planned opening of a
data rooms in the U.S. and U.K., initiating the sale process
for the Company's oil and gas assets in Ecuador.
-48-
Signatures
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
VINTAGE PETROLEUM, INC.
-----------------------
(Registrant)
DATE: August 9, 2002 \s\ Michael F. Meimerstorf
------------------------------------
Michael F. Meimerstorf
Vice President and Controller
(Principal Accounting Officer)
-49-
Exhibit Index
The following documents are included as exhibits to this Form 10-Q. Those
exhibits below incorporated by reference herein are indicated as such by the
information supplied in the parenthetical thereafter. If no parenthetical
appears after an exhibit, such exhibit is filed herewith.
Exhibit
Number Description
4.1 Indenture dated as of May 2, 2002, between JP Morgan Chase Bank,
as Trustee, and the Company (filed as Exhibit 4.1 to the Company's
Registration Statement on Form S-4, Registration No. 333-89182).
10.1 Credit Agreement dated as of May 2, 2002, among the Company, as
Borrower, and certain commercial lending institutions, as lenders,
Bank of Montreal, as agent, and the Syndication Agent and
Co-Documentation Agents party thereto.
10.2 First Amendment to Credit Agreement dated as of May 24, 2002,
among the Company, as Borrower, the Lenders party thereto, Bank of
Montreal, as administrative agent, Deutsche Bank Trust Company
Americas, as syndication agent, and Fleet National Bank, Societe
Generale and The Bank of New York, as co-documentation agents.
10.3 Form of Restricted Stock Award Agreement under the Vintage
Petroleum, Inc. 1990 Stock Plan.
99.1 Press release dated August 7, 2002, issued by the Company
announcing second quarter 2002 earnings results and revisions to
2002 capital budget and growth targets.
99.2 Certificate pursuant to 18 U.S.C. Section 1350, as adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.3 Certificate pursuant to 18 U.S.C. Section 1350, as adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
-50-